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power demand or complying with the
standards. These emergency provisions
are discussed in a subsequent section of
this preamble.
Concern was expressed by the
commenters that the cost impact of the
standard would be excessive and that
the benefits do not justify the cost,
especially since Alaskan coal is among
the lowest sulfur-content coal in the
country. The Administrator agrees that
for comparable sulfur-content coals,
scrubber operating costs are slightly
higher in Alaska because of the
transportation costs of required
materials such as lime. However, the
operating costs are lower than the
typical costs of FGD units controlling
emissions from higher sulfur coals in the
contiguous 48 States.
The Administrator considered
applying a less stringent SO2 standard to
Alaskan coal-fired units, but concluded
that there is insufficient distinction
between conditions in Alaska and
conditions in the northern part of the
contiguous 48 States to justify such
action. The Administrator has
concluded that Alaskan coal-fired units
should be controlled in the same manner
as other facilities firing low-sulfur coal.
Noncontinental Areas
Facilities in noncontinental areas
(State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, and the
Northern Mariana Islands) are exempt
from the SO2 percentage reduction
requirements. Such facilities are
required, however, to meet the SO2
emission limitations of 520 ng/J (1.2 lb/
million Btu) heat input (30-day rolling
average) for coal and 340 ng/J (0.8 lb/
million Btu) heat input (30-day rolling
average) for oil, in addition to all
requirements under the NO, and
particulate matter standards. This is the
same as the proposed standards.
Although this provision was identified
as an issue in the preamble to the
proposed standards, very few comments
were received on it. In general, the
comments supported the proposal. The
main question raised is whether Puerto
Rico has adequate land available for
sludge disposal.
After evaluating the comments and
available information, the Administrator
has concluded that noncontinental
areas, including Puerto Rico, are unique
and should be exempt from the SO2
percentage reduction requirements.
The impact of new power plants in
noncontinental areas on ambient air
quality will be minimized because each
will have to undergo a review to assure
compliance with the prevention of
significant deterioration provisions
under the Clean Air Act. The
Administrator does not intend to rule
out the possibility that an individual
BACT or LAER determination for a
power plant in a noncontinental area
may require scrubbing.
Emerging Technology
The final regulations for emerging
technologies are summarized earlier in
this preamble under SUMMARY OF
STANDARDS and are very similar to
the proposed regulations.
In general, the comments received on
the proposed regulations were
supportive, although a few commenters
suggested some changes. A few
commenters indicated that section lll(j)
of the Act provides EPA with authority
to handle innovative technologies. Some
commenters pointed out that the
proposed standards did not address
certain technologies such as dry
scrubbers for SO2 control. One
commenter suggested that SRC I should
be included under the solvent refined
coal rather than coal liquefaction
category for purposes of allocating the
15,000 MW equivalent electrical
capacity.
On the basis of the comments and
public record, the Administrator
believes the need still exists to provide
a regulatory mechanism to allow a less
stringent standard to the initial full-scale
demonstration facilities of certain
emerging technologies. At the time the
standards were proposed, the
Administrator recognized that the
innovative technology waiver provisions
under section lll(j) of the Act are not
adequate to encourage certain capital-
intensive, front-end control
technologies. Under the innovative
technology provisions, the
Administrator may grant waivers for a
period of up to 7 years from the date of
issuance of a waiver or up to 4 years
from the start of operation of a facility,
whichever is less. Although this amount
of time may be sufficient to amortize the
cost of tail-gas control devices that do
not achieve their design control level, it
does not appear to be sufficient for
amortization of high-capital-cost, front-
end control technologies. The proposed
provisions were designed to mitigate the
potential impact on emerging front-end
technologies and insure that the
standards dojiot preclude the
development of such technologies.
Changes have been made to the
proposed regulations for emerging
technologies relative to averaging time
in order to make them consistent with
the final NO, and SO, standards;
however, a 24-hour averaging period has
been retained for SRC-I because it has
relatively uniform emission rates, which
makes a 24-hour averaging period more
appropriate than a 30-day rolling
average.
Commercial demonstration permits
establish less stringent requirements for
the SOa or NO, standards, but do not
exempt facilities with these permits
from any other requirements of these
standards.
Under the final regulations, the
Administrator (in consultation with the
Department of Energy) will issue
commercial demonstration permits for
the initial full-scale demonstration
facilities of each specified technology.
These technologies have been shown to
have the potential to achieve the
standards established for commercial
facilities. If, in implementing these
provisions, the Administrator finds that
a given emerging technology cannot
achieve the standards for commercial
facilities, but it offers superior overall
environmental performance (taking into
consideration all areas of environmental
impact, including air, water, solid waste,
toxics, and land use) alternative
standards can be established.
It should be noted that these permits
will only apply to the application of this
standard and will not supersede the new
source review procedures and
prevention of significant deterioration
requirements under other provisions of
the Act.
Modification/Reconstruction
The impact of the modification/
reconstruction provisions is the same for
the final standard as it was for the
proposed standard; existing facilities are
only covered by the final standards if
the facilities are modified or
reconstructed as defined under 40 CFR
60.14, 60.15, or 60.40a. Many types of fuel
switches are expressly exempt from
modification/reconstruction provisions
under section 111 of the Act.
Few, if any, existing steam generators
that change fuels, replace burners, etc.,
are expected to qualify under the
modification/reconstruction provisions;
thus, few, if any, existing electric utility
steam generating units will become
subject to these standards.
The preamble to the proposed
regulations did not provide a detailed
discussion of the modification/
reconstruction provisions, and the
comments received indicated that these
provisions were not well understood by
the commenters. The general
modification/reconstruction pro visions
under 40 CFR 60.14 and 60.15 apply to all
source categories covered under Part 60.
Any source-specific modification/
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reconstruction provisions are defined in
more detail under the applicable subpart
(60.40a for this standard).
A number of commenters expressly
requested that fuel switching provisions
be more clearly addressed by the
standard. In response, the Administrator
has clarified the fuel switching
provisions by including them in the final
standards. Under these provisions
existing facilities that are converted to
nonfossil fuels are not considered to
have undergone modification. Similarly,
existing facilities designed to fire gas or
oil and that are converted to shale oil,
coal/oil mixtures, coal/oil/water
mixtures, solvent refined coal, liquified
coal, gasified coal, or any other coal-
derived fuel are not considered to have
undergone modification. This was the
Administrator's intention under the
proposal and was mentioned in the
Federal Register preamble for the
proposal.
SO, Standards
SO, Control Technology—The final
SO, standards are based on the
performance of a properly designed.
installed, operated and maintained FGD
system. Although the standards are
based on lime and limestone FGD
systems, other commercially available
FGD systems {e.g., Wellman-Lord,
double alkali and magnesium oxide) are
also capable of achieving the final
standard. In addition, when specifying
the form of the final standards, the
Administrator considered the potential
of dry SO, control systems as discussed
later in this section.
Since the standards were proposed,
EPA has continued to collect SO, data
with continuous monitors at two sites
and initiated data gathering at two
additional sites. At the Conesville No. 5
plant of Columbus and Southern Ohio
Electric company, EPA gathered
continuous SO, data from July to
December 1978. The Conesville No. 5
FGD unit is a turbulent contact absorber
(TCA) scrubber using thiosorbic lime as
the scrubbing medium. Two parallel
modules handle the gas flow from a 411-
MW boiler firing mn-of-mine 4.5 percent
sulfur Ohio coal. During the test period,
data for only thirty-four 24-hour
averaging periods were gathered
because of frequent boiler and scrubber
outages. The Conesville system
averaged 88.8 percent SO, removal, and
outlet SO, emissions averaged 0.80 lb/
million Btu. Monitoring of the Wellman-
Lord FGD unit at Northern Indiana
Public Service Company's Mitchell
station during 1978 included one 41-day
continuous period of operation. Data
from this period were combined with
previous data and analyzed. Results
indicated 0.61 Ib SO,/million Btu and
89.2 percent SO, removal for fifty-six 24-
hour periods.
From December 1978 to February 1979,
EPA gathered SO, data with continuous
monitors at the 10-MW prototype unit
(using a TCA absorber with lime) at
Tennessee Valley Authority's (TVA)
Shawnee station and the Lawrence No.
4 FGD unit (using limestone) of Kansas
Power and Light Company. During the
Shawnee test, data were obtained for
forty-two 24-hour periods in which 3.0
percent sulfur coal was fired. Sulfur
dioxide removal averaged 88.6 percent.
Lawrence No. 4 consists of a 125-MW
boiler controlled by a spray tower
limestone FGD unit. In January and
February 1979, during twenty-two 24-
hour periods of operation with 0.5
percent sulfur coal, the average SO,
removal was 96.6 percent. The Shawnee
and Lawrence tests also demonstrated
that SO, monitors can function with
reliabilities above 80 percent. A
summary of the recent EPA-acquired
SO, monitored data follows:
8tt*
Scrubber
Coal sulfur,
pet
No of 24-
hour parted,
Average SO,
removal, pel
CooetvHte No. 6...
NIPSCO
Shawnee -
Lawrence No 4 ...
Thosorbk: ime/TCA
,„,....... Wellman-Lord ..._„ -...
Ume/TCA ,
45
3.5
30
05
34
56
42
22
692
862
666
966
Since proposing the standards, EPA
has prepared a report that updates
information in the earlier PEDCo report
on FGD systems. The report includes
Listings of several new closed-loop
systems.
A variety of comments were received
concerning SO, control technology.
Several comments were concerned with
the use of data from FGD systems
operating in Japan. These comments
suggested that the Japanese experience
shows that technology exists to obtain
greater than 90 percent SCfe removal.
The commenters pointed out that
attitudes of the plant operators, the skill
of the FGD system operators, the close
surveillance of power plant emissions by
the Japanese Government, and technical
differences in the mode of scrubber
operation were primary factors in the
higher FGD reliabilities and efficiencies
for Japanese systems. These commenters
stated that the Japanese experience is
directly applicable to U.S. facilities.
Other comments stated that the
Japanese systems cannot be used to
support standards for power plants in
the U.S. because of the possible
differences in factors such as the degree
of closed-loop versus open-loop
operation, the impact of trace
constituents such as chlorides, the
differences in inlet SO: concentrations,
SOj uptake per volume of slurry,
Japanese production of gypsum instead
of sludge, coal blending and the amount
of maintenance.
The comments on closed-loop
operation of Japanese systems inferred
that larger quantities of water are
purged from these systems than from
their U.S. counterparts. A closed-loop
system is one where the only water
leaving the system is by: (1) evaporative
water losses in the scrubber, and (2) the
water associated with the sludge. The
administrator found by investigating the
systems referred to in the comments that
six of ten Japanese systems listed by
one commenter and two of four coal-
fired Japanese systems are operated
within the above definition of closed-
loop. The closed-loop operation of
Japanese scrubbers was also attested to
in an Interagencey Task Force Report,
"Sulfur Oxides Control Technology in
Japan" (June 30,1978) prepared for
Honorable Henry M. Jackson, Chairman,
Senate Committee on Energy and
Natural Resources. It is also important
to note that several of these successful
Japanese systems were designed by U.S.
vendors.
After evaluating all the comments, the
Administrator has concluded that the
experience with systems in Japan is
applicable to U.S. power plants and can
be used as support to show that the final
standards are achievable.
A few commenters stated that closed-
loop operation of an FGD system could
not be accomplished, especially at
utilities burning high-sulfur coal and
located in areas where rainfall into the
sludge disposal pond exceeds
evaporation from the pond. It is
important to note that neither the
proposed nor final standards require
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closed-loop operation of the FGD. The
commenters are primarily concerned
that future water pollution regulations
will require closed-loop operation.
Several of these commenters ignored the
large amount of water that is evaporated
by the hot exhaust gases in the scrubber
and the water that is combined with and
goes to disposal with the sludge in a
typical ponding system. If necessary, the
sludge can be dewatered by use of a
mechanical clarifier, filter, or centrifuge
and then sludge disposed of in a landfill
designed to minimize rainwater
collection. The sludge could also be
physically or chemically stabilized.
Most U.S. systems operate open-loop
(i.e., have some water discharge from
their sludge pond) because they are not
required to do otherwise. In a recent
report "Electric Utility Steam Generating
Units—Flue Gas Desulfurization
Capabilities as of October 1978" (EPA-
450/3-79-001), PEDCo reported that
several utilities burning both low- and
high-sulfur coal have reported that they
are operating closed-loop FGD systems.
As discussed earlier, systems in Japan
are operating closed-loop if pond
disposal is included in'the system. Also,
experiments at the Shawnee test facility
have shown that highly reliable
operation can be achieved with high
sulfur coal (containing moderate to high
levels of chloride) during closed-loop
operation. The Administrator continues
to believe that although not required,
closed-loop operation is technically and
economically feasible if the FGD and
disposal system are properly designed.
If a water purge is necessary to control
chloride buildup, this stream can be
treated prior to disposal using
commercially available water treatment
methods, as discussed in the report
"Controlling SO? Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPA-600/7-78-045b).
Two comments endorsed coal
cleaning as an SO2 emission control
technique. One commenter encouraged
EPA to study the potential of coal
cleaning, and another endorsed coal
cleaning in preference to FGD. The
Administrator investigated coal cleaning
and the relative economics of FGD and
coal cleaning and the results are
presented in the report "Physical Coal
Cleaning for Utility Boiler SO2 Emission
Control" (EPA-600/7-78-034). The
Administrator does not consider coal
cleaning alone as representing the best
demonstrated system for SO2 emission
reduction. Coal cleaning does offer the
following benefits when used in
conjuction with an FGD system: (1) the
SO2 concentrations entering the FGD
system are lower and less variable than
would occur without coal cleaning, (2)
percent removal credit is allowed
toward complying with the SO2 standard
percent removal requirement, and (3) the
SO2 emission limit can be achieved
when using a coal having a sulfur
content above that which would be
needed when coal cleaning is not
practiced. The amount of sulfur that can
be removed from coal by physical coal
cleaning was investigated by the U.S.
Department of the Interior ("Sulfur
Reduction Potential of the Coals of the
United States," Bureau of Mines Report
of Investigations/1976, RI-8118). Coal
cleaning principally removes pyritic
sulfur from coal by crushing it to a
maximum top size and then separating
the pyrites and other rock impurities
from the coal. In order to prevent coal
cleaning processes from developing into
undesirable sources of energy waste, the
amount of crushing and the separation
bath's specific gravity must be limited to
reasonable levels. The Administrator
has concluded that crushing to 1.5
inches topsize and separation at 1.6
specific gravity represents common
practice. At this level, the sulfur
reduction potential of coal cleaning for
the Eastern Midwest (Illinois, Indiana,
and Western Kentucky) and the
Northern Appalachian Coal
(Pennsylvania, Ohio, and West Virginia)
regions averages approximately 30
percent. The washability of specific coal
seams will be less than or more than the
average.
Some comments state that FGD
systems do not work on specific coals,
such as high-sulfur Illinois-Indiana coal,
high-chloride Illinois coal, and Southern
Appalachian coals. After review of the
comments and data, the Administrator
concluded that FGD application is not
limited by coal properties. Two reports,
"Controlling SO2 Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPS-600/7-78-045b)
and "Flue Gas Desulfurization Systems:
Design and Operating Considerations"
(EPA-600/7-78-O30b) acknowledge that
coals with high sulfur or -chloride
content may present problems.
Chlorides in flue gas replace active
calcium, magnesium, or sodium alkalis
in the FGD system solution and cause
stress corrosion in susceptible materials.
Prescrubbing of flue gas to absorb
chlorides upstream of the FGD or the
use of alloy materials and protective
coatings are solutions to high-chloride
coal applications. Two reports, "Flue
Gas Desulfurization System Capabilities
for Coal-Fired Steam Generators" (EPA-
600/7-78-032b) and "Flue Gas
Desulfurization Systems: Design and
Operating Considerations" (EPA -600/
7-7-78-030b) also acknowledge that 90
percent SOa removal (or any given level)
is more difficult when burning high-
sulfur coal than when burning low-sulfur
coal because the mass of SO2 that must
be removed is greater when high-sulfur
coal is burned. The increased load
results in larger and more complex FGD
systems (requiring higher liquid-to-gas
ratios, larger pumps, etc). Operation of
current FGD installations such as
LaCygne with over 5 percent sulfur coal,
Cane Run No. 4 on high-sulfur
midwestern coal, and Kentucky Utilities
Green River on 4 percent sulfur coal
provides evidence that complex systems
can be operated successfully on high-
sulfur coal. Recent experience at TVA,
Widows Creek No. 8 shows that FGD
systems can operate successfully at high
SO2 removal efficiencies when Southern
Appalachian coals are burned.
Coal blending was the subject of two
comments: (1) that blending could
reduce, but not eliminate, sulfur
variability; and (2) that coal blending
was a relatively inexpensive way to
meet more relaxed standards. The
Administrator believes that coal
blending, by itself, does not reduce the
average sulfur content of coal but
reduces the variability of the sulfur
content. Coal blending is not considered
representative of the best demonstrated
system for SO2 emission reduction. Coal
blending, like coal cleaning, can be
beneficial to the operation of an FGD
system by reducing the variability of
sulfur loading in the inlet flue gas. Coal
blending may also be useful in reducing
short-term peak SO2 concentrations
where ambient SO2 levels are a
problem.
Several comments were concerned
with the dependability of FGD systems
and problems encountered in operating
them. The commenters suggested that
FGD equipment is a high-risk
investment, and there has been limited
"successful" operating experience. They
expressed the belief that utilities will
experience increased maintenance
requirements and that the possibility of
forced outages due to scaling and
corrosion would be greater as a result of
the standards.
One commenter took issue with a
statement that exhaust stack liner
problems can be solved by using more
expensive materials. The commenter
also argued that EPA has no data
supporting the assumption that
scrubbers have been demonstrated at or
near 90 percent reliability with one
spare module. The Administrator has
considered these comments and has
concluded that properly designed and
operated FGD systems can perform
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reliably. An FCD system is a chemical
process which must be designed (1) to
include materials that will withstand
corrosive/erosive conditions, (2) with
instruments to monitor process
chemistry and (3] with spare capacity to
allow for planned downtime for routine
maintenance. As with any chemical
process, a startup or shakedown period
is required before steady, reliable
operation can be achieved.
The Administrator has continued to
follow the progress of the FGD systems
cited in the supporting documents
published in conjunction with the
proposed regulations in September 1978.
Availability of the FGD system at
Kansas City Power and Light Company's
LaCygne Unit No. 1 has steadily
improved. No FGD-related forced
outages were reported from September
1977 to September 1978. Availability
from January to September 1978
averaged 93 percent. Outages reported
were a result of boiler and turbine
problems but not FGD system problems.
LaCygne Unit No. 1 burns high-sulfur (5
percent) coal, uses one of the earlier
FGD's installed in the U.S., and reduces
SO» emissions by 80 percent with a
limestone system at greater than 90
percent availability. Northern States
Power Company's Sherburne Units
Numbers 1 and 2 on the other hand
operate on low-sulfur coal (0.8 percent).
Sherburne No. 1, which began operating
early in 1976, had 93 percent availability
in both 1977 and 1978. Sherburne No. 2,
which began operation in late 1976 had
availabilities of 93 percent in 1977 and
94 percent in 1978. Both of these systems
include spare modules to maintain these
high availabilities.
Several comments were received
expressing concern over the increased
water use necessary to operate FGD
systems at utilities located in arid
regions. The Administrator believes that
water availability is a factor that limits
power plant siting but since an FGD
system uses less than 10 percent of the
water consumed at a power plant, FGD
will not be the controlling factor in the
siting of new utility plants.
A few commenters criticized EPA for
not considering amendments to the
Federal Water Pollution Control Act
(now the Clean Water Act), the
Resource Conservation and Recovery
Act, or the Toxic Substances Control
Act when analyzing the water pollution
and solid waste impacts of FGD
systems. To the extent possible, the
Administrator believes that the impacts
of these Acts have been taken into
consideration in this rule-making. The
economic impacts were estimated on the
basis of requirements anticipated for
power plants under these Acts.
Various comments were received
regarding the SO> removal efficiency
achievable with FGD technology. One
comment from a major utility system
stated that they agreed with the
standards, as proposed. Many
comments stated that technology for
better than 90 percent SOt removal
exists. One comment was received
stating that 95 percent SO] removal
should be required. The Administrator
concludes that higher SO, removals are
achievable for low-sulfur coal which
was the basis of this comment. While 95
percent SO, removal may be obtainable
on high-sulfur coals with dual alkali or
regenerable FGD systems, long-term
data to support this level are not
available and the Administrator has
concluded that the demand for dual
alkah'/regenerable systems would far
exceed vendor capabilities. When the
uncertainties of extrapolating
performance from 90 to 95 percent for
high-sulfur coal, or from 95 percent on
low-sulfur coal to high-sulfur coal, were
considered, the Administrator
concluded that 95 percent SO, removal
for lime/limestone based systems on
high-sulfur coal could not be reasonably
expected at this time.
Another comment stated that all FGD
systems except lime and limestone were
not demonstrated or not universally
-applicable. The proposed SO, standards
were based upon the conclusion that
they were achievable with a well
designed, operated, and maintained
FGD system. At the time of proposal, the
Administrator believed that lime and
limestone FGD systems would be the
choice of most utilities in the near future
but, in some instances, utilities would
choose the more reactive dual alkali or
regenerable systems. The use of
additives such as magnesium oxides
was not considered,to be necessary for
attainment of the standard, but could be
used at the option of the utility.
Available data show that greater than
90 percent SO* removal has been
achieved at full scale U.S. facilities for
short-term periods when high-sulfur coal
is being combusted, and for long-term
periods at facilities when low-sulfur
coal is burned. In addition, greater than
90 percent SO, removal has been
demonstrated over long-term operating
periods at FGD facilities when operating
on low- and medium-sulfur coals in
Japan.
Other commenters questioned the
exclusion of dry scrubbing techniques
from consideration. Dry scrubbing was
considered in EPA's background
documents and was not excluded from
consideration. Five commercial dry SO»
control systems are currently on order;
three for utility boilers (400-MW, 455-
MW, and 550-MW) and two for
industrial applications. The utility units
are designed to achieve 50 to 85 percent
reduction on a long-term average basis
and are scheduled to commence
operation in 1981-1982. The design basis
for these units is to comply with
applicable State emission limitations. In
addition, dry SO, control systems for six
other utility boilers are out for bid.
However, no full scale dry scrubbers are
presently in operation at utility plants so
information available to EPA and
presented in the background document
dealt with prototype units. Pilot scale
data and estimated costs of full-scale
dry scrubbing systems offer promise of
moderately high (70-85 percent) SO,
removal at costs of three-fourths or less
of a comparable lime or limestone FGD
system. Dry control system and wet
control system costs are approximately
equal for a 2-percent-sulfur coal. With
lower-sulfur coals, dry controls are
particularly attractive, not only because
they would be less costly than wet
systems, but also because they are
expected to require less maintenance
and operating staff, have greater
turndown capabilities, require less
energy consumption for operation, and
produce a dry solid waste material that
can be more easily disposed of than wet
scrubber sludge.
Tests done at the Hoot Lake Station (a
53-MW boiler) in Minnesota
demonstrated the performance
capability of a spray dryer-baghouse dry
control system. The exhaust gas
concentrations before the control
systems were 800 ppm SO, and an
average of 2 gr/acf particulate matter.
With lime as the sorbent, the control
system removed over 86 percent SO,
and 99.96 percent particulate matter at a
stoichiometric ratio of 2.1 moles of lime
absorbent per inlet mole of SO,. When
the spent lime dust was recirculated
from the bag filter to the lime slurry feed
tank, SOj removal efficiencies up to 90
percent ware obtained at stoichiometric
ratios of 1.3-1.5. With the lime
recirculation process, SO, removal
efficiencies of 70-80 percent were
demonstrated at a more economical
stoichiometric ratio (about 0.75). Similar
tests were performed at the Leland Olds
Station using commercial grade-lime.
Based upon the available information,
the Administrator has concluded that 70
percent SO, removal using lime as the
reactanUs technically feasible and
economically attractive in comparison
to wet scrubbing when coals containing
less than 1.5 percent sulfur are being
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combusted. The coal reserves which
contain 1.5 percent sulfur or less
represent approximately 90 percent of
the total Western U.S. reserves.
The standards specify a percentage
reduction and an emission limit but do
not specify technologies which must be
used. The Administrator specifically
took into consideration the potential of
dry SOj scrubbing techniques when
specifying the final form of the standard
in order to provide an opportunity for
their development on low-sulfur coals.
Averaging Time
Compiance with the final SOj
standards is based on a 30-day rolling
average. Compliance with the proposed
standards was based on a 24-hour
average.
Several comments state that the
proposed SO2 percent reduction
requirement is attainable using currently
available control equipment. One utility
company commented upon their
experience with operating pilot and
prototype scrubbers and a. full-scale
limestone FGD system on a 550-MW
plant. They stated that the FGD state of
the art is sufficiently developed to
support the proposed standards. Based
on their analysis of scrubber operating
variability and coal quality variability,
they indicated that to achieve an 85
percent reduction in SOt emissions 90
percent of the time on a daily basis, the
30-day average scrubber efficiency
would have to be at least 88 to 90
percent.
Other comments stated that EPA
contractors did not consider SOa
removal in context with averaging time,
that vendor guarantees were not based
on specific averaging times, and that
quoted SO» removal efficiencies were
based on testing modules. EPA found
through a survey of vendors that many
would offer 90-95 percent SO2 removal
guarantees based upon their usual
acceptance test criteria. However, the
averaging time was not specified. The
Industrial Gas Cleaning Institute (IGCI),
which represents control equipment
vendors, commented that the control
equipment industry has the present
capability to design, manufacture, and
install FGD control systems that have
the capability of attaining the proposed
SOa standards (a continuous 24-hour
average basis). Concern was expressed,
however, about the proposed 24-hour
averaging requirement, and this
commenter recommended the adoption
of 30-day averaging. Since minute-to-
minute variations in factors affecting
FGD efficiency cannot be compensated
for instantaneously, 24-hour averaging is
an impracticably short period for
implementing effective correction or for
creating offsetting favorable higher
efficiency periods.
Numerous other comments were
received recommending that the
proposed 24-hour averaging period be
changed to 30 days. A utility company
stated that their experience with
operating full scale FGD systems at 500-
and 400-MW stations indicates that
variations in FGD operation make it
extremely difficult, if not impossible, to
maintain SOa removal efficiencies in
compliance with the proposed percent
reduction on a continual daily basis. A
commenter representing the industry
stated that it is clear from EPA's data
that the averaging time could be no
shorter than 24 hours,, but that neither
they nor EPA have data at this time to
permit a reasonable determination of
what the appropriate averaging time
should be.
The Administrator has thoroughly
reviewed the available data on FGD
performance and all of the comments
received. Based on this review, he has
concluded that to alleviate this concern
over coal sulfur variability, particularly
its effect on small plant operations, and
to allow greater flexibility in operating
FGD units, the final SOa standard should
be based on a 30-day rolling average
rather than a 24-hour average as
proposed. A rolling average has been
adopted because it allows the
Administrator to enforce the standard
on a daily basis. A 30-day average is
used because it better describes the
typical performance of an FGD system,
allows adequate time for owners or
operators to respond to operating
problems affecting FGD efficiency,
permits greater flexibility in procedures
necessary to operate FGD systems in
compliance with the standard, and can
reduce the effects of coal sulfur
variability on maintaining compliance
with the final SOa standards without the
application of coal blending systems.
Coal blending systems may be required
in some cases, however, to provide for
the attainment and maintenance of the
National Ambient Air Quality Standards
for SOa.
Emission Limitation
In the September proposal a 520 ng/J
(1.20 Ib/million Btu) heat input emission
limit, except for 3 days per month, was
specified for solid fuels. Compliance
was to be determined on a 24-hour
averaging basis.
Following the September proposal, the
joint working group comprised of EPA,
The Department of Energy, the Council
of Economic Advisors, the Council on
Wage and Price Stability, and others
investigated ceilings lower than the
proposal. In looking at these
alternatives, the intent was to take full
advantage of the cost effectiveness
benefits of a joint coal washing/
scrubbing strategy on high-sulfur coal.
The cost of washing is relatively
inexpensive; therefore, the group
anticipated that a low emission ceiling,
which would require coal washing and
90 percent scrubbing, could
substantially reduce emissions in the
East and Midwest at a relatively low
cost. Since coal washing is now a
widespread practice, it was thought that
Eastern coal production would not be
seriously impacted by the lower
emission limit. Analyses using an
econometric model of the utility sector
confirmed these conclusions and the
results were published in the Federal
Register on December 8,1978 (43 FR
57834).
Recognizing certain inherent
limitations in the model when assessing
impacts at disaggregated levels, the
Administrator undertook a more
detailed analysis of regional coal
production impacts in February using
Bureau of Mines reports which provided
seam-by-seam data on the sulfur content
of coal reserves and the coal washing
potential of those reserves. The analysis
identified the amount of reserves that
would require more than 90 percent
scrubbing of washed coal in order to
meet designated ceilings. To determine
the sulfur reduction from coal washing,
the Administrator assumed two levels of
coal preparation technology, which were
thought to represent state-of-the-art coal
preparation (crushing to 1.5-inch top size
with separation at 1.6 specific gravity,
and %-inch top size with separation at
1.6 specific gravity). The amount of
sulfur reduction was determined
according to chemical characteristics of
coals in the reserve base. This
assessment was made using a model
developed by EPA's Office of Research
and Development.
As a result of concerns expressed by
the National Coal Association, a
meeting was called for April 5,1979, in
order for EPA and the National Coal
Association to present their respective
findings as they pertained to potential
impacts of lower emission limits on
high-sulfur coal reserves in the Eastern
Midwest (Illinois, Indiana, and Western
Kentucky) and the Northern
Appalachian (Ohio, West Virginia, and
Pennsylvania) coal regions. Recognizing
the importance of discussion, the
Administrator invited representatives
from the Sierra Club, the Natural
Resources Defense Council, the
Environmental Defense Fund, the Utility
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Air Regulator/Group, and the United
Mine Workers of America, as well as
other interested parties to attend.
At the April 5 meeting, EPA presented
its analysis of the Eastern Midwest and
Northern Appalachian coal regions. The
analysis showed that at a 240 ng/J (0.55
Ib/million Btu) annual emission limit
more than 90 percent scrubbing would
be required on between 5 and 10 percent
of Northern Appalachian reserves and
on 12 to 25 percent of the Eastern
Midwest reserves. At a 340 ng/J (0.80 lb/
million Btu} limit, less than 5 percent of
the reserves in each of these regions
would require greater than 90 percent
scrubbing. At that same meeting, the
National Coal Association presented
data on the sulfur content and
washability of reserves which are
currently held by member companies.
While the reported National Coal
Association reserves represent a very
small portion of the total reserve base,
they indicate reserves which are
planned to be developed in the near
future and provide a detailed property-
by-property data base with which to
compare EPA analytical results. Despite
the differences in data base sizes, the
National Coal Association's study
served to confirm the results of the EPA
analysis. Since the National Coal
Association results were within 5
percentage points of EPA's estimates,
the Administrator concluded that the
Office of Research and Development
model would provide a widely accepted
basis for studying coal reserve impacts.
In addition, as a result of discussions at
this meeting the Administrator revised
his assessment of state-of-the-art coal
cleaning technology. The National Coal
Association acknowledged that crushing
to 1.5-inch top size with separation at 1.6
specific gravity was common practice in
industry, but that crushing to smaller top
sizes would create unmanageable coal
handling problems and great expense.
In order to explore further the
potential for dislocations in regional
coal markets, the Administrator
concluded that actual buying practices
of utilities rather than the mere technical
usability of coals should be considered.
This additional analysis identified coals
that might not be used because of
conservative utility attitudes toward
scrubbing and the degree of risk that a
utility would be willing to take in buying
coal to meet the emission limit. This
analysis was performed in a similar
manner to the analysis described above
except that two additional assumptions
were made: (1) utilities would purchase
coal that would provide about a 10
percent margin below the emission limit
in order to minimize risk, and (2) utilities
would purchase coal that would meet
the emission limit (with margin) with a
90 percent reduction in potential SOS
emissions. This assumption reflects
utility preference for buying washed
coal for which only 85 percent scrubbing
is needed to meet both the percent
reduction and the emission limit as
compared to the previous assumption
that utilities would do 90 percent
scrubbing on washed coal (resulting in
more than 90 percent reduction in
potential SO» emissions). This analysis
was performed using EPA data at 430
ng/J (1.0 Ib/million Btu) and 520 ng/J
(1.20 Ib/million Btu) monthly emission
limits. The results revealed that a
significant portion (up to 22 percent) of
the high-sulfur coal reserves in the
Eastern Midwest and portions of
Northern Appalachian coal regions
would require more than a 90 percent
reduction if tRe emission limitation was
established below 520 ng/J (1.20 lb/
million Btu) on a 30-day rolling average
basis. Although higher levels of control
are technically feasible, conservatism in
utility perceptions of scrubber
performance could create a significant
disincentive against the use of these
coals and disrupt the coal markets in
these regions. Accordingly, the
Administrator concluded the emission
limitation should be maintained at 520
ng/J (1.20 Ib/million Btu) on a 30-day
rolling average basis. A more stringent
emission limit would be counter to one
of the basic purposes of the 1977
Amendments, that is, encouraging the
use of higher sulfur coals.
Full Versus Partial Control
In September 1978, the Administrator
proposed a full or uniform control
alternative and set forth other partial or
variable control options as well for
public comment. At that time, the
Administrator made it clear that a
decision as to the form of the final
standard would not be made until the
public comments were evaluated and
additional analyses were completed.
The analytical results are'discussed
later under Regulatory Analysis.
This issue focuses on whether power
plants firing lower-sulfur coals should
be required to achieve the same
percentage reduction in potential SO»
emissions as those burning higher-sulfur
coals. When addressing this issue, the
public commenters relied heavily on the
statutory language and legislative
history of Section 111 of the Clean Air
Act Amendments of 1977 to bolster their
arguments. Particular attention was
directed to the 'Conference Report which
says in the pertinent part:
In establishing a national percent reduction
for new fossil fuel-fired sources, the
conferees agreed that the Administrator may,
in his discretion, set a range of pollutant
reduction that reflects varying fuel
characteristics. Any departure from the
uniform national percentage reduction
requirement, however, must be accompanied
by a finding that such a departure does not
undermine the basic purposes of the House
provision and other provisions of the act,
such as maximizing the use of locally
available fuels.
Comments Favoring Full or Uniform
Control. Commenters in favor of full
control relied heavily on the statutory
presumption in favor of a uniform
application of the percentage reduction
requirement. They argued that the
Conference Report language, ". . . the
Administrator may, in his discretion, set
a range of pollutant reduction that
reflects varying fuel
characteristics. . . ." merely reflects the
contention of certain conferees that low-
sulfur coals may be more difficult to
treat than high-sulfur coals. This
contention, they assert, is not borne out
by EPA's technical documentation nor
by utility applications for prevention of
significant deterioration permits which
clearly show that high removal
efficiencies can be attained on low-
sulfur coals. In the face of this, they
maintain there is no basis for applying a
lower percent reduction for such coals.
These commenters further maintain
that a uniform application of the percent
reduction requirement is needed to
protect pristine areas and national
parks, particularly in the West. In doing
so, they note that emissions may be up
to seven times higher at the individual
plant level under a partial approach
than under uniform control. In the face
of this, they maintain that partial control
cannot be considered to reflect best
available control technology. They also
contend that the adoption of a partial
approach may serve to undermine the
more stringent State requirements
currently in place in the West.
Turning to national impacts,
commenters favoring a uniform
approach note that it will result in lower
emissions. They maintain that these
lower emissions are significant in terms
of public health and that such
reductions should be maximized,
particularly in light of the Nation's
commitment to greater coal use. They
also assert that a uniform standard is
clearly affordable. They point out that
the incremental increase in costs
associated with a uniform standard is
small when compared to total utility
expenditures and will have a minimal
impact at the consumer level. They
further maintain that EPA has inflated
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the costs of scrubber technology and has
failed to consider factors that should
result in lower costs in future years.
With respect to the oil impacts
associated with a uniform standard,
these same commenters are critical of
the oil prices used in the EPA analyses
and add that if a higher oil price had
been assumed the supposed oil impact
would not have materialized.
They also maintain that the adoption
of a partial approach would serve to
perpetuate the advantage that areas
producing low-sulfur coal enjoyed under
the current standard, which would be
counter to one of the basic purposes of
the House bill. On the other hand, they
argue, a uniform standard would not
only reduce the movement of low-sulfur
coals eastward but would serve to
maximize the use of local high-sulfur
coals.
Finally, one of the commenters
specified a more stringent full control
option than had been analyzed by EPA.
It called for a 95 percent reduction in
potential SOa emissions with about a
280 ng/J (0.65 Ib/million Btu) emission
limit on a monthly basis. In addition,
this alternative reflected higher oil
prices and declining scrubber costs with
time. The results were presented at the
December 12 and 13 public hearing on
the proposed standards.
Comments Favoring Partial or
Variable Control. Those commenters
advocating a partial or variable
approach focused their arguments on the
statutory language of Section 111. They
maintained that the standard must be
based on the "best technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated." They also
asserted that the Conference Report
language clearly gives the Administrator
authority to establish a variable
standard based on varying fuel
characteristics, i.e., coal sulfur content.
Their principal argument is that a
variable approach would achieve
virtually the same emission reductions
at the national level as a uniform
approach but at substantially lower
costs and without incurring a significant
oil penalty. In view of this, they
maintain that a variable approach best
satisfies the statutory language of
Section 111.
In support of variable control they
also note that the revised NSPS will
serve as a minimum requirement for
prevention of significant deterioration
and non-attainment considerations, and
that ample authority exists to impose
more stringent requirements on a case-
by-case basis. They contend that these
authorities should be sufficient to
protect pristine areas and national parks
in the West and to assure the attainment
and maintenance of the health-related
ambient air quality standards. Finally,
they note that the NSPS is technology-
based and not directly related to
protection of the Nation's public health.
In addition, they argue that a variable
control option would provide a better
opportunity for the development of
innovative technologies. Several
commenters noted that, in particular, a
uniform requirement would not provide
an opportunity for the development of
dry SOa control systems which they felt
held considerable promise for bringing
about SOt emission reductions at lower
costs and in a more reliable manner.
Commenters favoring variable control
also advanced the arguments that a
standard based on a range of percent
reductions would provide needed
flexibility, particularly when selecting
intermediate sulfur content coals.
Further, if a control system failed to
meet design expectations, a variable
approach would allow a source to move
to lower-sulfur coal to achieve
compliance. In addition, for low-sulfur
coal applications, a variable option
would substantially reduce the energy
penalty of operating wet scrubbers since
a portion of the flue gas could be used
for plume reheat.
To support their advocacy of a
variable approach, two commenters, the
Department of Energy and the Utility Air
Regulatory Group (UARG, representing
a number of utilities), presented detailtd
results of analyses that had been
conducted for them. UARG analyzed a
standard that required a minimum
reduction of 20 percent with 520 ng/J
(1.20 Ib/million Btu) monthly emission
limit. The Department of Energy
specified a partial control option that
required a 33 percent minimum
requirement with a 430 ng/J (1.0 lb/
million Btu) monthly emission limit.
Faced with these comments, the
Administrator determined the final
analyses that should be performed, He
concluded that analyses should be
conducted on a range of alternative
emission limits and percent reduction
requirements in order to determine the
approach which best satisfies the
statutory language and legislative
history of section 111. For these
analyses, the Administrator specified a
uniform or full control option, a partial
control option reflecting the Department
of Energy's recommendation for a 33
percent minimum control requirement,
and a variable control option which
specified a 520 ng/J (1.20 Ib/million Btu)
emission limitation with a 90 percent
reduction in potential SO2 emissions
except when emissions to the
atmosphere were reduced below 280 ng/
J (0.60 Ib/million Btu), when only a 70
percent reduction in potential SOZ
emissions would apply. Under the
variable approach, plants firing high-
sulfur coals would be required to
achieve a 90 percent reduction in
potential emissions in order to comply
with the emission limitation. Those using
intermediate and low-sulfur content
coals would be permitted to achieve
between 70 and 90 percent, provided
their emissions were less than 260 ng/J
(0.60 Ib/million BTU).
In rejecting the minimum requirement
of 20 percent advocated by .UARG, the
Administrator found that it not only
resulted in the highest emissions, but
that it was also the least cost effective
of the variable control options
considered. The more stringent full
control option presented in the
comments was rejected because it
required a 95 percent reduction in
potential emissions which may not be
within the capabilities of demonstrated
technology for high-sulfur coals in all
cases.
Emergency Conditions
The final standards allow an owner or
operator to bypass uncontrolled flue
gases around a malfunctioning FGD
system provided (1) the FGD system has
been constructed with a spare FGD
module, (2) FGD modules are not
available in sufficent numbers to treat
the entire quantity of flue gas generated,
and (3) all available electric generating
capacity is being utilized in a power
pool or network consisting of the
generating capacity of the affected
utility company (except for the capacity
of the largest single generating unit in
the company), and the amount of power
that could be purchased from
neighboring interconnected utility
companies. The final standards are
essentially the same as those proposed.
The revisions involve wording changes
to clarify the Administrator's intent and
revisions to address potential load
management and operating problems.
None of the comments received by EPA
disputed the need for the emergency
condition provisions or objected to their
intent
The intent of the final standards is to
encourage power plant owners and
operators to install the best available
FGD systems and to implement effective
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operation and maintenance procedures
but not to create power supply
disruptions. FGD systems with spare
FGD modules and FGD modules with
spare equipment components have
greater capability of reliable operation
than systems without spares. Effective
control and operation of FGD systems
by engineering supervisory personnel
experienced in chemical process
operations and properly trained FGD
system operators and maintenance staff
are also important in attaining reliable
FGD system operation. While the
standards do not require these
equipment and staffing features, the
Administrator believes that their use
will make compliance with the
standards easier. Malfunctioning FGD
systems are not exempt from the SO»
standards except during infrequent
power supply emergency periods. Since
the exemption does not apply unless a
spare module has been installed (and
operated), a spare module is required for
the exemption to apply. Because of the
disproportionate cost of installing a
spare module on steam generators
having a generating capacity of 125 MW
or less, the standards do not require
them to have-spare modules before the
emergency conditions exemption
applies.
The proposed standards included the
requirement that the emergency
condition exemption apply only to those
facilities which have installed a spare
FGD system module or which have 125
MW or less of output capacity.
However, they did not contain
procedures for demonstrating spare
module capability. This capability can
be easily determined once the facility
commences operation. To specify how
this determination is to be performed,
provisions have been added to the
regulations. This determination is not
required unless the owner or operator of
the affected facility wishes to claim
spare module capability for the purpose
of availing himself of the emergency
condition exemption. Should the
Administrator require a demonstration
of spare module capability, the owner or
operator would schedule a test within 60
days for any period of operation lasting
from 24 hours to 30 days to demonstrate
that he can attain the appropriate SOj
emission control requirements when the
facility is operated at a maximum rate
without using one of its FGD system
modules. The test can start at any time
of day and modules may be rotated in
and out of service, but at all times in the
test period one module (but not
necessarily the same module) must not
be operated to demonstrate spare
module capability.
Although it is within the
Administrator's discretion to require the
spare module capability demonstration
test, the owner or operator of the facility
has the option to schedule the specific
date and duration of the test. A
minimum of only 24 hours of operation
are required during the test period
because this period of time is adequate
to demonstrate spare module capability
and it may be unreasonable in all
circumstances to require a longer (e.g.,
30 days) period of operation at the
facility's maximum heat input rate.
Because the owner or operator has the
flexibility to schedule the test, 24 hours
of operation at maximum rate will not
impose a significant burden on the
facility
The Administrator believes that the
standards will not cause supply
disruption because (1) well designed
and operated FGD systems can attain
high operating availability, (2) a spare
FGD module can be used to rotate other
modules out of service for periodic
maintenance or to replace a
malfunctioning module, (3) load shifting
of electric generation to another
generating unit can normally be used if a
part or all of the FGD system were to
malfunction, and (4) during abnormal
power supply emergency periods, the
bypassing exemption ensures that the
regulations would not require a unit to
stand idle if its operation were needed
to protect the reliability of electric
service. The Administrator believes that
this exemption will not result in
extensive bypassing because the
probability of a major FGD malfunction
and power supply emergency occurring
simultaneously is small.
A commenter asked that the definition
of system capacity be revised to ensure
that the plant's capability rather than
plant rated capacity be used because
the full rated capacity is not always
operable. The Administrator agrees with
this comment because a component
failure (e.g., the failure of one coal
pulverizer) could prevent a boiler from
being operated at its rated capacity, but
would not cause the unit to be entirely
shut down. The definition has been
revised to allow use of the plant's
capability when determining the net
system capacity.
One commenter asked that the
definition of system capacity be revised
to include firm contractual purchases
and to exclude firm contractual sales.
Because power obtained through
contractual purchases helps to satisfy
load demand and power sold under
contract affects the net electric
generating capacity available in the
system, the Administrator agrees with
this request and has included power
purchases in the definition of net system
capacity and has excluded sales by
adding them to the definition of system
load.
A commenter asked that the
ownership basis for proration of electric
capacity in several definitions be
modified when there are other
contractual arrangements. The
Administrator agrees with this comment
and has revised the definitions
accordingly.
One commenter asked that definitions
describing "all electric generating
equipment owned by the utility
company" specifically include
hydroelectric plants. The proposed
definitions did include these plants, but
the Administrator agrees with the
clarification requested, and the
definitions have been revised.
A commenter asked that the word
"steam" be removed from the definition
of system emergency reserves to clarify
that nuclear units are included. The
Administrator agrees with the comment
and has revised the definition.
Several commenters asked that some
type of modification be made to the
emergency condition provisions that
would consider projected system load
increases within the next calendar day.
One commenter asked that emergency
conditions apply based on a projection
of the next day's load. The
Administrator does not agree with the
suggestion of using a projected load,
which may or may not materialize, as a
criterion to allow bypassing of SO2
emissions, because the load on a
generating unit with a malfunctioning
FGD system should be reduced
whenever there is other available
system capacity.
A commenter recommended that a
unit removed from service be allowed to
return to service if such action were
necessary to maintain or reestablish
system emergency reserves. The
Administrator agrees that it would be
impractical to take a large steam
generating unit entirely out of service
whenever load demand is expected to
later increase to the level where there
would be no other unit available to meet
the demand or to maintain system
emergency reserves. To address the
problem of reducing load and later
returning the load to the unit, the
Administrator has revised the proposed
emergency condition provisions to give
an owner or operator of a unit with a
malfunctioning FGD system the option
of keeping (or bringing) the unit into
spinning reserve when the unit is
needed to maintain (or reestablish)
system emergency reserves. During this
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period, emissions must be controlled to
the extent that capability exists within
the FGD system, but bypassing
emissions would be allowed when the
capability of a partially or completely
failed FGD system is inadequate. This
procedure will allow the unit to operate
in spinning reserve rather than being
entirely shut down and will ensure that
a unit can be quickly restored to service.
The final emergency condition
provisions permit bypassing of
emissions from a unit kept in spinning
reserve, but only (1) when the unit is the
last one available for maintaining
system emergency reserves, (2) when it
is operated at the minimum load
consistent with keeping the unit in
spinning reserve, and (3) has inadequate
operational FGD capability at the
minimum load to completely control SO2
emissions. This revision will still
normally require load on a
malfunctioning unit to be reduced to a
minimum level, even if load demand is
anticipated to increase later; but it does
prevent having to take the unit entirely
out of operation and keep it available in
spinning reserve to assume load should
an emergency arise or as load increases
the following day. Because emergency
condition periods are a small percentage
of total operating hours, this revision to
allow bypassing of SO, emissions from a
unit held in spinning reserve with
reduced output is expected to have
minor impact on the amount of SO2
emitted.
One commenter stated that the
proposed provisions would not reduce
the necessity for additional plant
capacity to compensate for lower net
reliability. The Administrator does not
agree with this comment because the
emergency condition provisions allow
operation of a unit with a failed FGD
system whenever no other generating
capacity is available for operation and
thereby protects the reliability of
electric service. When electric load is
shifted from a new steam-electric
generating unit to another electric
generating unit, there would be no net
change in reserves within the power
system. Thus, the emergency condition
provisions prevent a failed FGD system
from impacting upon the utility
company's ability to generate electric
power and prevents an impact upon
reserves needed by the power system to
maintain reliable electric service.
A commenter asked that the definition
of available system capacity be clarified
because (1) some utilities have certain
localized areas or zones that, because of
system operating parameters, cannot be
served by all of the electric generating
units which constitute the utility's
system capacity, and (2) an affected
facility may be the only source of supply
for a zone or area. Almost all electric
utility generating units in the United
States are electrically interconnected
through power transmission lines and
switching stations. A few isolated units
in the U.S. are not interconnected to at
least one other electric generating unit
and it is possible that a new unit could
also be constructed in an isolated area
where interconnections would not be
practical. For a single, isolated unit
where it is not practical to construct
interconnections, the emergency
condition provisions would apply
whenever an FGD malfunction occurred
because there would be no other
available system capacity to which load
could be shifted. It is also possible that
two or three units could be
interconnected, but not interconnected
with a larger power network (e.g.,
Alaska and Hawaii). To clarify this
situation, the definitions of net system
capacity, system load, and system
emergency reserves have been revised
to include only that electric power or
capacity interconnected by a network of
power transmission facilities. Few units
will not be interconnected into a
network encompassing the principal and
neighboring utility companies. Power
plants, including those without FGD
systems, are expected to experience
electric generating malfunctions and
power systems are planned with reserve
generating capacity and interconnecting
electric transmission lines to provide
means of obtaining electricity from
alternative generating facilities to meet
demand when these occasions arise.
Arrangements for an affected facility
would typically include an
interconnection to a power transmission
network even when it is geographically
located away from the bulk of the utility
company's power system to allow
purchase of power from a neighboring
utility for those localized service areas
when necessary to maintain service
reliability. Contract arrangements can
provide for trades of power in which a
localized zone served by the principal
company owning or operating the
affected facility is supplied by a
neighboring company. The power bought
by the principal company can, if desired
by the neighboring company, be
replaced by operation of other available
units in the principal company even if
these units are located at a distance
from the localized service zone. The
proposed definition of emergency
condition was contingent upon the
purchase of power from another
electrical generation facility. To further
clarify this relationship, the
Administrator has revised the proposed
definitions to define the relationship
between the principal company (the
utility company that owns the
generating unit with the malfunctioning
FGD system) and the neighboring power
companies for the purpose of
determining when emergency conditions
exist.
A commenter requested that the
proposed compliance provisions be
revised so that they could not be
interpreted to force a utility to operate a
partially functional FGD module when
extensive damage to the FGD module
would occur. For example, a severely
vibrating fan must be shut down to
prevent damage even though the FGD
system may be otherwise functional.
The Administrator agrees with this
comment and has revised the
compliance provisions not to require
FGD operation when significant damage
to equipment would result.
One commenter asked that the
definition of system emergency reserves
account for not only the capacity of the
single largest generating unit, but also
for reserves needed for system load-
frequency regulation. Regulation of
power frequency can be a problem when
the mix of capacitive and reactive loads
shift. For example, at night capacitive
load of industrial plants can adversely
affect power factors. The Administrator
disagrees that additional capacity
should be kept independent of the load
shifting requirements. Under the
definition for system emergency
reserves, capacity equivalent to the
largest single unit in the system was set
aside for load management. If frequency
regulation has been a particular
problem, extra reserve margins would
have been maintained by the utility
company even if an FGD system were
not installed. Reserve capacity need not
be maintained within a single generating
unit. The utility company can regulate
system load-frequency by distributing
their system reserves throughout the
electric power system as needed. In the
Administrator's judgment, these
regulations do not impact upon the
reserves maintained by the utility
company for the purpose of maintaining
power system integrity, because the
emergency condition provisions do not
restrict the utility company's freedom in
distributing their reserves and do not
require construction of additional
reserves.
A commenter asked that utility
operators be given the option to ignore
the loss of SO2 removal efficiency due to
FGD malfunctions by reducing the level
of electric generation from an affected
unit. This would control the amount of
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SOi emitted on.a pounds per hour basis,
but would also allow and exemption
from the percentage of Sd removal
specified by the SOi standards. The
Administrator believes that allowing
this exemption is not necessary because
load can usually be shifted to other
electric generating units. This procedure
provides an incentive to the owner or
operator to properly maintain and
operate FGD systems. Under the
procedures suggested by the coTnmenter,
neglect of the FGD system would be
encouraged because an exemption
would allow routine operation at
reduced percentages of SO, removal.
Steam generating units are often
operated at less than rated capacity and
a fully operational FGD system would
not be required for compliance during
these periods if this exemption were
allowed. The procedure suggested by
the commenter is also not necessary
because FGD modules can be designed
and constructed with separate
equipment components so that they are
routinely capable of independent
operation whenever another module of
the steam generating unit's FGD system
is not available. Thus, reducing the level
of electric generation and removing the
failed FGD module for servicing would
not affect the remainder of the FGD
system and would permit the utility to
maintain compliance with the standards
without having to take the generating
unit entirely out of operation. Each
module should have the capability of
attaining the same percentage reduction
of Sd from the flue gas it treats
regardless of the operability of the other
modules in the system to maintain
compliance with the standards.
Although the efficiency of more than one
FGD module may occasionally be
affected by certain equipment
malfunctions, a properly designed FGD
system has no routine need for an
exemption from the SO, percentage
reduction requirement when the unit is
operated at reduced load. The
Administrator has concluded that the
final regulations provide sufficient
flexibility for addressing FGD
malfunctions and that an exemption
from the percentage SOj removal
requirement is not necessary to protect
electric service reliability or to maintain
compliance with these SO2 standards.
Particulate Matter Standard
The final standard limits particulate
matter emissions to 13 ng/J (0.03 lb/
million Btu) heat input and is based on
the application of ESP or baghouse
control technology. The final standard is
the same as the proposed. The
Administrator has concluded that ESP
and baghouse control systems are the
best demonstrated systems of
continuous emission reduction (taking
into consideration the cost of achieving
such emission reduction, and nonair
quality health and enviornmental
impacts, and energy requirements) and
that 13 ng/J (0.03 Ib/million Btu} heat
input represents the emission level
achievable through the application of
these control systems.
One group of commenters indicated
that they did not support the proposed
standard because in their opinion it
would be too expensive for the benefits
obtained; and they suggested that the
final standard limit emissions to 43 ng/J
(0.10 Ib/million Btu) heat input which is
the same as the current standard under
40 CFR Part 60 Subpart D. The
Administrator disagrees with the
commenters because the available data
clearly indicate that ESP and baghouse
control systems are capable of
performing at the 13 ng/J (0.03 Ib/million
Btu) heat input emission level, and the
economic impact evaluation indicates
that the costs and economic impacts of
installing these systems are reasonable.
The number of commenters expressed
the opinion that the proposed standard
was to strict, particularly for power
plants firing low-sulfur coal, because
baghouse control systems have not been
adequately demonstrated on full-size
power plants. The commenters
suggested that extrapolation of test data
from small scale baghhouse control
systems, such as those used to support
the proposed standard, to full-size utility
applications is not reasonable.
The Administrator believes that
baghouse control systems are
demonstrated for all sizes of power
plants. At the time the standards were
proposed, the Administrator concluded
that since baghouses are designed and
constructed in modules rather than as
one large unit, there should be no
technological barriers to designing and
constructing utility-sized facilities. The
largest baghouse-controlled, coal-fired
power plant for which EPA had
emission test data to support the
proposed standard was 44 MW. Since
the standards were proposed, additional
information has become available which
supports the Administrator's position
that baghouses are demonstrated for all
sizes of power plants. Two large
baghouse-controlled, coal-fired power
plants have recently initiated
operations. EPA has obtained emission
data for one of these units. This unit has
achieved particulate matter emission
levels below 13 ng/J (0.03 Ib/million BtuJ
heat input. The baghouse system for this
facility has 28 modules rated at 12.5 MW
capacity per module. This supports the
Administrator's conclusion that
baghouses are designed and constructed
in modules rather than as one large unit,
and there should be no technological
barriers to designing and constructing
utility-sized facilities.
One commenter indicated that
baghouse control systems are not
demonstrated for large utility
application at this time and
recommended that EPA gather one year
of data from 1000 MW of baghouse
installations to demonstrate that
baghouses can operate reliably and
achieve 13 ng/J (0.03 Ib/million Btu) heat
input. The standard would remain at 21
to 34 ng/J (0.05 to 0.08 Ib/million Btu)
heat input until such demonstration. The
Administrator does not believe this
approach is necessary because
baghouse control systems have been
adequately demonstrated for large
utility applications.
One group of commenters supported
the proposed standard of 13 ng/J (0.03
Ib/million Btu) heat input. They
indicated that in their opinion the
proposed standard attained the proper
balance of cost, energy and
environmental factors and was
necessary in consideration of expected
growth in coal-fired power plant
capacity.
Another group of commenters which
included the trade association of
emission control system manufacturers
indicated that 13 ng/J (0.03 Ib/million
Btu) is technically achievable. The trade
association further indicated the
proposed standard is technically
achievable for either high- or low-sulfur
coals, through the use of baghouses,
ESPs, or wet scrubbers.
A number of commenters
recommended that the proposed
standard be lowered to 4 ng/J (0.01 lb/
million Btu) heat input. This group of
commenters presented additional
emission data for utility baghouse
control systems to support their
recommendation. The data submitted by
the commenters were not available at
the time of proposal and were for utility
units of less than 100 MW electrical
output capacity. The commenters
suggested that a 4 ng/J (o.Ol Ib/million
Btu) heat input standard is achievable
based on baghouse technology, and they
suggested that a standard based on
baghouse technology would be
consistent with the technology-forcing
nature of section 111 of the Act. The
Administrator believes that the
available data base for baghouse
performance supports a standard of 13
ng/J (0.03 Ib/million Btu) heat input but
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does not support a lower standard such
as 4 ng/J (0.01 Ib/million Btu) heat input.
One commenter suggested that the
standard should be set at 26 ng/J (0.06
Ib/million Btu) heat imput so that
particulate matter control systems
would not be necessary for oil-fired
utility steam generators. Although it is
expected that few oil-fired utility boilers
will be constructed, the ESP
performance data which is contained in
the "Electric Utility Steam Generating
Units, Background Information for
Promulgated Emission Standards" (EPA
450/3-79-021), supports the conclusion
that ESPs are applicable to both oil
firing and coal firing. The Administrator
believes that emissions from oil-fired
utility boilers should be controlled to the
same level as coal-fired boilers.
Mi Standard
The NO, standards limit emissions to
210 ng/J (0.50 Ib/million Btu) heat input
from the combustion of subbituminous
coal and 260 ng/J (0.60 Ib/million BtuJ
heat imput from the combustion of
bituminous coal, based on a 30-day
rolling average. In addition, emission
limits have been established for other
solid, liquid, and gaseous fuels, as
discussed in the rational section of this
preamble. The final standards differ
from the proposed standards only in
that the final averaging time for
determining compliance with the
standards is based on a 30-day rolling
average, whereas a 24-hour average was
proposed. All comments received during
the public commenl period were
considered in developing the final NO,
standards. The major issues raised
during the comment period are
discussed below.
One issue concerned the possibility
that the proposed 24-hour averaging
period for coal might seriously restrict
the flexibility boiler operators need
during day-to-day operation. For
example, several commenters noted that
on some boilers the control of boiler
tube slagging may periodically require
increased excess air levels, which, in
turn, would increase NO, emissions.
One commenter submitted data
indicating that two modern Combustion
Engineering (CE) boilers at the Colstrip,
Montana plant of the Montana Power
Company do not consistently achieve
the proposed NO, level of 210 ng/J (0.50
Ib/million Btu) heat input on a 24-hour
basis. The Colstrip boilers burn
subbituminous coal and are required to
comply with the.NO, standard under 40
CFR Part 60, Subpart D of 300 ng/J (0.70
Ib/million Btu) heat input. Several other
commenters recommended that the 24-
hour averaging period be extended to 30
days to allow for greater operational
flexibility.
As an aid in evaluating the
operational flexibility question, the
Administrator has reviewed a total of 24
months of continuously monitored NO,
data from the two Colstrip boilers. Six
months of these data were available to
the Administrator before proposal of
these standards, and two months were
submitted by a commenter. The
commenter also submitted a summary of
28 months of Colstrip data indicating the
number of 24-hour averages per month
above 210 ng/J (0.50 Ib/million Btu) heat
input The remaining Colstrip data were
obtained by the Administrator from the
State of Montana after proposal. In
addition to the Colstrip data, the
Administrator has reviewed
approximately 10 months of
continuously monitored NO, data from
five modern CE utility boilers. Three of
the boilers burn subbituminous coal,
two burn bituminous coal, and all five
have monitors that have passed
certification tests. These data were
obtained from electric utility companies
after proposal. A summary of all of the
continuously monitored NO, data that
the Administrator has considered
appears in "Electric Utility Steam
Generating Units, Background
Information for Promulgated Emission
Standards" (EPA 450/3-79-021).
The usefulness of these continuously
monitored data in evaluating the ability
of modern utility boilers to continuously
achieve the NO, emission limits of 210
and 260 ng/J (0.50 and 0.60 Ib/million
Btu) heat input is somewhat limited.
This is because the boilers were
required to comply with a higher NO,
level of 300 ng/J (0.70 Ib/million Btu)
heat input. Nevertheless some
conclusions can be drawn, as follows:
(1) Nearly all of the continuously
monitored NO, data are in compliance
with the boiler design limit of 300 ng/J
(0.70 Ib/million Btu) heat input on the
basis of a 24-hour average.
(2) Most of the continuously
monitored NO, data would be in
compliance with limits of 260 ng/J (0.60
Ib/million Btu) heat input for bituminous
coal ov 210 ng/J (0.50 Ib/million Btu)
heat input for subbituminous coal when
averaged over a 30-day period. Some of
the data would be out of compliance
based on a 24-hour average.
(3) The volume of continuously
monitored NO, emission data evaluated
by the Administrator (34 months from
seven large coal-fired boilers) is
sufficient to indicate the emission
variability expected during day-to-day
operation of a utility-size boiler. In the
Administrator's judgment, this emission
variability adequately represents
slagging conditions, coal variability,
load changes, and other factors that may
influence the level of NO, emissions.
(4) The variability of continuously
monitored NO, data is sufficient to
cause some concern over the ability of a
utility boiler that burns solid fuel to
consistently iachievp a NO, boiler design
limit, whether 300, 260, or 210 ng/J (0.70,
0.60, or 0.50 Ib/million Btu) heat input,
based on 24-hour averages. In contrast,
it appears that there would be no
difficulty in achieving the boiler design
limit based on 30-day periods.
Based on these conclusions, the
Administrator has decided to require
compliance with the final standards for
solid fuels to be based on a 30-day
rolling average. The Administrator
believes that the 30-day rolling average
will allow boilers made by all four major
boiler manufacturers to achieve the
standards while giving boiler operators
the flexibility needed to handle
conditions encountered during normal
operation.
Although the Administrator has not
evaluated continuously monitored NO,
data from boilers manufactured by
companies other than CE, the data from
CE boilers are considered representative
of the other boiler manufacturers. This is
because the boilers of all four
manufacturers are capable of achieving
the same NO,[ design limit, and because
the conditions that occur during normal
operation of a boiler (e.g., slagging,
variations in fuel quality, and load
reductions) are similar for all four
manufacturer designs. These conditions,
the Administrator believes, lead to
similar emission variability and require
essentially the same degree of
operational flexibility.
Some commenters have question the
validity of the Colstrip data because the
Colstrip continuous NO, monitors have
not passed certification tests. In April
and June of 1978 EPA conducted a
detailed evaluation of these monitors.
The evaluation led the Administrator to
conclude that the monitors were
probably biased high, but by less than
21 ng/J (0.50 Ib/million Btu) heat input.
Since this error is so small (less than 10
percent), the Administrator considers
the data appropriate to use in
developing the standards.
A number of commenters expressed
concern over the ability of as many as
three of the four major boiler
manufacturer designs to achieve the
proposed standards. Although most of
the available NO, test data are from CE
boilers, the Administrator believes that
all four of the boiler manufacturers will
be able to supply boilers capable of
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achieving the standards. This conclusion
is supported with (1) emission test
results from 14 CE, seven Babcock and
Wilcox (B&W), three Foster Wheeler
(FW), and four Riley Stoker (RS) utility
boilers; (2) 34 months of continuously
monitored NO, emission data from
seven CE boilers; and (3) an evaluation
of plans under way at B&W, FW, and RS
to develop low-emission burners and
furnace designs. Full-scale tests of these
burners and furnace designs have
proven their effectiveness in reducing
NO, emissions without apparent long-
term adverse side effects.
Another issue raised by commenters
concerned the effect that variations in
the nitrogen content of coal may have on
achieving the NO, standards. The
Adminstrator recognizes that NO, levels
are sensitive to the nitrogen content of
the coal burned and that the combustion
of high-nitrogen-content coals might be
expected to result in higher NO,
emissions than those from coals with
low nitrogen contents. However, the
Administrator also recognizes that other
factors contribute to NO, levels,
including moisture in the coal, boiler
design, and boiler operating practice. In
the Administrator's judgment, the
emission limits for NO, are achievable
with properly designed and operated
boilers burning any coal, regardless of
its nitrogen content. As evidence of this,
three of the six boilers tested by EPA
burned coals with nitrogen contents
above average, and yet exhibited NO,
emission levels well below the
standards. The three boilers that burned
coals with lower nitrogen contents also
exhibited emission levels below the
standards. The Administrator believes
this is evidence that at NO, levels near
210 and 260 ng/J (0.50 and 0.60 lb/
million Btu) heat input, factors other
than fuel-nitrogen-content predominate
in determining final emission levels.
A number of commenters expressed
concern over the potential for
accelerated tube wastage (i.e.,
corrosion) during operation of a boiler in
compliance with the proposed
standards. Almost all of the 300-hour
and 30-day coupon corrosion tests
conducted during the EPA-sponsored
low-NO, studies indicate that corrosion
rates decrease or remain stable during
operation of boilers at NO, levels as low
as those required by the standards. In
the few instances where corrosion rates
increased during low-NO, operation, the
increases were considered minor. Also,
CE has guaranteed that its new boilers
will achieve the NO, emission limits
without increased tube corrosion rates.
Another boiler manufacturer, B&W, has
developed new low-emission burners
that minimize corrosion by surrounding
the flame in an oxygen-rich atmosphere.
The other boiler manufacturers have
also developed techniques to reduce the
potential for corrosion during low-NO,
operation. The Administrator has
received no contrasting information to
the effect that boiler tube corrosion
rates would significantly increase as a
result of compliance with the standards.
• Several commenters stated that
according to a survey of utility boilers
subject to the 300 ng/J (0.70 Ib/million
Btu) heat input standard under 40 CFR
Part 60, Subpart D, none of the boilers
can achieve the standard promulgated
here of 200 ng/J (0.60 Ib/million Btu)
heat input on a range of bituminous
coals. Three of the-six utility boilers
tested by EPA burned bituminous coal.
(Two of these boilers were
manufactured by CE and one by B&W.J
In addition, the Administrator has
reviewed continuously monitored NO,
data from two CE boilers that burn
bituminous coal. Finally, the
Administrator has examined NO,
emission data obtained by the boiler
manufacturers on seven CE, four B&W,
three FW, 'and three RS modern boilers,
all of which burn bituminous coal.
Nearly all of these data are below the
260 ng/J (0.60 Ib/million Btu) heat input
standard. The Administrator believes
that these data provide adequate
evidence that the final NO, standard for
bituminous coal is achievable by all four
boiler manufacturer designs.
An issue raised by several
commenters concerned the use of
catalytic ammonia injection and
advanced low-emission burners to
achieve NO, emission levels as low as
15 ng/J (0.034 Ib/million Btu) heat input.
Since these controls are not yet
available, the commenters
recommended that new utility boilers be
designed with sufficient space to allow
for the installation of ammonia injection
and advanced burners in the future. In
the meantime the commenters
recommended that NO, emissions be
limited to 190 ng/J (0.45 Ib/million Btu)
heat input. The Administrator believes
that the technology needed to achieve
NO, levels as low as 15 ng/J (0.034 lb/
million Btu) heat input has not been
adequately demonstrated at this time.
Although a pilot-scale catalytic-
ammonia-injection system has
successfully achieved 90 percent NO,
removal at a coal-fired utiliiy power
plant in Japan, operation of a full-scale
ammonia-injection system has not yet
been demonstrated on a large coal-fired
boiler. Since the Clean Air Act requires
that emission control technology for new
source performance standards be
adequately demonstrated, the
Administrator cannot justify
establishing a low NO, standard based
on unproven technology. Similarly, the
Administrator cannot justify requiring
boiler designs to provide for possible
future installation of unproven
technology.
The recommendation that NO,
emissions be limited to 190 ng/J (0.45 lb/
million Btu) heat input is based on boiler
manufacturer guarantees jn California.
(No such utility boilers have been built
as yet.) Although manufacturer
guarantees are appropriate to consider
when establishing emission limits, they
cannot always be used as a basis for a
standard. As several commenters have
noted, manufacturers do not always
achieve their performance guarantees.
The standard is not established at this
level, because emission test data are not
available which demonstrate that a
level of 190 ng/J (0.45 Ib/million Btu)
heat input can be continuously achieved
without adverse side effects when a
wide variety of coals are burned.
Regulatory Analysis
Executive Order 12044 (March 24,
1978), whose objective is to improve
Government regulations, requires
executive branch agencies to prepare
regulatory analyses for regulations that
may have major economic
consequences. EPA has extensively
analyzed the costs and other impacts of
these regulations. These analyses, whicn
meet the criteria for preparation of a
regulatory analysis, are contained
within the preamble to the proposed
regulations (43 FR 42154), the
background documentation made
available to the public at the time of
proposal (see STUDIES, 43 FR 42171),
this preamble, and the additional
background information document
accompanying this action ("Electric
Utility Steam Generating Units,
Background Information for
Promulgated Emission Standards," EPA-
450/3-79-021). Due to the volume of this
material and its continual development
over a period of 2-3 years, it is not
practical to consolidate all analyses into
a single document. The following
discussion gives a summary of the most
significant alternatives considered. The
rationale for the action taken for each
pollutant being regulated is given in a
previous section.
In order to determine the appropriate
form and level of control for the
standards, EPA has performed extensive
analysis of the potential national
impacts associated with the alternative
standards. EPA employed economic
models to forecast the structure and
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operating characteristics of the utility
industry in future years. These models
project the environmental, economic,
and energy impacts of alternative
standards for the electric utility
industry. The major analytical efforts
took place in three phases as described
below.
Phase 1. The initial effort comprised a
preliminary analysis completed in April
1978 and a revised assessment
completed in August 1978. These
analyses were presented in the
September 19,1978 Federal Register
proposal (43 FR 42154). Corrections to
the September proposal package and
additional information was published on
November 27,1978 (43 FR 55258).
Further details of the analyses can be
found in "Background Information for
Proposed SOt Emission Standards—
Supplement," EPA 450/2-78-007a-l.
Phase 2. Following the September 19
proposal, the EPA staff conducted
additional analysis of the economic,
environmental, and energy impacts
associated with various alternative
sulfur dioxide standards. As part of this
effort, the EPA staff met with
representatives of the Department of
Energy, Council of Economic Advisors,
Council on Wage and Price Stability,
and others for the purpose of
reexamining the assumptions used for
the August analysis and to develop
alternative forms of the standard for
analysis. As a result, certain
assumptions were changed and a
number of new regulatory alternatives
were defined. The EPA staff again
employed the economic model that was
used in August to project the national
and regional impacts associated with
each alternative considered.
The results of the phase 2 analysis
were presented and discussed at the
public hearings in December and were
published in the Federal Register on
December 8,1978 (43 FR 7834).
Phase 3. Following the public
hearings, the EPA staff continued to
analyze the impacts of alternative sulfur
dioxide standards. There were two
primary reasons for the continuing
analysis. First, the detailed analysis
(separate from the economic modeling)
of regional coal production impacts
pointed to a need to investigate a range
of higher emission limits.
Secondly, several comments were
received from the public regarding the
potential of dry sulfur dioxide scrubbing
systems. The phase 1 and phase 2
analyses had assumed that utilities
would use wet scrubbers only. Since dry
scrubbing costs substantially less then
wet scrubbing, adoption of the dry
technology would substantially change
the economic, energy, and
environmental impacts of alternative
sulfur dioxide standards. Hence, the
phase 3 analysis focused on the impacts
of alternative standards under a range
of emission ceilings assuming both wet
technology and the adoption of dry
scrubbing for applications in which it is
technically and economically feasible.
Impacts Analyzed
The environmental impacts of the
alternative standards were examined by
projecting pollutant emissions. The
emissions were estimated nationally
and by geographic region for each plant
type, fuel type, and age category. The
EPA staff also evaluated the waste
products that would be generated under
alternative standards.
The economic and financial effects of
the alternatives were examined. This
assessment included an estimation of
the utility capital expenditures for new
plant and pollution control equipment as
well as the fuel costs and operating and
maintenance expenses associated with
the plant and equipment. These costs
were examined in terms of annualized
costs and annual revenue requirements.
The impact on consumers was
determined by analyzing the effect of
the alternatives on average consumer
costs and residential electric bills. The
alternatives were also examined in
terms of cost per ton of SO» removal.
Finally, the present value costs of the
alternatives were calculated.
The effects of the alternative
proposals on energy production and
consumption were also analyzed.
National coal use was projected and
broken down in terms of production and
consumption by geographic region. The
amount of western coal shipped to the
Midwest and East was also estimated.
In addition, utility consumption of oil
and natural gas was analyzed.
Major Assumptions
Two types of assumptions have an
important effect on the results of the
analyses. The first group involves the
model structure and characteristics. The
second group includes the assumptions
used to specify future economic
conditions.
The utility model selected for this
analysis can be characterized as a cost
minimizing economic model. In meeting
demand, it determines the most
economic mix of plant capacity and
electric generation for the utility system,
based on a consideration of construction
and operating costs for new plants and
variable costs for existing plants. It also
determines the optimum operating level
for new and existing plants. This
economic-based decision criteria should
be kept in mind when analyzing the
model results. These criteria imply, for
example, that all utilities base decisions
on lowest costs and that neutral risk is
associated with alternative choices.
Such assumptions may not represent
the utility decision making process in all
cases. For example, the model assumes
that a utility bases supply decisions on
the cost of constructing and operating
new capacity versus the cost of
operating existing capacity.
Environmentally, this implies a tradeoff
between emissions from new and old
sources. The cost minimization
assumption implies that in meeting the
standard a new power plant will fully
scrub high-sulfur coal if this option is
cheaper than fully or partially scrubbing
low-sulfur coal. Often the model will
have to make such a decision, especially
in the Midwest where utilities can
choose between burning local high-
sulfur or imported western low-sulfur
coal. The assumption of risk neutrality
implies that a utility will always choose
the low-cost option. Utilities, however,
may perceive full scrubbing as involving
more risks and pay a premium to be able
to partially scrub the coal. On the other
hand, they may perceive risks
associated with long-range
transportation of coal, and thus opt for
full control even though partial control
is less costly.
The assumptions used in the analyses
to represent economic conditions in a
given year have a significant impact on
the final results reached. The major
assumptions uaed in the analyses are
shown in Table 1 and the significance of
these parameters is summarized below.
The growth rate in demand for electric
power is very important since this rate
determines the amount of new capacity
which will be needed and thus directly
affects the emission estimates and the
projections of pollution control costs. A
high electric demand growth rate results
in a larger emission reduction
associated with the proposed standards
and also results in higher costs.
The nuclear capacity assumed to be
installed in a given year is also.
important to the analysis. Because
nuclear power is less expensive, the
model will predict construction of new
nuclear plants rather than new coal
plants. Hence, the nuclear capacity
assumption affects the amount of new
coal capacity which will be required to
meet a given electric demand level. In
practice, there are a number of
constraints which limit the amount of
nuclear capacity which can be
constructed, but for this study, nuclear
capacity was specified approximately
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
equal to the mpderate growth
projections of the Department of Energy.
The oil price assumption has a major
impact on the amount of predicted new
coal capacity, emissions, and oil
consumption. Since the model makes
generation decisions based on cost, a
low oil price relative to the cost of
building and operating a new coal plant
will result in more oil-fired generation
and less coal utilization. This results in
less new coal capacity which reduces
capital costs but increases oil
consumption and fuel costs because oil
is more expensive per Btu than coal.
This shift in capacity utilization also
affects emissions, since an existing oil
plant generally has a higher emission
rate than a new coal plant even when
only partial control is allowed on the
new plant.
Coal transportation and mine labor
rates both affect the delivered price of
coal. The assumed transportation rate is
generally more important to the
predicted consumption of low-sulfur
coal (relative to high-sulfur coal), since
that is the coal type which is most often
shipped long distances. The assumed
mining labor cost is more important to
eastern coal costs and production
estimates since this coal production is
generally much more labor intensive
than western coal.
Because of the uncertainty involved in
predicting future economic conditions,
the Administrator anticipated a large
number of comments from the public
regarding the modeling assumptions.
While the Administrator would have
liked to analyze each scenario under a
range of assumptions for each critical
parameter, the number of modeling
inputs made such an approach
impractical. To decide on the best
assumptions and to limit the number of
sensitivity runs, a joint working group
was formed. The group was comprised
of representatives from the Department
of Energy, Council of Economic
Advisors, Council on Wage and Price
Stability, and others. The group
reviewed model results to date,
identified the key inputs, specified the
assumptions, and identified the critical
parameters for which the degree of
uncertainty was such that sensitivity
analyses should be performed. Three
months of study resulted in a number of
changes which are reflected in Table 1
and discussed below. These
assumptions were used in both the
phase 2 and phase 3 analyses.
After more evaluation, the joint
working group concluded that the oil
prices assumed in the phase 1 analysis
were too high. On the other hand, no
firm guidance was available as to what
oil prices should be used. In view of this,
the working group decided that the best
course of action was to use two sets of
oil prices which reflect the best
estimates of those governmental entities
concerned with projecting oil prices. The
oil price sensitivity analysis was part of
the phase 2 analysis which was
distributed at the public hearing. Further
details are available in the draft report,
"Still Further Analysis of Alternative
New Source Performance Standards for
New Coal-Fired Power Plants (docket
number IV-A-5)." The analysis showed
that while the variation in oil price
affected the magnitude of emissions,
costs, and energy impacts, price
variation had little effect on the relative
impacts of the various NSPS alternatives
tested. Based on this conclusion, the
higher oil price was selected for
modeling purposes since it paralleled
more closely the middle range
projections by the Department of
Energy.
Reassessment of the assumptions
made in the phase 1 analysis also
revealed that the impact of the coal
washing credit had not been considered
in the modeling analysis. Other credits
allowed by the September proposal,
such as sulfur removed by the
pulverizers or in bottom ash and flyash,
were determined not to be significant
when viewed at the national and
regional levels. The coal washing credit,
on the other hand, was found to have a
significant effect on predicted emissions
levels and, therefore, was factored into
the analysis.
As a result of this reassessment,
refinements also were made in the fuel
gas desulfurization (FGD) costs
assumed. These refinements include
changes in sludge disposal costs, energy
penalties calculated for reheat, and
module sizing. In addition, an error was
corrected in the calculation of partial
scrubbing costs. These changes have
resulted in relatively higher partial
scrubbing costs when compared to full
scrubbing.
Changes were made in the FGD
availability assumption also. The phase
1 analysis assumed 100 percent
availability of FGD systems. This
assumption, however, was in conflict
with EPA's estimates on module
availability. In view of this, several
alternatives in the phase 2 analysis were
modeled at lower system availabilities.
The assumed availability was consistent
with a 90 percent availability for
individual modules when the system is
equipped with one spare. The analysis
also took into consideration the
emergency by-pass provisions of the
proposed regulation. The analysis
showed that lower reliabilities would
result in somewhat higher emissions and
costs for both the partial and full control
cases. Total coal capacity was slightly
lower under full control and slightly
higher under partial control. While it
was postulated that the lower reliability
assumption would produce greater
adverse impacts on full control than on
partial control options, the relative
differences in impacts w<,,-e found to be
insignificant. Hence, the working group
discarded the reliability issue as a major
consideration in the analyzing of
national impacts of full and partial
control options. The Administrator still
believes that the newer approach better
reflects the performance of well
designed, operated, and maintained
FGD systems. However, in order to
expedite the analyses, all subsequent
alternatives were analyzed with an
assumed system reliability of 100
percent.
Another adjustment to the analysis
was the incorporation of dry SO»
scrubbing systems. Dry scrubbers were
assumed to be available for both new
and retrofit applications. The costs of
these systems were estimated by EPA's
Office of Research and Development
based on pilot plant studies and
contract prices for systems currently
under construction. Based on economic
analysis, the use of dry scrubbers was
assumed for low-sulfur coal (less than
1290 ng/J or 3 Ib SO,/million Btu)
applications in which the control
requirement was 70 percent or less. For
higher sulfur content coals, wet
scrubbers were assumed to be more
economical. Hence, the scenarios
characterized as using "dry" costs
contain a mix of wet and dry technology
whereas the "wet" scenarios assume
wet scrubbing technology only.
Additional refinements included a
change in the capital charge rate for
pollution control equipment to conform
to the Federal tax laws on depreciation,
and the addition of 100 billion tons of
coal reserves not previously accounted
for in the model.
Finally, a number of less significant
adjustments were made. These included
adjustments in nuclear capacity to
reflect a cancellation of a plant,
consideration of oil consumption in
transporting coal, and the adjustment of
costs to 1978 dollars rather than 1975
dollars. It should be understood that all
reported costs include the costs of
complying with the proposed particulate
matter standard and NO, standards, as
well as the sulfur dioxide alternatives.
The model does not incorporate the
Agency's PSD regulations nor
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forthcoming requirements to protect
visibility.
Public Comments
Following the September proposal, a
number of comments were received on
the impact analysis. A great number
focused on the model inputs, which
were reviewed in detail by the joint
working group. Members of the joint
working group represented a spectrum
of expertise (energy, jobs, environment,
inflation, commerce). The following
paragraphs discuss only those
comments addressed to parts of the
analysis which were not discussed in
the preceding section.
One commenter suggested that the
costs of complying with State
Implementation Plan (SEP) regulations
and prevention of significant
deterioration requirements should not
be charged to the standards. These cost?
are not charged to the standards in the
analyses. Control requirements under
PSD are based on site specific, case-by-
case decisions for which the standards
serves as a minimum level of control.
Since these judgments cannot be
forecasted accurately, no additional
control was assumed by the model
beyond the requirements of these
standards. In addition, the cost of
meeting the various SEP regulations was
included as a base cost in all the
scenarios modeled. Thus, any forecasted
cost differences among alternative
standards reflect differences in utility
expenditures attributable to changes in
the standards only.
Another commenter believed that the
time horizon for the analysis (1990/1995)
was too short since most plants on line
at that time will not be subject to the
revised standard. Beyond 1995, our data
show that many of the power plants on
line today will be approaching
retirement age. As utilization of older
capacity declines, demand will be
picked up by newer, better controlled
plants. As this replacement occurs,
national SO, emissions will begin to
decline. Based on this projection, the
Administrator believes that the 1990-
1995 time frame will represent the peak
years for SO, emissions and is,
therefore, the relevant time frame for
this analysis.
Use of a higher general inflation rate
was suggested by one commenter. A
distinction must be made between
general inflation rates and real cost
escalation. Recognizing the uncertainty
of future inflation rates, the EPA staff
conducted the economic analysis in a
manner that minimized reliance on this"
assumption. All construction, operating,
and fuel costs were expressed as
constant year dollars and therefore the
analysis is not affected by the inflation
rate. Only real cost escalation was
included in the economic analysis. The
inflation rates will have an impact on
the present value discount rate chosen
since this factor equals the inflation rate
plus the real discount rate. However,
this impact is constant across all
scenarios and will have little impact on
the conclusions of the analysis.
Another commenter opposed the
presentation of economic impacts in
terms of monthly residential electric
bills, since this treatment neglects the
impact of higher energy costs to
industry. The Administrator agrees with
this comment and has included indirect
consumer impacts in the analysis. Based
on results of previous analysis of the
electric utility industry, about half of the
total costs due to pollution control are
felt as direct increases in residential
electric bills. The increased costs also
flow into the commercial and industrial
sectors where they appear as increased
costs of consumer goods. Since the
Administrator is unaware of any
evidence of a multiplier effect on these
costs, straight cost pass through was
assumed. Based on this analysis, the
indirect consumer impacts (Table 5]
were concluded to be equal to the
monthly residential bills ("Economic
and Financial Impacts of Federal Air
and Water Pollution Controls on the
Electric Utility Industry," EPA-230/3-
76/013, May 1976).
One utility company commented that
the model did not adequately simulate
utility operation since it did not carry
out hour-by-hour dispatch of generating
units. The model dispatches by means of
load duration curves which were
developed for each of 35 demand
regions across the United States.
Development of these curves took into
consideration representative daily load
curves, traditional utility reserve
margins, seasonal demand variations,
and historical generation data. The
Administrator believes that this
approach is adequate for forecasting
long-term impacts since it plans for
meeting short-term peak demand
requirements.
Summary of Results
The final results of the analyses are
presented in Tables 2 through 5 and
discussed below. For the three
alternative standards presented,
emission limits and percent reduction
requirements are 30-day rolling
averages, and each standard was
analyzed with a particulate standard of
13 ng/J (0.03 Ib/million Btu) and the
proposed NO, standards. The full
control option was specified as a 520
ng/I (1.2 Ib/million Btu) emission limit
with a 90 percent reduction in potential
SOa emissions. The other options are the
same as full control except when the
emissions to the atmosphere are
reduced below 260 ng/j (0.6 Ib/million
Btu) in which case the minimum percent
reduction requirement is reduced. The
variable control ontion requires a 70
percent minimum reduction and the
partial control option has a 33 percent
minimum reduction requirement. The
impacts of each option were forecast
first assuming the use of wet scrubbers
only and then assuming introduction of
dry scrubbing technology. In contrast to
the September proposal which focused
on 1990 impacts, the analytical results
presented today are for the year 1995.
The Administrator believes that 1995
better represents the differences among
alternatives since more new plants
subject to the standard will be on line
by 1995. Results of the 1990 analyses are
available in the public record.
Wet Scrubbing Results
The projected SO2 emissions from
utility boilers are shown by plant type
and geographic region in Tables 2 and 3.
Table 2 details the 1995 national SO,
emissions resulting from different plant
types and age groups. These standards
will reduce 1995 SO2 emissions by about
3 million tons per year (13 percent) as
compared to the current standards. The
emissions from new plants directly
affected by the standards are reduced
by up to 55 percent. The emission
reduction from new plants is due in part
to lower emission rates and in part to
reduced coal consumption predicted by
the model. The reduced coal
consumption in new plants results from
the increased cost of constructing and
operating new coal plants due to
pollution controls. With these increased
costs, the model predicts delays in
construction of new plants and changes
in the utilization of these plants after
start-up. Reduced coal consumption by
new plants is accompanied by higher
utilization of existing plants and
combustion turbines. This shift causes
increased emissions from existing coal-
and.oil-fired plants, which partially
offsets the emi ssion reductions achieved
by new plants subject to the standard.
Projections of 1995 regional SOa
emissions are summarized in Table 3.
Emissions in the East are reduced by
about 10 to 13 percent as compared to
predictions under the current standards,
whereas Midwestern emissions are
reduced only slightly, The smaller
reductions in the Midwest are due to a
slow growth of new coal-fired capacity.
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In general, introductions of coal-fired
capacity tends to reduce emissions since
new coal plants replace old coal- and
oil-fired units which have higher
emission rates. The greatest emission
reduction occurs in the West and West
South Central regions where significant
growth is expected and today's
emissions are relatively low. For these
two regions combined, the full control
option reduces emissions by 40 percent
from emission levels under the current
standards, while the partial and variable
options produce reductions of about 30
percent.
Table 4 illustrates the effect of the
proposed standards on 1995 coal
production, western coal shipped east,
and utility oil and gas consumption.
National coal production is predicted to
triple by 1995 under all the alternative
standards. This increased demand
raises production in all regions of the
country as compared to 1975 levels.
Considering these major increases in
national production, the small
production variations among the
alternatives are not large. Compared to
production under the current standards,
production is down somewhat in the
West, Northern Great Plains, and
Appalachia, while production is up in
the Midwest. These shifts occur because
of the reduped economic advantage of
low-sulfur coals under the revised
standards. While three times higher than
1975 levels, western coal shipped east is
lower under all options than under the
current standards.
Oil consumption in 1975 was 1.4
million barrels per day. The 3.1 million
barrels per day figure for 1975
consumption in Table 4 includes utility
natural gas consumption (equivalent of
1.7 million barrels per day) which the
analysis assumed would be phased out
by 1990. Hence, in 1995, the 1.4 million
barrel per day projection under current
standards reflects retirement of existing
oil capacity and offsetting increases in
consumption due to gas-to-oil
conversions.
Oil consumption by utilities is
predicted to increase under all the
options. Compared to the current
standards, increased consumption is
200,000 barrels per day under the partial
and variable options and 400,000 barrels
per day under full control. Oil
consumption differences are due to the
higher costs of new coal plants under
these standards, which causes a shift to
more generation from existing oil plants
and combustion turbines. This shift in
generation mix has important
implications for the decision-making
process, since the only assumed
constraint to utility oil use was the
price. For example, if national energy
policy imposes other constraints which
phase out or stabilize oil use for electric
power generation, then the differences
in both oil consumption and oil plant
emissions (Table 2) across the various
standards will be mitigated.
Constraining oil consumption, however,
will spread cost differences among
standards.
The economic effects in 1995 are
shown in Table 5. Utility capital
expenditures increase under all options
as compared to the $770 billion
estimated to be required through 1995 in
the absence of a change in the standard.
The capital estimates in Table 5 are
increments over the expenditures under
the current standard and include both
plant capital (for new capacity] and
pollution control expenditures. As
shown in Table 2, the model estimates
total industry coal capacity to be about
17 GW (3 percent) greater under the
non-uniform control options. The cost of
this extra capacity makes the total
utility capital expenditures higher under
the partial and variable options, than
under the full control option, even
though pollution control capital is lower.
Annualized cost includes levelized
capital charges, fuel costs, and
operation and maintenance costs
associated with utility equipment. All of
the options cause an increase in
annualized cost over the current
standards'. This increase ranges from a
low of $3.2 billion for partial control to
$4.1 billion for full control, compared to
the total utility annualized costs of
about $175 billion.
The average monthly bill is
determined by estimating utility revenue
requirements which are a function of
capital expenditures, fuel costs, and
operation and maintenance costs. The
average bill is predicted to increase only
slightly under any of the options, up to a
maximum 3-percent increase shown for
full control. Over half of the large total
increase in the average monthly bill
over 1975 levels ($25.50 per month) is
due to a significant increase in the
amount of electricity used by each
customer. Pollution control
expenditures, including those to meet
the current standards, account for about
15 percent of the increase in the cost per
kilowatt-hour while the remainder of the
cost increase is due to capital intensive
capacity expansion and real escalations
in construction and fuel cost.
Indirect consumer impacts range from
$1.10 to $1.60 per month depending on
the alternative selected. Indirect
consumer impacts reflect increases in
consumer prices due to the increased
energy costs in the commercial and
industrial sectors.
The incremental costs per ton of SO,
removal are also shown in Table 5. The
figures are determined by dividing the
change in annualized cost by the change
in annual emissions, as compared to the
current standards. These ratios are a
measure of the cost effectiveness of the
options, where lower ratios represent a
more efficient resource allocation. All
the options result in higher cost per ton
than the current standards with the full
control option being the most expensive.
Another measure of cost effectiveness
is the average dollar-per-ton cost at the
plant level. This figure compares total
pollution control cost with total SOj
emission reduction for a model plant.
This average removal cost varies
depending on the level of control and
the coal sulfur content. The range for full
control is from $325 per ton on high-
sulfur coal to $1,700 per ton on low-
sulfur coal. On low-sulfur coals, the
partial control cost is $2,000 per ton, and
the variable cost is $1,700 per ton.
The economic analyses also estimated
the net present value cost of each
option. Present value facilitates
comparison of the options by reducing
the streams of capital, fuel, and
operation and maintenance expenses to
one number. A present value estimate
allows expenditures occurring at
different times to be evaluated on a
similar basis by discounting the
expenditures back to a fixed year. The
costs chosen for the present value
analysis were the incremental utility
revenue requirements relative to the
current NSPS. These revenue
requirements most closely represent the
costs faced by consumers. Table 5
shows that the present value increment
for 1995 capacity is $41 billion for full
control, $37 billion for variable control,
and $32 billion for partial control.
Dry Scrubbing Results
Tables 2 through 5 also show the
impacts of the options under the
assumption that dry SOi scrubbing
systems penetrate the pollution control
market. These analyses assume that
utilities will install dry scrubbing
systems for all applications where they
are technologically feasible and less
costly than wet systems. (See earlier
discussion of assumptions.)
The projected SO» emissions from
utility boilers are shown by plan type
and geographic region in Tables 2 and 3.
National emission projections are
similar to the wet scrubbing results.
Under the dry control assumption,
however, the variable control option is
predicted to have the lowest national
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emissions primarily due to lower oil
plant emissions relative to the full
control option. Partial control produces
more emissions than variable control
because of higher emissions from new
plants. Compared to the current
standards, regional emission impacts
are also similar to the wet scrubbing
projections. Full control results in the
lowest emissions in the West, while
variable control results hi the lowest
emissions in the East. Emissions in the
Midwest and West South Central are
relatively unaffected by the options.
Inspection of Tables 2 and 3 shows
that with the dry control assumption the
current standard, full control, and
partial control cases produce slightly
higher emissions than the corresponding
wet control cases. This is due to several
factors, the most important of which is a
shift in the generation mix. This shift
occurs because dry scrubbers have
lower capital costs and higher variable
costs than wet scrubbers and, therefor,
the two systems have different effects
on the plant utilization rates. The higher
variable costs are due primarily to
transportation charges on intermediate
-to low sulfur coal which must be used
with dry scrubbers. The increased
variable cost of dry controls alters the
dispatch order of existing plants so that
older, uncontrolled plants operate at
relatively higher capacity factors than
would occur under the wet scrubbing
assumption, hence increasing total
emissions. Another factor affecting
emissions is utility coal selection which
may be altered by differences in
pollution control costs.
Table 4 shows the effect to the
proposed standards on fuels in 1995.
National coal production remains
essentially the same whether dry or wet
controls are assumed. However, the use
of dry controls causes a slight
reallocation in regional coal production,
except under a full control option where
dry controls cannot be applied to new
plants. Under the variable and partial
options Appalachian production
increases somewhat due to greater
demand for intermedia^ sulfur coals
while Midwestern coal production
declines slightly. The non-uniform
options also result in a small shifting in
the western regions with Northern Great
Plains production declining and
production in the rest of West
increasing. The amount of western coal
shipped east under the current standard
is reduced from 122 million to 99 million
tons (20% decrease) due to the increased
use of eastern intermediate sulfur coals
for dry scrubbing applications. Western
coal shipped east is reduced further by
the revised standards, to a low of 55
million tons under full control. Oil
impacts under the dry control
assumption are identical to the wet
control cases, with full control resulting
in increased consumption of 200
thousand barrels per day relative to the
partial and variable options.
The 1995 economic effects of these
standards are presented in Table 5. In
general, the dry control assumption
results in lower costs. However, when
comparing the dry control costs to the
wet control figures it must be kept in^
mind that the cost base for comparison,
the current standards, is different under
the dry control and wet control
assumptions. Thus, while the
uncremental costs of full control are
higher under the dry scrubber
assumption the total costs of meeting
the standard is lower than if wet
controls were used.
The economic impact figures show
that when dry controls are assumed the
cost savings associated with the
variable and partial options is
significantly increased over the wet
control cases. Relative to full control the
partial control option nets a savings of
$1.4 billion in annualized costs which
equals a $14 billion net present value
savings. Variable control results in a
$1.1 billion annualized cost savings
which is a savings of $12 billion in net
present value. These changes in utility
costs affect the average residential bill
only slightly, with partial control
resulting in a savings of $.50 per month
and variable control savings of $.40 per
month on the average bill, relative to full
control.
Conclusions
One finding that has been clearly
demonstrated by the two years of
analysis is that lower emission
standards on new plants do not
necessarily result in lower national SO.
emissions when total emissions from the
entire utility system are considered.
There are two reasons for this finding.
First, the lowest emissions tend to result
from strategies that encourage the
construction of new coal capacity. This
capacity, almost regardless of the
alternative analyzed, will be less
polluting than the existing coal- or oil-
fired capacity that it replaces. Second,
the higher cost of operating the new
capacity (due to higher pollution costs)
may cause the newer, cleaner plants to
be utilized less than they would be
under a less stringent alternative. These
situations are demonstrated by the
analyses presented here.
The variable control option produces
emissions that are equal to or lower
than the other options under both the
wet and dry scrubbing assumptions.
Compared to full control, variable
control is predicted to result in 12 GW to
17 GW more coal capacity. This
additional capacity replaces dirtier
existing plants and compensates for the
slight increase in emissions from new
plants subject to the standards, hence
causing emissions to be less than or
equal to full control emissions
depending on scrubbing cost assumption
(i.e., wet or dry). Partial control and
variable control produce about the same
coal capacity, but the additional 300
thousand ton emission reduction from
new plants causes lower total emissions
under {he variable option. Regionally, all
the options produce about the same
emissions in the Midwest and West
South Central regions. Full control
produces 200 thousands tons less
emissions in the West than the variable
option and 300 thousand tons less than
partial control. But the variable and
partial options produce between 200 and
300 thousand tons less emissions in the
East.
The variable and partial control
options have a clear advantage over full
control with respect to costs under both
the wet and dry scrubbing assumptions.
Under the dry assumption, which the
Administrator believes represents the
best prediction of utility behavior,
variable control saves about $1.1 billion
per year relative to full control and
partial control saves an additional $0.3
billion.
All the options have similar impacts
on coal production especially when
considering the large increase predicted
over 1975 production levels. With
respect to oil consumption, however, the
hill control option causes a 200,000
barrel per day increase as compared to
both the partial and variable options.
Based on these analyses, the
Administrator has concluded that a non-
uniform control strategy is best
considering the environmental, energy,
and economic impacts at both national
and regional levels. Compared to other
options analyzed, the variable control
standard presented above achieves the
lowest emissions in an efficient manner
and will not disrupt local or regional
coal markets. Moreover, this option
avoids the 200 thousand barrel per day
oil penalty which has been predicted
under a number of control options. For
these reasons, the Administrator
believes that the variable control option
provides the best balance of national
environmental, energy, and economic
objectives.
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Table 1.—Ai»y Modeling Assumptions
Assumption
Growth rates.
Nuclear capacity -
01 prices <* 1875).
Cod t*roport*l»n.
Coal mnng labor oasts..
Capital charge rate
Cost reporting tin*
FGDcort»_
Coal cleaning ereo*
Bottom ash and fly ash content
1876-1985 4.6%/yr.
1985-1995: 4.0%.
1965 97 GW.
1890 185.
1896 226.
1885 $12.90/bot
1890 $1640.
1985 $21.00.
1% per year real renew.
U M W settlement and 1% real Increase thereafter.
12.5% lor pollution control expenditure*.
1978bo4tars,
No change from phase 2 analysis except for the addition of dry
' acrubbinfl systems tor certain applicalleos.
5%-35% SO, reducaon assumed tor high auMur bituminous coate
only.
No credit assumed.
Tatota 2.—National 1995 SO, Emissions From Utility Boilers •
(Million tons)
Plant category
Level of control*
1975
Current standards
FuH cufiUul
Partial cxmljol
93% minimum
Variable control
70% rnmmun
SffVNSPS Plants'
New Plants'
Ol Plants..
Total National
Emission*—
15.5
7.1
1.0
Dry
15.8
7.0
1.0
Wai
16.0
1.4
Dry
16J
S.1
1.4
15.9
a.e
1J
Dry
16.2
S.4
1.2
Wet Dry
16.0 161
S.3 1.1
14 1.2
18.6
23.7
23.8
20.6
20.7
20.9
20.6
20.5
Total Coal
Capacity (GW) 205
Stodge generated (mWon
tons dry)
552
23
654
27
521
56
520
86
534
43
637
39
533
SO
537
41
•Results of joint EPA/DOE analyses completed in May 1979 based on oi prices of $12.90. $16.40, and t21.0Wbbl in the
years 196$. 1890. and 1995. respectively.
'With 520 ng/J maximum emission kmit
< Plants subject to existing State regulations or the current NSPS of 1.2 fc SCVmHon BTU.
• Based on wet SO, scrubbing costs.
'Baaed on dry SO. scrubbing costs where applicable.
'Plants subject to the revised standards.
Tabte 3.—Regional 1995 SO, Emissions From Utility Boilers •
(Mann tons]
Level of control'
1975
Currant standards
Ful control
Partial ixMAut
33% minimum
Variable control
70% minimum
Total National
Emissions—
MM* Oy4
18,8 23.7 234
*W Oy
20.6 20.7
»W Dry
*0.8 20.9
M Dry
20.6 20.5
Regional Emissions:
East*
West South Central •_
Total Coal
Capacity (GW).._
11.2
....,.,„. 1.1
_ 2.6
1.7
tti
•X3
2.6
1.7
10.1
74
1.7
OJ
10.1
74
1.7
04
8.8
74
14
1.2
•.8
8J)
14
U
8.8
74
14
1.1
8.7
8.0
1.T
1.1
205
552
554
S21
620
634
637
633
537
•Results of joint EPA/DOE analyses completed in May 1979 based on ol prices of $12.90. $16.40. and $21.00/bbl In the
years 1885. *890, and 1895. reapectrvely.
• With 520 ng/J maximum emission fend
' Based on wet SO, scrubbing costs.
' Based on dry SO, scrubbing costs where applicable.
• New England. Middle Atlantic, South Atlantic, and East South CanM Camus Regtona.
'East North Central and West North Central Census Regions.
•West South Central Census Region.
* Mountain and PacMc Census Regtona.
Performance Testing
Paniculate Matter
The final regulations require that
Method 5 or 17 under 40 CFR Part 60,
Appendix A, be used to determine
compliance with the particulate matter
emission limit. Particulate matter may
be collected with Method 5 at an
outstack filter temperature up to 160 C
(320 F); Method 17 may be used when
stack temperatures are less than 160 C
(320 F). Compliance with the opacity
standard in the final regulation is
determined by means of Method 9,
under 40 CFR Part 60. Appendix A. A
transmissometer that meets
Performance Specification 1 under 40
CFR Part 60, Appendix B is required.
Several comments were received
which questioned the accuracy of
Methods 5 and 17 when used to measure
particulate matter at the level of the
standard. The accuracy of Methods 5
and 17 is dependent on the amount of
sample collected and not the
concentration in the gas stream. To
maintain an accuracy comparable to the
accuracy obtained when testing for
mass emission rates higher than the
standard, it is necessary to sample for
longer times. For this reason, the
regulation requires a minimum sampling
time of 120 minutes and a minimum
sampling volume of 1.7 dscm (60 dscf).
Three comments raised the issue of
potential interference of acid mist with
the measurement of particulate matter.
The Administrator recognized this issue
prior to proposal of the regulations. In
the preamble to the proposed
regulations, the Administrator indicated
that investigations would continue to
determine the extent of the problem. A
series of tests at an FGD-equipped
facility burning 3-percent-sulfur coal
indicate that the amount of sample
collected using Method 5 procedures is
temperature sensitive over the range of
filter temperatures used (250° F to 380*
F], with reduced weights at higher
temperatures. Presumably, the
decreased weight at higher filter
temperatures reflect vaporization of acid
mist. Recently received particulate
emission data using Method 5 at 32* F
for a second coal-fired power plant
equipped with an electrostatic
precipitator and an FGD system
apparently conflicts with the data
generated by EPA. For this plant,
particulate matter was measured at 0.02
Ibs/million Btu. It is not known what
portion of this particulate matter, if any
was attributable to sulfuric acid mist.
The intent of the particulate matter
standard is to insure the Installation,
operation, and maintenance of a good
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Table t—Impacts on Fuels In 1995*
Level of control*
1975
•dual
Current standards
full control
Partial control
33% minimum
Variable control
70% minimum
Wet'
Dry-
Dry
Wet
Dry
Wet
Dry
U S Coal Production (million
Ions)
Appalachia
Midwest
Northern Great Plains....
West
Total
Western Coal Snipped East
(mthon tons)
Oil Consumpton by Power
Plants (million bbl/day).
Coal Transportation
396
151
54
46
647
21
489
404
655
230
1 778
122
1 2
02
524
391
630
222
1 767
99
1.2
0.2
463
487
633
182
1 765
59
1 6
02
465
488
628
180
1 761
55
16
02
475
456
622
212
1 765
66
t 4
02
486
452
576
228
1 742
59
14
0.2
470
465
632
203
1 770
71
14
0.2
484
450
602
217
1 752
70
1 4
0.2
Total ....
31
1.4
1.8
1.8
1.6
16
16
1.6
• Results of EPA analyses completed m May 1979 based on OK prices of $12 90, $16.40, and $21.00/bW m the years 1985,
1990, and 1995. respectively
' With 520ng/j maximum emission limit
' Based on wet SO, scrubbing costs
• Based on dry SO, scrubbing where applicable.
Tibte 5.— 1995 Economic Impacts •
(1978 dollars)
Level of control''
Current standards
Wet* Dry1
Average Monthly Residential Bills ($/
month) _ $53 00 $52 85
Indirect Consumer Impacts ($/month) „ -
Incremental Utility Capital Expendi-
tures. Cumulative 1976-1995 ($ bi-
llons)
Incremental Annuahzed Cost (S bil-
lions) ~
Present Value of Incremental Utility
Revenue Requirements ($ Mhons)....
Incremental Cost of SO' Reduction ($/
ton) ,, ,. .
Full control
Wet
$5450
1.50
4
4.1
41
1,322
Dry
$5445
1.60
5
4.4
45
1,428
Partial control
33% minimum
Wet
$54.15
115
6
3.2
32
1,094
Dry
$5395
1 10
-3
3.0
31
1,012
Vanabte control
70% minimum
Wet
$5430
1.30
10
36
37
1.163
Dry
$54.05
1.20
-1
3.3
33
1.036
• Results of EPA analyses completed m May 1979 based on oil prices of $12 90, $16.40, and $21 00/bW n the years 1985,
1990, and 1995, respectively.
' With 520 ng/J maximum emission kmrt.
' Based on wet SO, scrubbing costs.
' Based on dry SO, scrubbing costs where applicable.
emission control system. Since
technology is not available for the
control of sulfuhc acid mist, which is
condensed in the FGD system, the
Administrator does not believe the
particulate matter sample should
include condensed acid mist. The final
regulation, therefore, allows particulate
matter testing for compliance between
the outlet of the particulate matter
control device and the inlet of a wet
FGD system. EPA will continue to
investigate revised procedures to
minimize the measurement of acid mist
by Methods 5 or 17 when used to
measure particulate matter after the
FGD system. Since technology is
available to control particulate sulfate
carryover from an FGD system, and the
Administrator believes good mist
eliminators should be included with all
FGD systems, the regulations will be
amended to require particulate matter
measurement after the FGD system
when revised procedures for Methods !i
or 17 are available.
SO, and NOX
The final regulation requires that
compliance with the sulfur dioxide and
nitrogen oxides standards be
determined by using continuous
monitoring systems (CMS) meeting
Performance Specifications 2 and 3,
under 40 CFR Part 60, Appendix B. Data
from the CMS are used to calculate a 30-
day rolling average emission rate and
percentage reduction (sulfur dioxide
only) for the initial performance test
required under 40 CFR 60.8. At the end
of each boiler operating day after the
initial performance test a new 30-day
rolling average emission rate for sulfur
dioxide and nitrogen oxides and an
average percent reduction for sulfur
dioxide are determined. The final
regulations specify the minimum amount
of data that must be obtained for each
30 successive boiler operating days but
requires the calculation of the average
emission rate and percentage reduction
based on all available data. The
minimum data requirements can be
satisfied by using the Reference
Methods or other approved alternative
methods when the CMS, or components
of the system, are inoperative.
The final regulation requires operation
of the continuous monitors at all times,
including periods of startup, shutdown,
malfunction (NO, only), and emergency
conditions (SO, only), except for those
periods when the CMS is inoperative
because of meilfunctions, calibration or
span checks.
The proposed regulations would have
required that compliance be based on
the emission rate and percent reduction
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(sulfur dioxide only) for each 24-hour
period of operation. Continual
determination of compliance with the
proposed standard would have
necessitated that each source owner or
operator install redundant CMS or
conduct manual testing in the event of
CMS malfunction.
Comments on the proposed testing
requirements for sulfur dioxide and
nitrogen oxides indicated that CMS
could not operate without malfunctions;
therefore, every facility would require
redundant CMS. One commenter
calculated that seven CMS would be
needed to provide the required data.
Comments also •questioned the
practicality and feasibility of obtaining
around-the-clock emissions data by
means of manual testing in the event of
CMS malfunction. The commenter
stated that the need for immediate
backup testing using manual methods
would require a stand-by test team at all
times and that extreme weather
conditions or other circumstances could
often make if impossible for the test
team to obtain the required data. The
Administrator agrees with these
comments and has redefined the data
requirements to reflect the performance
that can be achieved with one well-
maintained CMS. The final requirements
are designed to eliminate the need for
redundant CMS and minimize the
possibility that manual testing will be
necessary, while assuring acquisition of
sufficient data to document compliance.
Compliance with the emission
limitations for sulfur dioxide and
nitrogen oxides and the percentage
reduction for sulfur dioxide is
determined from all available hourly
averages, except for periods of startup,
shutdown, malfunction or emergency
conditions for each 30 successive boiler
operating days. Minimum data
requirements have been established for
hourly averages, for 24-hour periods,
and for the 30 successive boiler
operating days. These minimum
requirements eliminate the need for
redundant CMS and minimize the need
for testing using manual sampling
techniques. The minimum requirements
apply separately to inlet and outlet
monitoring systems.
The regulation allows calculation of
hourly averages for the CMS using two
or more of the required four data points.
This provision was added to
accommodate those monitors for which
span and calibration checks and minor
repairs might require more than 15
minutes.
For any 24-hour period, emissions
data must be obtained for a minimum of
75 percent of the hours during which the
affected facility is operated (including
startup, shutdown, malfunctions or
emergency conditions). This provision
was added to allow additional time for
CMS calibrations and to correct minor
CMS problems, such as a lamp failure, a
plugged probe, or a soiled lens.
Statistical analyses of data obtained by
EPA show that there is no significant
difference (at the 95 percent confidence
interval) between 24-hour means based
on 75 percent of the data and those
based on the full data set.
To provide time to correct major CMS
malfunctions and minimize the
possibility that supplemental testing will
be needed, a provision has been added
which allows the source owner or
operator to demonstrate compliance if
the minimum data for each 24-hour
period has been obtained for 22 of tbe 30
successive boiler operating days. This
provision is based on EPA studies that
have shown that a single pair of CMS
pollutant and diluent monitors can be
made available in excess of 75 percent
of the time and several comments
showing CMS availability in excess of
90 percent of the time.
In the event a CMS malfunction would
prevent the source owner or operator
from meeting the minimum data
requirements, the regulation requires
that the reference methods or other
procedures approved by the
Administrator be used to supplement
the data. The Administrator believes,
however, that a single properly
designed, maintained, and operated
CMS with trained personnel and an
appropriate inventory of spare parts can
achieve the monitoring requirements
with currently available CMS
equipment. In the event that an owner or
operator fails to meet the minimum data
requirements, a procedure is provided
which may be used by the
Administrator to determine compliance
with the SO, and NO, standards. The
procedure is provided to reduce
potential problems that might arise if an
owner or operation is unable to meet the
minimum data requirements or attempts
to manipulate the acquisition of data so
as to avoid the demonstration of
noncompliance. The Administrator
believes that an owner or operator
should not be able to avoid a finding of
noncompliance with the emission
standards solely by noncompliance with
the minimum data requirements.
Penalties related only to failure to meet
the minimum data requirements may be
less than those for failure to meet the
emission standards and may not provide
as great an incentive to maintain
compliance with the regulations.
The procedure involves the
calculation of standard deviations for
the available inlet SOZ monitoring data
and the available outlet SO2 and NO,
monitoring data and assumes the data
are normally distributed. The standard
deviation of the inlet monitoring data for
SOj is used to calculate the upper
confidence limit of the inlet emission
rate at the 95 percent confidence
interval. The upper confidence limit of
the inlet emission rate is used to
determine the potential combustion
concentration and the allowable
emission rate. The standard deviation of
the outlet monitoring data for SO2 and
NO, are used to calculate the lower
confidence limit of the outlet emission
rates at the 95 percent confidence
interval. The lower confidence limit of
the outlet emission rate is compared
with the allowable emission rate to
determine compliance. If the lower
confidence limit of the outlet emission
rate is greater than the allowable
emission rate for the reporting period,
the Administrator will conclude that
noncompliance has occurred.
The regulations require the source
owner or operator who fails to meet the
minimum data requirements to perform
the calculations required by the added
procedure, and to report the results of
the calculations in the quarterly report.
The Administrator may use this
information for determining the
compliance status of the affected
facility.
It is emphasized that while the
regulations permit a determination of
the compliance status of a facility in the
absence of data reflecting some periods
of operation, an owner and operator is
required by 40 CFR 60.11(d) to continue
to operate the facility at all times so as
to minimize emissions consistent with
good engineering practice. Also, the
added procedure which allows for a
determination of compliance when less
than the minimum monitoring data have
been obtained does not exempt the
source owner or operator from the
minimum data requirements. Exemption
from the minimum data requirements
could allow the source owner to
circumvent the standard, since the
added procedure assumes random
variations in emission rates.
One commenter suggested that
operating data be used in place of CMS
data to demonstrate compliance. The
Administrator does not believe,
however, that the demonstration of
compliance can be based on operating
data alone. Consideration was given to
the reporting of operating parameters
during those periods when emissions
data have not been obtained. This
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alternative was rejected because it
would mean that the source owner or
operator would need to record the
operating parameters at all times, and
would impose an administrative burden
on source owners or operators in
compliance with the emission
monitoring requirements. The regulation
requires the owner or operator to certify
that the emission control systems have
been kept in operation during periods
when emissions data have not been
obtained.
Several commenters indicated that
CMS were not sufficiently accurate to
allow for a determination of compliance.
One commenter provided calculations
showing that the CMS could report an
FGD efficiency ranging from 77.5 to 90
percent, with the scrubber operating at
an efficiency of 85 percent The analysis
submitted by the commenler is
theoretically possible for any single data
point generated by the CMS. For the 30-
day averaging periods, however, random
variations in individual data points are
not significant. The criterion of
importance in showing compliance for
this longer averaging time is the
difference between the mean values
measured by the CMS and the reference
methods. EPA is developing quality
assurance procedures, which will
require a periodic demonstration that
the mean emission rates measured by
the CMS demonstrates a consistent and
reproducible relationship with the mean
emission rates measured by the
reference methods or acceptable
modifications of these methods.
A specific comment received on the
monitoring requirements questioned the
need to respan the CMS for sulfur
dioxide when the sulfur content of the
fuel changed by 0.5 percent The intent
of this requirement was to assure that a
change in fuel sulfur content would not
result in emissions exceeding the range
of the CMS. This requirement has been
deleted on the premise that the source
owner or operator will initiate his own
procedures to protect himself against
loss of data.
Several comments were also received
concerning detailed technical items
contained in Performance Specifications
2 and 3. One comment, for example,
suggested that a single "relative
accuracy" specification be used for the
entire CMS, as opposed to separate
values for the pollutant and diluent
monitors. Another comment questioned
the performance specification on
instrument response time, while still
other comments raised questions on
calibration procedures. EPA is in the
process of revising Performance
Specifications 2 and 3 to respond to
these, and other questions. The current
performance specifications, however,
are adequate for the determination of
compliance.
Fuel Pretreatment
The final regulation allows credit Cor
fuel pretreatment to remove sulfur or
increase heat content. Fuel pretreatment
credits are determined in accordance
with Method 19. This means that coal or
oil may be treated before firing and the
sulfur removed may be credited toward
meeting the SO, percentage reduction
requirement The final fuel pretreatment
provisions are the same as those
proposed.
Most all ooxmnenters on this issue
supported the fuel pretreatment
crediting procedure* proposed by EPA.
Several commenters requested that
credit also be given for sulfur removed
in the coal bottom ash and fly ash. This
is allowed under the final regulation and
was also allowed under the proposal in
the optional "as-fired" fuel sampling
procedures under the SO* emission
monitoring requirements. By monitoring
SOi emissions (ng/J, lb/million Btu) with
an as-fired fuel sampling system located
upstream of coal pulverizers and with
an in-stack continuous SO* monitoring
system downstream of the FGD system,
sulfur removal credits are combined for
the coal pulverizer, bottom ash. fly a&h
and FGD system into one removal
efficiency. Other alternative sampling
procedures may also be submitted to the
Administrator for approval.
Several commenters indicated that
they did not understand the proposed
fuel pretreatment crediting procedure for
refined fuel oil. The Administrator
intended to allow fuel pretreatment
credits for all fuel oil desulfurizau'on
processes used in preparation of utility
boiler fuels. Thus, the input and output
from oil desulfurization processes {e.g.,
hydrotreatment units) that are used to
pretreat utility boiler fuels used in
determining pretreatment credits. If
desulfurized oil is blended with
undesulfurized oil, fuel pretreatment
credits are prorated based on heat input
of oils blended. The Administrator
believes that the oil input to the
desulfurizer should be considered the
input for credit determination and not
the well head crude oil or input oil to the
refinery. Refining of crude oil results in
the separation of the base stock into
various density fractions which range
from lighter products such as naphtha
and distillate oils. Most of the sulfur
from the crude oil is bound to the
heavier residual oils which may have a
sulfur content of twice the input crude
oil. The residual oils can be upgraded to
a lower sulfur utility steam generator
fuel through th« use of desulfurization
technology {scrch as
hydrodesulfurization). The
Administrator believes that it is
appropriate to give full fuel pretreatment
credit for hydrotreatment units and not
to penalize hydrodesulfurization units
which are used to process high-sulfur
residual oils. Thus, the input to the
hydrodesulfurizarion unit is treed to
determine oil pretreatment credits and
not the lower sulfur refinery input crude.
This procedure will allow full credit for
residual oil hydrodesulfurization units.
In relation to fuel pretreatment credits
for coal, commenters requested that
sampling be allowed prior to the 'initial
coal breaker. Under the final standards,
coal sampling may be conducted at any
location (either before or after the initial
coal breaker). It is desirable to sample
coal after the initial breaker because the
smaller coal volume and coal size will
reduce sampling requirements under
Method 19. If sampling were conducted
before the initial breaker, rock removed
by the coal breaker would not result in
any additional sulfur removal credit
Coal samples are analyzed to determine
potential SO. emissions in ng/J (lb/
million Btu) and any removal of rock or
other similar reject material will not
change the potential SO» emission rate
(ng/j; Ib/million Btu).
An owner or operator of an affected
facility who elects to use fuel
pretreatment credits is responsible for
insuring that the EPA Method 19
procedures are followed in determining
SOa removal credit for pretreatment
equipment.
Miscellaneous
Establishment of standards of
performance for electric utility steam
generating units was preceded by the
Administrator's determination that these
sources contribute significantly to air
pollution which causes or contributes to
the endangerment of public health or
welfare (36 FR 5931), and by proposal of
regulations on September 19,1978 (43 FR
42154). In addition, a preproposal public
hearing (May 25-26,1977) and a
postproposal public hearing (December
12-13,1978) was held after notification
was given in the Federal Register. Under
section 117 of the Act, publication of
these regulations was preceded by
consultation with appropriate advisory
committees, independent experts, and
Federal departments and agencies.
Standards of performance for new
fossil-fuel-fired stationary sources
established under section 111 of the
Clean Air Act reflect:
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Application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, [section lll(a)(l)]
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
s more stringent emission standard in
several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources located in
nonattainment areas, i.e., those areas
where statutorily-mandated health and
welfare standards are being violated. In
this respect, section 173 of the Act
requires that a new or modified source
constructed in an area that exceeds the
National Ambient Air Quality Standard
(NAAQS) must reduce emissions to the
level that reflects the "lowest
achievable emission rate" (LAER), as
defined in section 171(3), for such source
category. The statute defines LAER as
that rate of emission which reflects:
(A) 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
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source,
whichever is more stringent.
In no event can the emission rate
exceed any applicable new source
performance standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" [as defined in
section 169(3)] for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless the Administrator takes
affirmative action to extend them.
Within the five year period, the
Administrator will review these
requirements.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for
revisions determined by the
Administrator to be substantial. The
Administrator has determined that these
revisions are substantial and has
prepared an economic impact
assessment and included the required
information in the background
information documents.
Dated: June 1,1979.
Douglas M. Costle,
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
In 40 CFR Part 60, § 60.8 of Subpart A
is revised, the heading and § 60.40 of
Subpart D are revised, a new Subpart
Da is added, and a new reference
method is added to Appendix A as
follows:
1. Section 60.8{d) and § 60.8{f) are
revised as follows:
{60.8 Performance tests.
(d) The owner or operator of an
affected facility shall provide the
Administrator at least 30 days prior
notice of any performance test, except
as specified under other subparts, to
afford the Administrator the opportunity
to have an observer present.
*****
(f) Unless otherwise specified in the
applicable subpart, each pt.formance
test shall consist of three separate runs
using the applicable test method. Each
run shall be conducted for the time and
under the conditions specified in the
applicable standard. For the purpose of
determining compliance with an
applicable standard, the arithmetic
means of results of the three runs shall
apply. In the event that a sample is
accidentally lost or conditions occur in
which one of the three runs must be
discontinued because of forced
shutdown, failure of an irreplaceable
portion of the sample train, extreme
meteorological conditions, or other
circumstances, beyond the owner or
operator's control, compliance may,
upon the Administrator's approval, be
determined using the arithmetic mean of
the results of the two other runs.
2. The heading for Subpart D is
revised to read as follows:
Subpart D—Standards of Performance
for Fossil-Fuel-Fired Steam Generators
for Which Construction Is Commenced
After August 17,1971
3. Section 60.40 is amended by adding
paragraph (d) as follows:
§60.40 AppttcaWHty and designation of
affected facility.
*****
(d) Any facility covered under Subpart
Da is not covered under This Subpart.
(Sec. Ill, 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601(a)).J
4. A new Subpart Da is added as
follows:
Subpart Da—Standards of Performance for
Electric Utility Steam Generating Units for
Which Construction Is Commenced After
September 18,1978
Sec.
60.40a Applicability and designation of
affected facility.
60.41a Definitions.
60.42a Standard for particulate matter.
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogen oxides.
60.45a Commercial demonstration permit.
60.48a Compliance provisions.
60.47a Emission monitoring.
60.48a Compliance determination
procedures and methods.
60.49a Reporting requirements.
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Authority: Sec. 111. 9m(a) of Hie CSem Air
Act a* amended (42 U.S.C. 7411,7601(a)), and
additional authority M moled below.
Subpart Da—Standards of
Performance for Electric Utility Steam
Generating Units for Which
Construction Is Commenced After
September W, 1878
f 60.40a Appflcabfltty and designation of
affected facility.
(a) The affected facility to which this
subpart applies is each electric utility
steam generating unit:
(1) That is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat input of fossil fuel (either
alone or in combination with any other
fuel); and
(2) For which construction or
modification is commenced after
September 18,1978.
[bj This subpart applies to electric
utility combined cycle gas turbines that
are capable of combusting more than 73
megawatt* (250 million Btu/hour) heat
input of fossil fuel in the steam
generator. Only emissions resulting from
combustion of fuels in the steam
generating unit are subject to this
subpart. (The gas turbine emissions are
subject to Subpart GG.)
(c) Any change to an existing fossil-
fuel-fired steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels, shall
not bring that unit under the
applicability of this subparL
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to
accommodate the use of any other fuel
(fossil or nonfossil) shall not bring that
unit under the applicability of this
subpart.
f6O41a Definition*.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
"Steam generating unit" means any
furnace, boiler, or other device nsed for
combusting fuel for the purpose of
producing steam (including fossil-fuel-
fired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included].
"Electric utility steam generating unit"
means any steam electric generating
unit that is constructed for the purpose
of supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam supplied to a steam
distribution system for the purpose of
providing steam to a steam-electric
generator that would produce electrical
energy for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from each
material for the purpose of creating
useful heat.
"Sabbiruminoos coal" means coal that
is classified as subbitaminoos A, B, or C
according to the American Society of
Testing and Materials' (ASTM)
Standard Specification for Classification
of Coals by Rank 0368-66.
"Lignite" means coal that is classified
as lignite A or B according to the
American Society of Testing and
Material*' (ASTM] Standard
Specification for Classification of Coals
by Rank 0388-06.
"Coal refuse" means waste products
of coal mining, physical coal cleaning,
and coal preparation operations (e.g.
culm, gob, etc.) containing coal, matrix
material, clay, and other organic and
inorganic material.
"Potential combustion concentration"
means the theoretical emissions (ng/J,
Ib/million Btu heat input) that would
result from combustion of a fuel in an
uncieaned state Owithout emission
control systems) and:
(a) For particulate matter is:
(1) 3,000 ng/J (7.0 ib/million Btu) beat
input for solid fuel; and
(2) 75 ng/J (0.17 Ib/millionBtu) heat
input for liquid fuels.
(b) For sulfur dioxide is determined
under § 60.48a(b).
(c) For nitrogen oxides is:
(1) 290 ng/J (0.67 Ib/million Btu) heat
input for gaseous fuels;
(2) 310 ng/J (0.72 Ib/million Btu) heat
input for liquid fuels; and
(3) 990 ng/J (2.30 Ib/million Btu) heat
input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion system
where heat from the turbine exhaust
gases is recovered fay a steam
generating unit
"Interconnected" means that two or
more electric generating units are
electrically tied together by a network of
power transmission lines, and other
power transmission equipment
"Electric utility company" means the
largest interconnected organization,
business, or governmental entity that
generates electric power for sale (e.g., a
holding company with operating
subsidiary companies).
"Principal company" means the
electric utility company or companies
which own the affected facility.
"Neighboring company" means any
one of those electric utility companies
with one or more electric power
interconnections to the principal
company and which have
geographically adjoining service areas.
"Net system capacity" means the sum
of the net electric generating capability
(not necessarily equal to rated capacity)
of all electric generating equipment
owned by an electric utility company
(including steam generating units,
internal combustion engines, gas
turbines, rmciear units, hydroelectric
units, and all other electric generating
equipment) pins firm contractual
purchases that are interconnected to the
affected facility that has the
malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established fay contractual
arrangement
"System load" means the entire
electric demand of an electric utility
company's service area interconnected
•with the affected facility that has the
malfunctioning flue gas desulfurization
system phis firm contractual sales to
other electric utility companies. Sales to
other electric utility companies (ag.,
emergency power) not on a firm
contractual basis may also be included
in the system load when no available
system capacity exists in the electric
utility company to which the power is
supplied for sale.
"System emergency reserves" means
an amount of electric generating
capacity equivalent to the rated
capacity of the single largest electric
generating unit in the electric utility
company (including steam generating
units, internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which is interconnected with
the affected facility that has the
Malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available system capacity" means
the capacity determined by subtracting
the system load and the system
emergency reserves from the net system
capacity.
"Spinning reserve" means the sum of
the unutilized net generating capability
of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of immediately accepting
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additional load. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available purchase power" means
the lesser of the following:
(a) The sum of available system
capacity in all neighboring companies.
(b) The sum of the rated capacities of
the power interconnection devices
between the principal company and all
neighboring companies, minus the sum
of the electric power load on these
interconnections.
(c) The rated capacity, of the power
transmission lines between the power
interconnection devices and the electric
generating units (the unit in the principal
company that has the malfunctioning
flue gas desulfurization system and the
unit(s) in the neighboring company
supplying replacement electrical power)
less the electric power load on these
transmission lines.
"Spare flue gas desulfurization system
module" means a separate system of
sulfur dioxide emission control
equipment capable of treating an /
amount of flue gas equal to the total
amount of flue gas generated by an
affected facility when operated at
maximum capacity divided by the total
number of nonspare flue gas
desulfurization modules in the system.
"Emergency condition" means that
period of time when:
(a) The electric generation output of
an affected facility with a
malfunctioning flue gas desulfurization
system cannot be reduced or electrical
output must be increased because:
(1) All available system capacity in
the principal company interconnected
with the affected facility is being
operated, and
(2) All available purchase power
interconnected with the affected facility
is being obtained, or
(b) The electric generation demand is
being shifted as quickly as possible from
an affected facility with a
malfunctioning flue gas desulfurization
system to one or more electrical
generating units held in reserve by the
principal company or by a neighboring
company, or
{c) An affected facility with a
malfunctioning flue gas desulfurization
system becomes the only available unit
to maintain a part or all of the principal
company's system emergency reserves
and the unit is operated in spinning
reserve at the lowest practical electric
generation load consistent with not
causing significant physical damage to
the unit. If the unit is operated at a
higher load to meet load demand, an
emergency condition would not exist
unless the conditions under (a) of this
definition apply.
"Electric utility combined cycle gas
turbine" means any combined cycle gas
turbine used for electric generation that
is constructed for the purpose of
supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam distribution system that
is constructed for the purpose of
providing steam to a steam electric
generator that would produce electrical
power for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Potential electrical output capacity"
is defined as 33 percent of the maximum
design heat input capacity of the steam
generating unit (e.g., a steam generating
unit with a 100-MW (340 million Btu/hr)
fossil-fuel heat input capacity would
have a 33-MW potential electrical
output capacity). For electric utility
combined cycle gas turbines the
potential electrical output capacity is
determined on the basis of the fossil-fuel
firing capacity of the steam generator
exclusive of the heat input and electrical
power contribution by the gas turbine.
"Anthracite" means coal that is
classified as anthracite according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-66.
"Solid-derived fuel" means any solid,
liquid, or gaseous fuel derived from solid
fuel for the purpose of creating useful
heat and includes, but is not limited to,
solvent refined coal, liquified coal, and
gasified coal.
"24-hour period" means the period of
time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a
facility that combusts more than 75
percent non-fossil fuel on a quarterly
(calendar) heat input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit for
the entire 24 hours.
§ 60.42a Standard for participate matter.
(a) On and after the date on which the
performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases which
contain particulate matter in excess of:
(1) 13 ng/J (0.03 Ib/million Btu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel;
(2) 1 percent of the potential
combustion concentration (99 percent
reduction) when combusting solid fuel;
and
(3) 30 percent of potential combustion
concentration (70 percent reduction)
when combusting liquid fuej.
(b) On and after the date the
particulate matter performance test
required to be conducted under § 60.8 is
completed, no owner or operator subject
to the provisions of this subpart shall
cause to be discharged into the
atmosphere from any affected facility
any gases which exhibit greater than 20
percent opacity (6-minute average),
except for one 6-minute period per hour
of not more than 27 percent opacity.
§ 60.43a Standard for sulfur dioxide.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid fuel or solid-derived fuel, except as
provided under paragraphs (c), (d), (f) or
(h) of this section, any gases which
contain sulfur dioxide in excess of:
(1) 520 ng/J (1.20 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 30 percent of the potential
combustion concentration (70 percent
reduction), when emissions are less than
260 ng/J (0.60 Ib/million Btu) heat input.
(b) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
liquid or gaseous fuels (except for liquid
or gaseous fuels derived from solid fuels
and as provided under paragraphs (e) or
(h) of this section), any gases which
contain sulfur dioxide in excess of:
(1) 340 ng/J (0.80 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 100 percent of the potential
combustion concentration (zero percent
reduction) when emissions are less than
86 ng/J (0.20 Ib/million Btu) heat input.
(c) On and after the date on which the
initial performance test required to be
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conducted under § 60.8 is complete, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid solvent refined coal (SRC-I) any
gases which contain sulfur dioxide in
excess of 520 ng/J (1.20 Ib/million Btu)
heat input and 15 percent of the
potential combustion concentration (85
percent reduction) except as provided
under paragraph (f) of this section;
compliance with the emission limitation
is determined on a 30-day rolling
average basis and compliance with the
percent reduction requirement is
determined on a 24-hour basis.
(d) Sulfur dioxide emissions are
limited to 520 ng/J (1.20 Ib/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recovery
facility, or
(3) Is located in a noncontinental area
and combusts solid fuel or solid-derived
fuel.
(e) Sulfur dixoide emissions are
limited to 340 ng/J (0.80 Ib/million Btu)
heat input from any affected facility
which is located in a noncontinental
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction
requirements under this section do not
apply to any affected facility that is
operated under an SO, commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(g) Compliance with the emission
limitation and percent reduction
requirements under this section are both
determined on a 30-day rolling average
basis except as provided under
paragraph (c) of this section.
(h) When different fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
(1) If emissions of sulfur dioxide to the
atmosphere are greater than 260 ng/J
(0.60 Ib/million Btu) heat input
En, = (340 x + 520 y]/100 and
PIO, — 10 percent
(2) It emissions of sulfur dioxide to the
atmosphere are equal to or less than 260
ng/J (0.60 Ib/million Btu) heat input:
Ego, = (340 x -f 520 y]/100 and
Pso, =(90x + 70y]/100
where:
Ego, is the prorated sulfur dioxide emission
limit (ng/J heat input),
PIO, is the percentage of potential sulfur
dioxide emission allowed (percent
reduction required — 100—PIO,],
x is the percentage of total heat input derived
from the combustion of liquid or gaseous
fuels (excluding solid-derived fuels)
y is the percentage of total heat input derived
from the combustion of solid fuel
(including solid-derived fuels)
{ 60.44a Standard for nitrogen oxides.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility, except as provided
under paragraph (b) of this section, any
gases which contain nitrogen oxides in
excess of the following emission limits,
based on a 30-day rolling average.
(1) NO, Emission Limits—
Fuel type
Gaseous Fuels:
Coal-denved fuels
All other fuels
liquid Fuels
Coal-derived fuel*
Shale oil „„,.
AH other fuel*..
SoMFuete:
Coal-dertved fuels
Any fuel containing more than
25%, by weight, coal refuse .
Any fuel containing more than
25%, by weight (grata If the
Agrafe n mined in North
Dakota, South Dakota, or
Montana, and * combusted
In a slag tap furnace .._ _
Ugrate not subject to the 340
ng/J heat input emission Hmtt
Subbrtummous coal
BftummoMS COftl ,,„„,
Anthracite coal..... ,,
All other fuels
Emission fentt
ng/J (Ib/mlhon Btu)
heat Input
210 $.50)
66 (0.20)
210 (0.50)
210 J0.50)
130 (0.30)
210 (0.50)
Exempt from NO?
standards and NO,
monitoring
requirement*
340 (0.80)
260 (060)
210 (0.50)
260 (0.60)
860 (060)
260 (0.60)
(2) NOX reduction requirements
Fuel type
Percent reduction
of potential
combustion
concentration
Gaseous fuels....
liquid fuels..
Solid fuels....
25%
30%
65%
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which is
combusting coal-derived liquid fuel and
is operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(c) When two or more fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
*(86 w+130 x+210 y+260 zj/100
where;
ENO, '» the applicable standard for nitrogen
oxides when multiple fuels are
combusted simultaneously (ng/J heat
input);
w is the percentage of total heat input
derived from the combustion of fuels
subject to the 86 ng/J heat input
standard;
x is the percentage of total heat input derived
from the combustion of fuels subject to
the 130 ng/J heat input standard;
y is the percentage of total heat input derived
from the combustion of fuels subject to
the 210 ng/J heat input standard; and
2 is the percentage of total heat input derived
from the combustion of fuels subject to
tie 260 ngf] heat input standard.
i 60.45a Commercial demonstration
permit
(a) An owner or operator of an
affected facility proposing to
demonstrate an emerging technology
may apply to the Administrator for a
commercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance
with paragraph (e) of this section.
Commercial demonstration permits may
be isfiued only by the Administrator,
and this authority will not be delegated.
(b) An owner or operator of an
affected facility that combusts solid
solvent refined coal (SRC-I) and who is
issued a commercial demonstration
permit by the Administrator is not
subject to the SOj emission reduction
requirements under § 60.43a(c) but must,
as a minimum, reduce SO, emissions to
20 percent of the potential combustion
concentration (80 percent reduction) for
each 24-hour period of steam generator
operation and to less than 520 ng/J (1.20
Ib/million Btu) heat input on a 30-day
rolling average basis.
(c) An owner or operator of a fluidized
bed combustion electric utility steam
generator (atmospheric or pressurized)
who is issued a commercial
demonstration permit by the
Administrator is not subject to the SO»
emission reduction requirements under
§ 60.43a(a) but must, as a minimum,
reduce SOa emissions to 15 percent of
the potential combustion concentration
(85 percent reduction) on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/million Btu) heat input
on a 30-day rolling average basis.
(d) The owner or operator of an
affected facility that combusts coal-
derived liquid fuel and who is issued a
commercial demonstration permit by the
Administrator is not subject to the
applicable NO, emission limitation and
percent reduction under § 60.44a(a) but
must, as a minimum, reduce emissions
to less than 300 ng/J (0.70 Ib/million Btu)
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heat input on a 30-day rolling average
basis.
(e) Commercial demonstration permits
may not exceed the following equivalent
MW electrical generation capacity for
any one technology category, and the
.total equivalent MW electrical
generation capacity for all commercial
demonstration plants may not exceed
15.000 MW.
Technology
Equhwtenl
•Metrical
Pohitar* capacity
(MWrtectncal
output)
Solid toKwnt noned coal
(SHC !)..._ ........ _ ............
FUfzed tod contwstion
SO, 6,000-10,000
SO. 400-3400
FludRed bed combustion
(pfesjwrized) .......... .... ......
so,
NO,
Total afcMabto tor el
400-1.200
750-10,000
15.000
|W.46a Compliance provision*.
(a) Compliance with the particulate
matter emission limitation under
| 60.42a(a)(l) constitutes compliance
with the percent reduction requirements
for particulate matter under
§ 60.42a(a)[2) and (3).
(b) Compliance with the nitrogen
oxides emission limitation under
S 60.44a(a) constitutes compliance with
the percent reduction requirements
under $ 60.44a(a){2).
(c) The particulate matter emission
standards under 160.42a and the
nitrogen oxides emission standards
under § 60.44a apply at all times except
during periods of startup, shutdown, or
malfunction. The sulfur dioxide emission
standards under { 60.43a apply at all
times except during periods of startup,
shutdown, or when both emergency
conditions exist and the procedures
under paragraph (d) of this section are
implemented.
(d) During emergency conditions in
the principal company, an affected
facility with a malfunctioning flue gas
desulfurization system may be operated
if sulfur dioxide emissions are
minimized by:
(1) Operating all operable flue gas
desulfurization system modules, and
bringing back into operation any
malfunctioned module as soon as
repairs are completed,
(2) Bypassing flue gases around only
those flue gas desulfurization system
modules that have been taken out of
operation because they were incapable
of any sulfur dioxide emission reduction
or which would have suffered significant
physical damage if they had remained in
operation, and
(3) Designing, constructing, and
operating a spare flue gas
desulfurization system module for an
affected facility larger than 365 MW
(1,250 million Btu/hr) heat input
(approximately 125 MW electrical
output capacity). The Administrator
may at his discretion require the owner
or operator within 80 days of
notification to demonstrate spare
module capability. To demonstrate this
capability, the owner or operator must
demonstrate compliance with the
appropriate requirements under
paragraph (a), (b), (d), (e), and (i) under
} 60.43a for any period of operation
lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization
module is not operated,
(ii) The affected facility is operating at
the maximum heat input rate,
(iii) The fuel fired during the 24-hour
to 30-day period is representative of the
type and average sulfur content of fuel
used over a typical 30-day period, and
(iv) The owner or operator has given
the Administrator at least 30 days notice
of the date and period of time over
which the demonstration will be
performed.
(e) After the initial performance test
required under § 60.8, compliance with
the sulfur dioxide emission limitations
and percentage reduction requirements
under § 60.43a and the nitrogen oxides
emission limitations under § 60.44a is
based on the average emission rate for
30 successive boiler operating days. A
separate performance test is completed
at the end of each boiler operating day
after the initial performance test, and a
new 30 day average emission rate for
both sulfur dioxide and nitrogen oxides
and a new percent reduction for sulfur
dioxide are calculated to show
compliance with the standards.
(f) For the initial performance test
required under $ 60.8, compliance with
the sulfur dioxide emission limitations
and percent reduction requirements
under $ 60.43a and the nitrogen oxides
emission limitation under S 60.44a is
based on the average emission rates for
sulfur dioxide, nitrogen oxides, and
percent reduction for sulfur dioxide for
the first 30 successive boiler operating
days. The initial performance test is the
only test in which at least 30 days prior
notice is required unless otherwise
specified by the Administrator. The
initial performance test is to be
scheduled so that the first boiler
operating day of the 30 successive boiler
operating days is completed within 60
days after achieving the maximum
production rate at which the affected
facility will be operated, but not later
than 180 days after initial startup of the
facility.
(g) Compliance is determined by
calculating the arithmetic average of all
hourly emission rates for SO* and NO,
for the 30 successive boiler operating
days, except for data obtained during
startup, shutdown, malfunction (NO,
only), or emergency conditions (SO»
only). Compliance with the percentage
reduction requirement for SO, is
determined based on the average inlet
and average outlet SO, emission rates
for the 30 successive boiler operating
days.
(h) If an owner or operator has not
obtained the minimum quantity of
emission data as required under § 60.47a
.of this subpart, compliance of the
affected facility with the emission
requirements under $ $ 60.43a and 60.44a
of this subpart for the day on which the
30-day period ends may be determined
by the Administrator by following the
applicable procedures in sections 6.0
and 7.0 of Reference Method 19
(Appendix A).
}60.47« Enrisskm monitoring.
(a) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
opacity of emissions discharged to the
atmosphere, except where gaseous fuel
is the only fuel combusted. If opacity
interference due to water droplets exists
in the stack (for example, from the use
of an FGD system), the opacity is
monitored upstream of the interference
(at the inlet to the FGD system). If
opacity interference is experienced at
all locations (both at the inlet and outlet
of the sulfur dioxide control system),
alternate parameters indicative of the
particulate matter control system's
performance are monitored (subject to
the approval of the Administrator).
(b) The owner or operator of an
affected facility shall install calibrate.
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
sulfur dioxide emissions, except where
natural gas is the only fuel combusted.
as follows:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet of
the sulfur dioxide control device.
(2) For e facility which qualifies under
the provisions of { 60.43a(d), sulfur
dioxide emissions are only monitored ••
discharged to the atmosphere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeting the requirement* of Method 19
(Appendix A) may be used to determine
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potential sulfur dioxide emissions in
place of a continuous sulfur dioxide
emission monitor at the inlet to the
sulfur dioxide control device as required
under paragraph (b)(l) of this section.
(c) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged to
the atmosphere.
(d) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
oxygen or carbon dioxide content of the
flue gases at each location where sulfur
dioxide or nitrogen oxides emissions are
monitored.
(e) The continuous monitoring
systems under paragraphs (b), (c), and
(d) of this section are operated and data
recorded during all periods of operation
of the affected facility including periods
of startup, shutdown, malfunction or
emergency conditions, except for
continuous monitoring system
breakdowns, repairs, calibration checks,
and zero and span adjustments.
(f) When emission data are not
obtained because of continuous
monitoring system breakdowns, repairs,
calibration checks and zero and span
adjustments, emission data will be
obtained by using other monitoring
systems as approved by the
Administrator or the reference methods
as described in paragraph (h) of this
section to provide emission data for a
minimum of 18 hours in at least 22 out of
30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph § 60.13(h) are
expressed in ng/J (Ibs/million Btu) heat
input and used to calculate the average
emission rates under § 60.46a. The 1-
hour averages are calculated using the
data points required under § 60.13(b). At
least two data points must be used to
calculate the 1-hour averages.
(h) Reference methods used to
supplement continuous monitoring
system data to meet the minimum data
requirements in paragraph § 60.47a(f)
will be used as specified below or
otherwise approved by the
Administrator.
(1) Reference Methods 3,6, and 7, as
applicable, are used. The sampling
location(s) are the same as those used
for the continuous monitoring system.
(2) For Method 6, the minimum
sampling time is 20 minutes and the
minimum sampling volume is 0.02 dscm
(0.71 dscf) for each sample. Samples are
taken at approximately 60-minute
intervals. Each sample represents a 1-
hour average.
(3) For Method 7, samples are taken at
approximately 30-minute intervals. The
arithmetic average of these two
consective samples represent a 1-hour
average.
(4) For Method 3, the oxygen or
carbon dioxide sample is to be taken for
each hour when continuous SOj and
NO, data are taken or when Methods 6
and 7 are required. Each sample shall be
taken for a minimum of 30 minutes in
each hour using the integrated bag
method specified in Method 3. Each
sample represents a 1-hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J (Ib/million
Btu) heat input are determined and used
as needed to achieve the minimum data
requirements of paragraph (f) of this
section.
(i) The following procedures are used
to conduct monitoring system
performance evaluations under
§ 60.13(c) and calibration checks under
§ 60.13(d).
(1) Reference method 6 or 7, as
applicable, is used for conducting
performance evaluations of sulfur
dioxide and nitrogen oxides continuous
monitoring systems.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under
performance specification 2 of appendix
B to this part.
(3) For affected facilities burning only
fossil fuel, the span value for a
continuous monitoring system for
measuring opacity is between 60 and 80
percent and for a continuous monitoring
system measuring nitrogen oxides is
determined as follows:
Fostffuel
Span value for
nitrogen oxides (ppm)
Gas
Uqud _,
SoM
Combination..
500
500
1,000
500 (x+y)+1.000Z
where:
x is the fraction of total heat input derived
from gaseous fossil fuel,
y is the fraction of total heat input derived
from liquid fossil fuel, and
z is the fraction of total heat input derived
from solid fossil fuel.
(4) All span values computed under
paragraph (b)(3) of this section for
burning combinations of fossil fuels are
rounded to the nearest 500 ppm.
(5) For affected facilities burning fossil
fuel, alone or in combination with non-
fossil fuel, the span value of the sulfur
dioxide continuous monitoring system at
the inlet to the sulfur dioxide control
device is 125 percent of the maximum
estimated hourly potential emissions of
the fuel fired, and the outlet of the sulfur
dioxide control device is 50 percent of
maximum estimated hourly potential
emissions of the fuel fired.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
§ 60.48a Compliance determination
procedures and methods.
(a) The following procedures and
reference methods are used to determine
compliance with the standards for
particulate matter under § 60.42a.
(1) Method 3 is used for gas analysis
when applying method 5 or method 17.
(2) Method 5 is used for determining
particulate matter emissions and
associated moisture content. Method 17
may be used for stack gas temperatures
less than 160 C (320 F).
(3) For Methods 5 or 17, Method 1 is
used to select the sampling site and the
number of traverse sampling points. The
sampling time for each run is at least 120
minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except thai
smaller sampling times or volumes,
when necessitated by process variables
or other factors, may be approved by the
Administrator.
(4) For Method 5, the probe and filter
holder heating system in the sampling
train is set to provide a gas temperature
no greater than 160°C (32°F).
(5) For determination of particulate
emissions, the oxygen or carbon-dioxide
sample is obtained simultaneously with
each run of Methods 5 or 17 by
traversing the duct at the same sampling
location. Method 1 is used for selection
of the number of traverse points except
that no more than 12 sample joints are
required.
(6) For each run using Methods 5 or 17,
the emission rate expressed in ng/J heat
input is determined using the oxygen or
carbon-dioxide measurements and
particulate matter measurements
obtained under this section, the dry
basis Fc-factor and the dry basis
emission rate calculation procedure
contained in Method 19 (Appendix A).
(7) Prior to the Administrator's
issuance of a particulate matter
reference method that does not
experience sulfuric acid mist
interference problems, particulate
matter emissions may be sampled prior
to a wet flue gas desulfurization system.
(b) The following procedures and
methods are used to determine
compliance with the sulfur dioxide
standards under § 60.43a.
(1) Determine the percent of potential
combustion concentration (percent PCC)
emitted to the atmosphere as follows:
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(I) Fuel Pretreatment (% Rf):
Determine the percent reduction
achieved by any fuel pretreatment using
the procedures in Method 19 (Appendix
A). Calculate the average percent
reduction for fuel pretreatment on a
quarterly basis using fuel analysis data.
The determination of percent R( to
calculate the percent of potential
combustion concentration emitted to the
atmosphere is optional. For purposes of
determining compliance with any
percent reduction requirements under
{ 60.43a, any reduction in potential SO»
emissions resulting from the following
processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurization of fuel
oil, etc.).
(B) Coal pulverizers, and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System (%
Rt): Determine the percent sulfur
dioxide reduction achieved by any
sulfur dioxide control system using
' emission rates measured before and
after the control system, following the
procedures in Method 19 (Appendix A);
or, a combination of an "as fired" fuel
monitor and emission rates measured
after the control system, following the
procedures in Method 19 (Appendix A).
When the "as fired" fuel monitor is
used, the percent/reduction is calculated
using the average emission rate from the
sulfur dioxide control device and the
average SO« input rate from the "as
fired" fuel analysis for 30 successive
boiler operating days.
(iii) Overall percent reduction (% Ra):
Determine the overall percent reduction
using the results obtained in paragraphs
(b)(l) (i) and (ii) of this section following
the procedures in Method 19 (Appendix
A). Results are calculated for each 30-
day period using the quarterly average
percent sulfur reduction determined for
fuel pretreatment from the previous
quarter and the sulfur dioxide reduction
achieved by a sulfur dioxide control
system for each 30-day period in the
current quarter.
(iv) Percent emitted (% PCC):
Calculate the percent of potential
combustion concentration emitted to the
atmosphere using the following
equation: Percent PCC = 100-Percent R,,
(2) Determine the sulfur dioxide
emission rates following the procedures
in Method 19 (Appendix A).
(c) The procedures and methods
outlined in Method 19 (Appendix A) are
used in conjunction with the 30-day
nitrogen-oxides emission data collected
under § 60.47a to determine compliance
with the applicable nitrogen oxides
standard under § 60.44.
(d) Electric utility combined cycle gas
turbines are performance tested for
particulate matter, sulfur dioxide, and
nitrogen oxides using the procedures of
Method 19 (Appendix A). The sulfur
dioxide and nitrogen oxides emission
rates from the gas turbine used in
Method 19 (Appendix A) calculations
are determined when the gas turbine is
performance tested under subpart GG.
The potential uncontrolled particulate
matter emission rate from a gas turbine
is defined as 17 ng/J (0.04 Ib/million Btu)
heat input
J 60.49a Reporting requirements.
(a) For sulfur dioxide, nitrogen oxides,
and particulate matter emissions, the
performance test data from the initial
performance test and from the
performance evaluation of the
continuous monitors (including the
transmissometer) are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides the following information's
reported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/million Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period in the quarter;
reasons for non-compliance with the
emission standards; and, description of
corrective actions taken.
(3) Percent reduction of the potential
combustion concentration of sulfur
dioxide for each 30 successive boiler
operating days, ending with the last 30-
day period in the quarter; reasons for
non-compliance with the standard; and,
description of corrective actions taken.
(4) Identification of the boiler
operating days for which pollutant or
dilutent data have not been obtained by
an approved method for at least 18
hours of operation of the facility;
justification for not obtaining sufficient
data; and description of corrective
actions taken.
(5) Identification of the times when
emissions data have been excluded from
the calculation of average emission
rates because of startup, shutdown,
malfunction (NO, only), emergency
conditions (SOi only), or other reasons,
and justification for excluding data for
reasons other than startup, shutdown,
malfunction, or emergency conditions.
(6) Identification of "F" factor used for
calculations, method of determination,
and type of fuel combusted.
(7) Identification of times when hourly
averages have been obtained based on
manual sampling methods.
(B) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring
system.
(9) Description of any modifications to
the continuous monitoring system which
could affect the ability of the continuous
monitoring system to comply with
Performance Specifications 2 or 3.
(c) If the minimum quantity of
emission data as required by § 60.47a is
not obtained for any 30 successive
boiler operating days, the following
information obtained under the
requirements of § 60.46a(h) is reported
to the Administrator for that 30-day
period:
(1) The number of hourly averages
available for outlet emission rates (n,,)
and inlet emission rates (n,) as
applicable.
(2) The standard deviation of hourly
averages for outlet emission rates (s0)
and inlet emission rates (s,j as
applicable.
(3) The lower confidence limit for the
mean outlet emission rate (E0*) and the
upper confidence limit for the mean inlet
emission rate (E|*) as applicable.
(4) The applicable potential
combustion concentration.
(5) The ratio of the upper confidence
limit for the mean outlet emission rate
(£„*) and the allowable emission rate
(E«d) as applicable.
(d) If any standards under § 60.43a are
exceeded during emergency conditions
because of control system malfunction,
the owner or operator of the affected
facility shall submit a signed statement:
(1) Indicating if-emergency conditions
existed and requirements under
§ 60.46a(d) were met during each period,
and
(2) Listing the following information:
(i) Time periods the emergency
condition existed;
(ii) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility;
(iii) Amount of power purchased from
interconnected neighboring utility
companies during the emergency period;
(iv) Percent reduction in emissions
achieved;
(v) Atmospheric emission rate fng/J)
of the pollutant discharged; and
(vi) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit toward
the sulfur dioxide emission standard
under § 60.43a is claimed, the owner or
operator of the affected facility shall
submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the
calendar quarter, and whether the credit
was determined in accordance with the
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provisions of § 60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat content,
and date each pretreated fuel shipment
was received during the previous
quarter; the name and location of the
fuel pretreatment facility; and the total
quantity and total heat content of all
fuels received at the affected facility
during the previous quarter.
(f) For any periods for which opacity,
sulfur dioxide or nitrogen oxides
emissions data are not available, the
owner or operator of the affected facility
shall submit a signed statement
indicating if any changes were made in
operation of the emission control system
during the period of data unavailability.
Operations of the control system and
affected facility during periods of data
unavailability are to be compared with
operation of the control system and
affected facility before and following the
period of data unavailability.
(g) The owner or operator of the
affected facility shall submit a signed
statement indicating whether:
(1) The required continuous
monitoring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to s^how compliance
was or was not obtained in accordance
with approved methods and procedures
of this part and is representative of
plant performance.
(3) The .minimum data requirements
have or have not been met; or, the
minimum data requirements have not
been met for errors that were
unavoidable. v
(4) Compliance with the standards has
or has not been achieved during the
reporting period.
(h) For the purposes of the reports
required under § 60.7, periods of excess
emissions are defined as all 6-minute
periods during which the average
opacity exceeds the applicable opacity
standards under § 60.42a(b). Opacity
levels in excess of the applicable
opacity standard and the date of such
excesses are to be submitted to the
Administrator each calendar quarter.
(i) The owner or operator of an
affected facility shall submit the written
reports required under this section and
subpart A to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day
following the end of each calendar
quarter.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
4. Appendix A to part 60 is amended
by adding new reference Method 19 as
follows:
Appendix A—Reference Methods
Method 19. Determination of Sulfur
Dioxide Removal Efficiency and
Particulate, Sulfur Dioxide and Nitrogen
Oxides Emission Rates From Electric
Utility Steam Generators
1. Principle and Applicability
€.1 Principle.
1.1.1 Fuel samples from before and
after fuel pretreatment systems are
collected and analyzed for sulfur and
heat content, and the percent sulfur
dioxide (ng/Joule, Ib/million Bru)
reduction is calculated on a dry basis.
(Optional Procedure.)
1.1.2 Sulfur dioxide and oxygen or
carbon dioxide concentration data
obtained from sampling emissions
upstream and downstream of sulfur
dioxide control devices are used to
calculate sulfur dioxide removal
efficiencies. (Minimum Requirement.) As
an alternative to sulfur dioxide
monitoring upstream of sulfur dioxide
control devices, fuel samples may be
collected in an as-fired condition and
analyzed for sulfur and heat content.
(Optional Procedure.)
1.1.3 An overall sulfur dioxide
emission reduction efficiency is
calculated from the efficiency of fuel
pretreatment systems and the efficiency
of sulfur dioxide control devices.
1.1.4 Particulate, sulfur dioxide,
nitrogen oxides, and oxygen or carbon
dioxide concentration data obtained
from sampling emissions downstream
from sulfur dioxide control devices are
used along with F factors to calculate
particulate, sulfur dioxide, and nitrogen
oxides emission rates. F factors are
values relating combustion gas volume
to the heat content of fuels.
1.2 Applicability. This method is
applicable for determining sulfur
removal efficiencies of fuel pretreatment
and sulfur dioxide control devices and
the overall reduction of potential sulfur
dioxide emissions from electric utility
steam generators. This method is also
applicable for the determination of
particulate, sulfur dioxide, and nitrogen
oxides emission rates.
2. Determination of Sulfur Dioxide
Removal Efficiency of Fuel
Pretreatment Systems
2.1 Solid Fossil Fuel.
2.1.1 Sample Increment Collection.
Use ASTM D 2234'. Type I, conditions
A, B, or C, and systematic spacing.
Determine the number and weight of
increments required per gross sample
representing each coal lot according to
Table 2 or Paragraph 7.1.5.2 of ASTM D
2234'. Collect one gross sample for each
raw coal lot and one gross sample for
each product coal lot.
2.1.2 ASTM Lot Size. For the purpose
of Section 2.1.1, the product coal lot size
is defined as the weight of product coal
produced from one type of raw coal. The
raw coal lot size is the weight of raw
coal used to produce one product coal
lot. Typically, the lot size is the weight
of coal processsed in a 1-day (24 hours)
period. If more than one type of coal is
treated and produced in 1 day, then
gross samples must be collected and
analyzed for each type of coal. A coal
lot size equaling the 90-day quarterly
fuel quantity for a specific power plant
may be used if representative sampling
can be conducted for the raw coal and
product coal.
Note.—Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
2.1.3 Grass Sample Analysis.
Determine the percent sulfur content
(%S) and gross calorific value (GCV) of
the solid fuel on a dry basis for each
gross sample. Use ASTM 2013 • for
sample preparation, ASTM D 3177 ] for
sulfur analysis, and ASTM D 3173 ' for
moisture analysis. Use ASTM D 3176 *
for gross calorific value determination.
2.2 Liquid Fossil Fuel.
2.2.1 Sample Collection. Use ASTM
D 270 l following the practices outlined
for continuous sampling for each gross
sample representing each fuel lot.
2JZ.2 Lot Size. For the purposes of
Section 2.2.1, the weight of product fuel
from one pretreatment facility and
intended as one shipment (ship load,
barge load, etc.) is defined as one
product fuel lot. The weight of each
crude liquid fuel type used to produce
one product fuel lot is defined as one
inlet fuel lot.
Note.— Alternate deTinitioos of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
Note.— For the purposes of this method,
raw or inlet fuel (coal or oil) is defined as the
fuel delivered to the desulfurization
pretreatment facility or to the steam
generating plant. For pretreated oil the input
oil,to the oil desurfurizajion process (e.g.
hydrotreatment emitted) is sampled.
2.2.3 Sample Analysis. Determine
the percent sulfur content (%S) and
gross calorific value (GCV). Use ASTMD
240 l for the sample analysis. This value
can be assumed to be on a dry basis.
1 Use the molt recent revision or designation of
the ASTM procedure specified.
'Use the most recent revision or designation of
the ASTM procedure specified.
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2.3 Calculation of Sulfur Dioxide
Removal Efficiency Due to Fuel
Pretregtment. Calculate the percent
sulfur dioxide reduction due to fuel
pretreatment using the following
equation:
1R. « 100
*VGCVo
SS1/GCV1
Where:
XR<=Sulfur dioxide removal efficiency due
pretreatment; percent.
*S»=Sulfur content of the product fuel lot on
a dry basis; weight percent
%Si=Sulfur content of the inlet fuel lot on a
dry basis; weight percent.
GCV,=Gross calorific value for the outlet
fuel lot on a dry basis; k]/kg (Btu/lb).
GCV,=Gro88 calorific value for the inlet fuel
lot on a dry basis; kj/kg (Btu/lb).
Note.—If more than one fuel type is used to
produce the product fuel, use the following
equation to calculate the sulfur contents per
unit of heat content of the total fuel lot %S/
GCV:
SS/GCV
k-1
Where:
Yk«The fraction of total mass input derived
from each type, k. of fuel.
*Sfc= Sulfur content of each fuel type, k/on a
dry basis; weight percent
GCVk=GroBS calorific, value for each fuel
type, k, on a dry basis; kj/kg (Btu/lb).
n— The number of different types of fuels.
3. Determination of Sulfur Removal
Efficiency of the Sulfur Dioxide Control
Device
3.1 Sampling. Determine SO»
emission rates at the inlet and outlet of
the sulfur dioxide control system
according to methods specified in the
applicable subpart of the regulations
and the procedures specified in Section
5. The inlet sulfur dioxide emission rate
may be determined through fuel analysis
(Optional, see Section 3.3.)
3.2. Calculation. Calculate the
percent removal efficiency using the
following equation:
• 100 * (1.0 -
^0
021
Where:
%R, =Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
inlet and outlet monitoring data; percent.
Ego o=Sulfur dioxide emission rate from the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
- En i=Sulfur dioxide emission rate to the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
3.3 As-fired Fuel Analysis (Optional
Procedure). If the owner or operator of
an electric utility steam generator
chooses to determine the sulfur dioxide
imput rate at the inlet to the sulfur
dioxide control device through an as-
fired fuel analysis in lieu of data from a
sulfur dioxide control system inlet gas
monitor, fuel samples must be collected
in accordance with applicable
paragraph in Section 2. The sampling
can be conducted upstream of any fuel
processing, e.g., plant coal pulverization.
For the purposes of this section, a fuel
lot size is defined as the weight of fuel
consumed in 1 day (24 hours) and is
directly related to the exhaust gas
monitoring data at the outlet of the
sulfur dioxide control system.
3.3.1 Fuel Analysis. Fuel samples
must be analyzed for sulfur content and
gross calorific value. The ASTM
procedures for determining sulfur
content are defined in the applicable
paragraphs of Section 2.
3.3.2 Calculation of Sulfur Dioxide
Input Rate. The sulfur dioxide imput rate
determined from fuel analysis is
calculated by:
2.0(»Sf
GCV
x 10 for S. I. units.
2.0(JS.) .
—g^T x 10 for English units.
Where:
I
Sulfur dioxide Input rate from as-fired fuel analysis,
ng/J (Ib/mUllon Btu).
XSf » Sulfur content of as-fired fuel, on a dry basis; weight
percent.
GCV'» Gross calorific value for as-fired fuel, on a dry basis;
kJ/kg (Btu/lb).
3.3.3 Calculation of Sulfur Dioxide 3.3.2 and the sulfur dioxide emission
Emission Reduction Using As-fired Fuel rate, ESQI, determined in the applicable
Analysis. The sulfur dioxide emission paragraph of Section 5.3. The equation
reduction efficiency is calculated using f°r sulfur dioxide emission reduction
the sulfur imput rate from paragraph efficiency is:
5R
9(f)
100
(1.0 -
Where:
*Rg(f) " Sulfur d1ox'lde removal efficiency of the sulfur
dioxide control system using as-fired fuel analysis
data; percent.
Eso • Sulfur dioxide emission rate fron sulfur dioxide control
*U2
system; ng/J (lb/m1lUon Btu).
I$ • Sulfur dioxide Input rate from as-fired fuel analysis;
ng/J Ob/nil lion Btu}.
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4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
loon.o- O.o -
the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %Rt,
4.2 Calculate the overall percent
sulfur redaction as:
*Rfl
O.O-lrf)]
Where:
Overall sulfur dioxide reduction; percent.
XR- • Sulfur dioxide removal efficiency of fuel pretreatment
from Section 2; percent. Refer to applicable subpart
for definition of ipplicable averaging period.
$R • Sulfur dioxide removal efficiency of sulfur dioxide control
device either 0. or CO- - based calculation or calculated
froa fuel analysts and emission data, from Section 3;
percent. Refer to applicable subpart for definition of
applicable averaging period.
5. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(Fd) factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, F,
factors are used.
5.2.1 A verage F Factors, Table 1
shows average Fd, F^ and Fe factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1. the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of this section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SOi or
Ot or COa concentrations data obtained
in Section 3.1. Determine the particulate,
NO,, and O. or CO, concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted; a wet F factor (Fw) la the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
227.0(«H) + 95.7(tC) + 35.4(«S) + 8.6«N) - 28.5QO)
GCY
347.4(SH)+95.7(tC)-t-35.4(«S}+8.6(lN}-28.5(tO)+13.0(SH20)«*
For English Units:
, . 106[5.S7(tH)
1.53(«C) + 0.57(tS) *
- 0.<6(tO)]
GCV
106[5.57(«H)+1.53(SC)*0.57(JS)+0.14(lN)-0.46(«0)-fO.21(^0)**]
The »2° tern nay be omitted If SH and W include the unavailable
hydrogen and oxygen In the fora of (UO.
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Where:
F« F,, and Fc have the units of scm/J, or scf/
million Btu; %H, %C, %S, %N, %O, and
%HW) and the pollutant
concentration (C,) are measured in the
flue gas on a wet basis, the following
equations are applicable: (Note: Fw
factors are not applicable after wet
scrubbers.)
(a)
20.9
120.9(1 -
Where:
8,,=Proportion by volume of water vapor in
the ambient air.
In lieu of actual measurement, B,.
may be estimated as follows:
Note.—The following estimating factors are
selected to assure that any negative error
introduced in the term:
/ 20.9 x
20.9(1 - B ) - *0,
will not be larger than —1.5 percent
However, positive errors, or over-
estimation of emissions, of as much as 5
percent may be introduced depending
upon the geographic location of the
facility and the associated range of
ambient mositure.
(i) Bw.=0.027. This factor may be used
as a constant value at any location.
(ii) B».=Highest monthly average of
Bw. which occurred within a calendar
year at the nearest Weather Service
Station.
(iii) 8,,=Highest daily average of BW,
which occurred within a calendar month
at the nearest Weather Service Station,
calculated from the data for the past 3
years. This factor shall be calculated for
each month and may be used as an
estimating factor for the respective
calendar month.
(b)
Sr rd
20.9
L20.9 (1 - 8WS) -
Where:
Bwl=Proportion by volume of water vapor in
the stack gas.
5.3.1.3 Dry/Wet Basis. When the
pollutant concentration (Cw) is measured
on a wet basis and the oxygen
concentration (%Oad) or measured on a
dry basis, the following equation is
applicable:
E -
r] C-
20.9
20.9 - SO,
2d
When the pollutant concentration (CJ
is measured on a dry basis and the
oxygen concentration (%OM) is
measured on a wet basis, the following
equation is applicable:.
Cd Fd
20.9
20.9 -
5.3.2 Carbon Dioxide-Based F Factor
Procedure.
5.3.2.1 Dry Basis. When both the
percent carbon dioxide (%COj,i) and the
pollutant concentration (Cd) are
measured in the flue gas on a dry basis,
the following equation is applicable:
5.3.2.2 Wet Basis. When both the
percent carbon dioxide (%COt») and the
pollutant concentration (C,) are
measured on a wet basis, the following
equation is applicable:
5.3.2.3 Dry/Wet Basis. When the
pollutant concentration (Cw) is measured
on a wet basis and the percent carbon
dioxide (%COJd) is measured on a dry
basis, the following equation is
applicable:
C F
100
When the pollutant concentration (CJ
is measured on a dry basis and the
precent carbon dioxide (%CO>W) is
measured on a wet basis, the following
equation is applicable:
E ' C 0 - B) F
5.4 Calculation of Emission Rate
from Combined Cycle-Gas Turbine
Systems. For gas turbine-steam
generator combined cycle systems, the
emissions from supplemental fuel fired
to the steam generator or the percentage
reduction in potential (SO>) emissions
cannot be determined directly. Using
measurements from the gas turbine
exhaust (performance test, subpart GG)
and the combined exhaust gases from
the steam generator, calculate the
emission rates for these two points
following the appropriate paragraphs in
Section 5.3.
Note. — Fw factors shall not be used to
determine emission rates from gas turbines
because of the injection of steam nor to
calculate emission rates after wet scrubbers;
Fd or Fc factor and associated calculation
procedures are used to combine effluent
emissions according to the procedure in
Paragraph 5.2.3.
The emission rate from the steam generator
is calculated as:
IV-327
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Federal Register / Vol. 44, No. 113 / Monday, June 11. 1979 / Rules and Regulations
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
XR.
the base value. Any sulfur redaction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %Rf.
4.2 Calculate the overall percent
sulfur reduction «:
Where:
XR » Overall sulfur dioxide reduction; percent.
XR- • Sulfur dioxide removaV efficiency of fuel pretreatment
from Section 2; percent. Refer to applicable subpart
for definition of applicable averaging period.
XR • Sulfur dioxide removal efficiency of sulfur dioxide control
9
device either 0. or CO. - based calculation or calculated
fro* fuel analysts *nd emission data, from Section 3;
percent. Refer to applicable subpart for definition of
applicable averaging period.
5. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used. (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(Fd) factors and associated emission
calculation procedures are used after
wet scrubbers.] When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, Fc
factors are used.
5.2.1 Average F Factors, Table 1
snows average Fd. F,,, and Fc factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1, the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of mis section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SOi or
Oi or CO* concentrations data obtained
in Section 3.1. Determine the particulate,
NO,, and Oa or CO, concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted; a wet F factor (F.) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
Z27.0(XH) * »5.7(XC) * 35.4(XS) + 8.6UN) - 28.5(XO)
GCV
347.4(XH)*95.7(SC)-t-35.4(tS}+e.6(%N)-28.5(SO)-H3.0(«H20)**
For English Units:
r . 106[5.57(»H) * 1.53OC)
*0.57(XS)
GCV
O.UflH) - 0.46(M)1
106[5.57(XH)+1.53(SC)-*0.57(XS)+0.14(XN)-0.46(»5)*0.2USH20}**]
The »20 tern My be omitted If tH and SO Include the unavailable
hydrogen and oxygen In the for* of M.O.
IV-328
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1079 / Rules and Regulations
59 V
Where:
Ew=Pollutant emission rate from steam
generator effluent, ng/J (lb/million Btu).
E,«= Pollutant emission rate in combined
cycle effluent; ng/J (Ib/million Btu).
Elt=Pollutant emission rate from gas turbine
effluent; ng/J (Ib/million Btu).
X»=Fraction of total heat input from
•upplemental fuel fired to the steam
generator.
X,,=Fraction of total heat input from gas
turbine exhaust gases.
Note.—The total heat input to the steam
generator is the sum of the heat input from
•upplemental fuel fired to the steam
generator and the heat input to the steam
generator from the exhaust gases from the
gas turbine.
5.5 Effect of Wet Scrubber Exhaust,
Direct-Fired Reheat Fuel Burning. Some
wet scrubber systems require that the
temperature of the exhaust gas be raised
above the moisture dew-point prior to
the gas entering the stack. One method
used to accomplish this is directfiring of
an auxiliary burner into the exhaust gas.
The heat required for such burners is
from 1 to 2 percent of total heat input of
the steam generating plant. The effect of
this fuel burning on the exhaust gas
components will be less than ±1.0
percent and will have a similar effect on
emission rate calculations. Because of
this small effect, a determination of
effluent gas constituents from direct-
fired reheat burners for correction of
stack gas concentrations is not
necessary.
Where:
§,,=Standard deviation of the average outlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
a, = Standard deviation of the average inlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
6.3 Confidence Limits. Calculate the
lower confidence limit for the mean
outlet emission rates for SO, and NO,
and, if applicable, the upper confidence
limit for the mean inlet emission rate for
SO, using the following equations:
Table 1»-1.—F Factors for Various fuels*
E,*=E,+U.i.8,
Where:
Eo*=The lower confidence limit for the mean
outlet emission rates; ng/J (Ib/million
Btu).
E,* =The upper confidence limit for the mean
inlet emission rate; ng/J (Ib/million Btu).
t».«= Values shown below for the indicated
number of available data points (n):
F.
n Values for IM
2
Fuel type
dscm
J
diet
10* Btu
mem
J
MCt
10* Btu
•cm
J
Kf
10* Btu
Coot:
Anthracite • _
Bituminous •—« -
UBnAs._ „,.
Gac
M*tuml ,„, .,,
Propene....«««...»»»«...«..»««...
Butane .«..«.-«-. ..
MUfoli||
Wood Bark
2.71x10"
2.63x10-
265x10-
2.47x10-
2.43x10-
2.34x10-
2.34x10-
2.48x10-
2.58x10'
(10100)
(9780)
(9660)
(9190)
(8710)
(8710)
(8710)
(9240) ..
(9600) -
2.83x10-
^e6x10-
3.21X10"
2.77X 10"
2.85x10"
2.74x10'
2.79x10'
(10540)
(10640)
(11950)
(10320)
(10810)
(10200)
(10390)
0.530X10-'
0.484x10-'
0.513x10-'
0383x10"'
0.287x10-'
0.321x10-'
0.337x10-'
0.492x10"'
0.497X10"'
(1970)
(1600)
(1910)
(1420)
(1040)
(1190)
(1250)
(1830)
(1850)
• A* classified accordng to ASTM D 388-66.
•Crude, residual, or distillate.
•Determined «t standard conditions: 20' C (68* F) and 760 mm Hg (29.92 la Hg).
10
11
12-16
17-21
22-26
27-31
32-51
52-91
92-151
152 or more
I.
6.31
2.42
2.35
213
2.02
1.94
1.89
1.86
1.83
1.81
1.77
1.73
1.71
1.70
1.66
1.67
1.66
1.65
6. Calculation of Confidence Limits for
Inlet and Outlet Monitoring Data
6.1 Mean Emission Rates. Calculate
the mean emission rates using hourly
averages in ng/J (Ib/million Btu) for SO,
and NO, outlet data and, if applicable,
SOa inlet data using the following
equations:
6.2 Standard Deviation of Hourly
Emission Rates. Calculate the standard
deviation of the available outlet hourly
average emission rates for SO! and NO,
and, if applicable, the available inlet
hourly average emission rates for SO«
using the following equations:
1 nj
Where:
E.=Mean outlet emission rate; ng/J (lb/
million Btu).
E,=Mean inlet emission rate; ng/J (Ib/million
Btu).
x.—Hourly average outlet emission rate; ng/J
(Ib/million Btu).
X|—Hourly average in let emission rate; ng/j
(Ib/million Btu).
n.sNumber of outlet hourly averages
available for the reporting period.
ni« Number of inlet hourly average!
available for reporting period.
•1 -(^F£) C/^r?
\~ j \^
PCC
The values of this table are corrected for
n-1 degrees of freedom. Use n equal to
the number of hourly average data
points.
7. Calculation to Demonstrate
Compliance When Available
Monitoring Data Are Less Than the
Required Minimum
7.1 Determine Potential Combustion
Concentration (PCCjforSOt.
7.1.1 When the removal efficiency
due to fuel pretreatment (% Rf) is
included in the overall reduction in
potential sulfur dioxide emissions (% R«)
and the "as-fired" fuel analysis is not
used, the potential combustion
concentration (PCC) is determined as
follows:
10'; ng/J
Ib/million Btu.
• Potential emissions removed by the pretreatment
l process, using the fuel parameters defined In
section 2.3; ng/J (Ib/million Btu).
IV-329
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1079 / Rules and Regulations
7.1.2 When the "as-fired" fuet
analysis is used and the removal
efficiency due to fuel pretreatment (% R,)
is not included Ln the overall reduction
in potential sulfur dioxide emissions (%
RJ, the potential combustion
concentration (PCC) is determined as
follows:
PCC=I.
PCC
PCC
I. + 2
I. * 2
7.1.4 When inlet monitoring data are
used and the removal efficiency due to
fuel pretreatment (% R,) is not included
in the overall reduction in potential
sulfur dioxide emissions (% R,), the
potential combustion concentration
(PCC) is determined as follows:
PCC = E,*
Where:
E,* = The upper confidence limit of the mean
inlet emission rate, as determined in
section 6.3.
7.2 Determine Allowable Emission
Rates
7.2.1 NO*. Use the allowable
emission rates for NOX as directly
defined by the applicable standard in
terms of ng/J (Ib/million Btu).
7.2.2 SO,. Use the potential
combustion concentration (PCC) for SOj
as determined in section 7.1, to
determine the applicable emission
standard. If the applicable standard is
an allowable emission rate in ng/J (lb/
million Btu), the allowable emission rate
When:
I, = The luUar dioxide Input rate a* defined
in Motion 3.3
7.1.3 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment [% RJ
i« included in the overall reduction {%
RO), the potential combustion
concentration (PCC) is determined as
follows:
ng/J
Ib/«ni1on 6tu.
is used as E.^. If the applicable standard
is an allowable percent emission,
calculate the allowable emission rate
(E.u] using the following equation:
E«« = %PCC/100
Where:
% PCC = Allowable percent emission as
defined by the applicable standard;
percent.
73 Calculate E, * lEua . To determine
compliance for the reporting period
calculate the ratio:
Where:
Eo* = The lower confidence limit for the
mean outlet emission rates, as defined in
section 6.3; ng/J (Ib/million Btu).
E.U, = Allowable emission rate an denned in
section 7.2; ng/J (Ib/million Btu).
If Eo'fEat is equal to or less than 1.0, the
facility is in compliance; if E,,*/E^ is greater
than 1.0, the facility is not in compliance for
the reporting period.
(FR Doc. 7V-17W7 Piled e-B-Tft &« *m]
IV-330
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
99
40 CFR Pan 60
[FRL 1276-3]
Priority List and Additions to the List
of Categories of Stationary Sources
AGENCY: Environmental Protection'
Agency.
ACTION: Final rule.
SUMMARY: This action contains EPA's
promulgated list of major source
categories for which standards of
performance for new stationary sources
are to be promulgated by August 1982.
The Clean Air Act Amendments of 1977
specify that the Administrator publish a
list of the categories of major stationary
sources which have not been previously
listed as source categories for which
standards of performance will be
established. The promulgated list
implements the Clean Air Act and
reflects the Administrator's
determination that, based on
preliminary assessments, emissions
from the listed source categories
contribute significantly to air pollution.
The intended effect of this promulgation
is to identify major source categories for
which standards of performance are to
be promulgated. The standards would
apply only to new or modified
statiorrary sources of air pollution.
EFFECTIVE DATE: August 21, 1979.
ADDRESSES: The background document
for the promulgated priority list may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number 919-
541-2777. Please refer to "Revised
Prioritized List of Source Categories for
New Source Performance Standards,"
EPA-450/3-79-023. The prioritization
methodology is explained in the
background document for the proposed
priority list. This document, "Priorities
for New Source Performance Standards
under the Clean Air Act Amendments of
1977," EPA-450/3-78-019, can also be
obtained from the Research Triangle
Park EPA Library. Copies of all
comment letters received from
interested persons participating in this
rulemaking, a summary of these
comments, and a summary of the
September 29, 1978, public hearing are
available for inspection and copying
during normal business hours at EPA's
Public Information Reference Unit,
Room 2922 [EPA Library), 401 M Street,
SW., Washington, DC.
FOR FURTHER INFORMATION CONTACT
Gary D. McCutchen, Emission Standards
and Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, N.C. 27711,
telephone number (919) 541-5421.
SUPPLEMENTARY INFORMATION: On
August 31,1978 (43 FR 38872), EPA
proposed a priority list of major source
categories for which standards of
performance would be promulgated by
August 1982, and invited public
comment on the list and the
methodology used to prioritize the
source categories. Promulgation of this
list is required by section lll(f) of the
Clean Air Act as amended August 7,
1977. The significant comments that
were received during the public
comment period, including those made
at a September 29,1978, public hearing,
have been carefully reviewed and
considered and, where determined by
the Administrator to be appropriate,
changes have been included in this
notice of final rulemaking.
Background
The program to establish standards of
performance for new stationary sources
(also called New Source Performance
Standards or NSPS) began on December
1970, when the Clean Air Act was
signed into law. Authorized under
section 111 of the Act, NSPS were to
require the best control system
(considering cost) for new facilities, and
were intended to complement the other
air quality management approaches
authorized by the 1970 Act. A total of 27
source categories are regulated by
NSPS, with NSPS for an additional 25
source categories under development.
During the 1977 hearings on the Clean
Air Act, Congress received testimony on
the need for more rapid development of
NSPS. There was concern that not all
sources which had the potential to
endanger public health or welfare were
controlled by NSPS and that the
potential existed for "environmental
blackmail" from source categories not
subject to NSPS These concerns were
reflected in the Clean Air Act
Amendments of 1977, specifically in
section lll(f).
Section lll(f) requires that the
Administrator publish a list of major
stationary sources of air pollution not
listed, as of August 7, 1977, under
section lll(b)(l)(A), which in effect
meant those sources for which NSPS
had not yet been proposed or
promulgated. Before promulgating this
list, the Administrator was to provide
notice of and opportunity for a public
hearing and consult with Governors and
State air pollution control agencies. In
developing priorities, section lll(f)
specifies that the Administrator
consider (1) the quantity of emissions
from each source category, (2) the extent
to which^ach pollutant endangers
public health or welfare, and (3) the
mobility and competitive nature of each
stationary source category, e.g., the
capability of a new or existing source to
locate in areas with less stringent air
pollution control regulations. Governors
may at any time submit applications
under section lll(g) to add major source
categories to the list, add any source
category to the list which may endanger
public health or welfare, change the
priority ranking, or revise promulgated
NSPS.
Development of the Priority List
Development of the priority list was
initiated by compiling data on a large
number of source categories from
literature resources. The data were first
analyzed to determine major source
categories, those categories for which an
average size plant has the potential to
emit 100 tons or more per year of any
one pollutant. These major source
categories were then subjected to a
priority ranking procedure using the
three criteria specified in section lll(f)
of the Act.
The procedure used first ranks source
categories on a pollutant by pollutant
basis. This resulted in nine lists (one for
each pollutant—volatile organic
compounds (VOC), nitrogen oxides,
particulate matter, sulfur dioxide,
carbon monoxide, lead, fluorides, acid
mist, and hydrogen sulfide) with each
list ranked using the criteria in the Act.
In this ranking, first priority was given
to quantity of emissions, second priority
to potential impact on health or welfare,
and third priority to mobility. Thus.
sources with the greatest growth rales
and emission reduction potential were
high on each list; sources with limited
choice of location, low growth and small
emission reduction potential were low
on each list.
The nine lists were combined into one
by selecting pollutant goals—a
procedure which, in effect, assigned a
relative priority to pollutants based
upon the potential impact of NSPS After
the pollutant goals were selected, the
final priority list was established
through the selection of source
categories which have maximum impact
on attaining the selected goals. The
effect of this procedure was to
emphasize control of all criteria
pollutants except carbon monoxide and
to give carbon monoxide and non-
criteria pollutants a lower priority.
IV-331
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
In the background reports and in the
preamble to the proposed priority list,
the term "hydrocarbon" was used even
though the emissions referred to were
VOC which, unlike hydrocarbon
compounds, can contain elements other
than carbon and hydrogen. A VOC is
defined by EPA as any organic
compound that, when released to the
atmosphere, can remain long enough to
participate in photochemical reactions.
Since VOC contribute to ambient levels
of photochemical oxidants, they are
considered a criteria pollutant.
The ranking of source categories on
the list and the differentiation between
major and minor sources was sensitive
to the accuracy of the data utilized. The
data base used to establish the priority
list was obtained from a number of
literature sources including EPA
screening studies. However, screening
studies were not available for all source
categories. Therefore, if new information
becomes avajlable after promulgation of
the list, the Administrator may delete
from or add to the list in response to this
new information.
Additional detail on the prioritization
methodology, the input factors used, and
the ranking of individual source
categories is available in the two
background documents (see
"ADDRESSES").
Significance of Priority List
The promulgated list is essentially an
advance notice of future standard
development activity. It identifies major
source categories and the approximate
order in which NSPS development
would be initiated. However, if further
study indicates that an NSPS would
have little or no effect on emissions, or
that an NSPS would be impractical, a
source category would be given a lower
priority or removed from the list.
Similarly, new information may increase
the priority of a source category. The
Administrator may also concurrently
develop standards for sources which are
not on the priority list, especially certain
"minor" sources which, in aggregate.
represent a large quantity of emissions.
The distinction between major and
minor source categories is defined only
for the purpose of determining NSPS
priorities and should not be used to
determine sources subject to New
Source Review, which is conducted on a
case-by-case basis. Moreover, some
New Source Review programs, such as
prevention of significant deterioration,
have separate and distinct criteria for
defining a major source (e.g., 100 tons
per year potential for certain source
types and 250 tons per year for others).
Identification of Source Categories
Two groups of sources in addition to
minor sources are not included on the
promulgated list. One group includes
sources which could not be evaluated
due to insufficient information. This lack
of data suggests that these sources,
which are identified in the background
report, "Priorities for NSPS under the
Clean Air Act of 1977," have not
previously been regulated or studied
and, therefore, are probably not major
sources. Nevertheless, the Administrator
will continue to investigate these
sources and will consider development
of NSPS for any which are identified as
being significant sources of air pollution.
The second group of source categories
not on the priority list consists of those
listed under section lll(b)(l)(A) on or
before August 7,1977. These are.
Fossil-fuel-fired steam generators
Incinerators
Portland Cement Plants
Nitric Acid Plants
Sulfuric Acid Plants
Asphalt Concrete Plants
Petroleum Refineries
Storage Vessels for Petroleum Liquids
Secondary Lead Smelters
Secondary Brass and Bronze Ingot Production
Plants
Iron and Steel Plants
Sewage Treatment Plants
Primary Copper Smelters
Primary Zinc Smelters
Primary Lead Smelters
Primary Aluminum Reduction Plants
Phosphate Fertilizer Industry. Wet Process
Phosphoric Acid Plants
Phosphate Fertilizer Industry:
Superphosphonc Acid Plants
Phosphate Fertilizer Industry. Diammonium
Phosphate Plants
Phosphate Fertilizer Industry. Triple
Superphosphate Plants
Phosphate Fertilizer Industry. Granular Triple
Superphosphate Storage Facilities
Coal Preparation Plants
Ferroalloy Production Facilities
Steel Plants Electric Arc Furnaces
Kraft Pulp Mills
Lime Plants
Grain Elevators
There are. however, some facilities (or
subcategones) within these source
categories for which NSPS have not
been developed, but which may by
themselves be significant sources of air
pollution. A number of these facilities
were evaluated as if they were separate
source categories; three which rank high
in priority are included on the
promulgated list to indicate that the
Administrator plans to develop
standards for them: Petroleum refinery
fugitive emissions, industrial fossil-fuel-
fired steam generators, and non-
municipal incinerators. In addition to
these, the Administrator will continue to
evaluate affected facilities within listed
source categories and may from time to
time develop NSPS for such facilities.
The iron and steel industry provides an
example of a category which is already
listed (so does not appear on the priority
list), but in which an active interest
remains. Although the growth rate for
new sintering capacity is presently very
low, the Administrator is continuing to
assess emission control and
measurement technology with a view
toward possible development of an
NSPS for sintering plants at a later date
A project is also underway to update
emission factors for all steelmaking
processes, including fugitive emissions,
in an effort to determine the relative
significance of emissions from each
process. In addition, byproduct coke
ovens, nearly always associated with
steel mills, are included on the priority
list and are undergoing standard
development stud;es
There are some differences between
the format of the list in the background
report, "Revised Prioritized List of
Source Categories for NSPS
Promulgation" and the format of the list
which appears here These differences
are primarily a result of aggregation of
subcategones which had been
subdivided for size classification and
priority ranking analysis. Non-metallic
mineral processing, for example, had
been subdivided into nine subcategories
for prioritization. eight of which were
analyzed separately (stone, sand and
gravel, clay, gypsum lime, borax,
fluorspar, and phosphate rock mining)
and one of which is considered a minor
source (mica mining) EPA plans to
study the entire non-metallic mineral
processing industry at one time, since
many of the processes and control
techniques are similar For this reuson,
the industr\ is identified by a single
aggregated listing This does not
necessarily implv that a single standard
would apply to all sources within the
listed category Ralher. as described
below in the case of the synthetic
organic chemical manufacturing
industry, the nature and scope of
standards will be determined only after
a detailed study of sources within the
category
In addition to the major sources, three
source categories not identified as being
major source categories have been
added to the list organic solvent
cleaning, industrial surface coating of
metal furniture, and lead acid battery
manufacture
Organic solvent cleaning was chosen
for study because this source category
accounts for some 5 percent of
stationary source VOC emissions
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Federal Register / Vol. 44. No. 163 / Tuesday. August 21. 1979 / Rules and Regulations
typical air quality control region. Thus.
although individual facilities typically
emit less than 100 tons per year, this is a
significant source of VOC emissions and
the Administrator considers it prudent
to continue the development of a
standard for this source category.
The metal furniture coating industry is
also a significant source of VOC
emissions, and there are over 300
existing facilities with the potential to
emit more than 100 tons per year.
Lead acid battery manufacture is a
significant source of lead emissions. An
NSPS for this source category is
expected to assist in attainment of the
National Ambient Air Quality Standard
for lead.
Stationary gas turbines are included
on this list because this source category
had not been listed by August 7,1977,
when the Clean Air Act Amendments
were enacted. However, this source
category has not been prioritized, since
it was listed under section lll(b)(l)(A)
and NSPS were proposed October 3,
1977.
One listed source category which
deserves special attention is the
synthetic organic chemical
manufacturing industry (SOCMI).
Preliminary estimates indicate that there
may be over 600 different processes
included in this source category, but
only 27 of these processes have been
evaluated. For the others, there was not
enough information available. As is the
case with several other aggregated
source categories, generic standards will
be used to cover as many of the sources
as possible, so separate NSPS for each
of the 600 processes are unlikely.
Based on an effort which has been
underway within EPA for two years to
study this complex source category, the
generic standards could regulate nearly
all emissions by covering four broad
areas: Process facilities, storage
facilities, leakage, and transport and
handling losses. Also, since a number of
the pollutants emitted are potentially
toxic or carcinogenic, regulation under
section 112, Nation"! Emission
Standards for Hazardous Air Pollutants
(NESHAP), rather than NSPS may be
more appropriated. Therefore, SOCMI is
listed as a single source category The 27
processes considered the most likely
candidates for NSPS or NESHAP
coverage through generic standards are
listed in the preamble to the proposed
priority list and discussed in the
background documents.
Additional information has resulted in
the exclusion from the list of some
source categories which are shown in
the background reports. Mixed fuel
boilers and feed and grain milling are
regulated by the NSPS for fossil-fuel
steam generators and grain elevators,
respectively. Beer manufacture has a
much lower emission level than had
been assumed in the background report,
and whiskey manufacture was deleted
due to a lack of any demonstrated
control technology.
Public Participation
The Clean Air Act requires that the
Administrator, prior to promulgating this
list of source categories, consult with
Governors and State air pollution
control agencies. An invitation was
extended on February 28,1978, to the
State and Territorial Air Pollution
Program Administrators (STAPPA) and
the National Governors' Association
(NGA) to attend the first Working Group
meeting, March 16,1978, and review the
draft background report and the
methods used to apply the priority
criteria. On March 24,1978, each
Governor and the director of each State
air pollution control agency was notified
by letter of this project, including an
invitation to participate or comment:
(1) At the April 5-6,1978, National Air
Pollution Control Techniques Advisory
Committee (NAPCTAC) meeting in
Alexandria, Virginia;
(2) When the final background report
was mailed to them;
(3) When the list was proposed in the
Federal Register; or
(4) At a public hearing to be held on
the proposed list. The draft background
report for,the proposed list was mailed
to all N APCTAC members, five of which
represent State or local agencies, two of
which represent environmental groups,
and eight of which represent industry.
Copies were mailed to six
environmental groups and three
consumer groups at the sam'e time, and
to a representative of the NGA. Copies
of the final background report for the
proposed list were sent to the
Governors, State and local air pollution
control agencies, NAPCTAC members,
environmental groups, the NGA, and
other requesters in July 1978.
The public comment period on the
proposed lish published in the August
31,1978, Federal Register, extended
through October 30,1978. There were 18
'comment letters received, 10 from
industry and 8 from various regulatory
agencies. Several comments resulted in
changes to the proposed priority list.
A public hearing was held on
September 29,1978, to discuss the
proposed priority list in accordance with
section lll(g)(8) of the Clean Air Act.
There were no written comments and
only one verbal statement resulting from
the public hearing.
Significant Comments and Changes to
the Proposed Priority List
As a result of public comments and
the availability of new screening studies
and reports, 34 major and 11 minor
source category data sets were
reevaluated. This reexamination
resulted in data changes for 29 major
and 9 minor source categories.
Ten source categories have been
removed from the proposed priority list.
Eight of these source category deletions
are a result of new data indicating that
NSPS would have little or no effect.
These source categories are: Varnish,
carbon black, explosives, acid sulfite
wood pulping, NSSC wood pulping.
gasoline additives manufacturing, alfalfa
dehydrating, and hydrofluoric acid
manufacturing. Printing ink
manufacturing was reclassified from a
major to a minor source category. In
addition, two source categories, gray
iron and steel foundries, were combined
fato one source category. Finally, fuel
conversion was removed from the list
due to uncertainties regarding the
approach and scheduled involved in
developing environmental standards for
the various processes. Likely candidates
for NSPS include coal gasification (both
low and high pressure), coal
liquefaction, and oil shale and tar sand
processing. These actions reduce the
final priority list to 59 source categories.
The most significant comments and
changes made to the proposed
regulations are discussed below:
1. Definition of "Mobility." Several
commenters felt that the treatment of
source category mobility (movability)
was too broad. Mobility in the
prioritization analysis refers to the
feasibility a stationary source has to
relocate to, or locate new facilities in,
areas with less stringent air pollution
control regulations. Non-movable
stationary source categories were
identified on the basis of being firmly
tied either to the market (e.g.. dry
cleaners) or to a supply of materials
(e.g., mining operations). The
Administrator recognizes that there are
many other factors which would be
considered in plant siting situations, but
considers the approach used in
determining the priority list sufficient for
the purposes of this study.
2. Source Category Aggregation.
Several commenters indicated that there
were discrepancies between the source
categories named in the priority list and
those in the background document. The
differences between the priority listing
in the Federal Register and the
background document list is a result of
aggregation of sources which had been
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
subcategorized for size classification
and priority ranking analysis in the
background document. Aggregation
indicates that all source categories
under a generic industry heading, such
as non-metallic mineral processing, will
be evaluated at the same time, although
this does not necessarily imply that a
single standard would apply to all
sources within the listed category.
3. Control Costs. Two commentere felt
that the cost of pollution control to meet
NSPS limitations should have been
included in the criteria for prioritization.
The Clean Air Act priority list criteria
do not include the cost of pollution
control, but pollution control costs were
considered during the determination of
control technology assumed for the
priority list study. Control costs are
examined in more detail during NSPS
development studies for each source
category, and must be considered in
determining each NSPS.
4. Minor Source Categories. One
commenter felt that the Administrator
lacks statutory authority to make a
policy decision to develop NSPS for a
minor source category until after the
major sources have been dealt with,
lince Congress indicated major sources
must be given priority. The
Administrator, in promulgating this list,
is placing an almost exclusive emphasis
on NSPS for major source categories.
However, the Clean Air Act does not
prohibit concurrent promulgation of
NSPS for minor, but significant, source
categories. For the three minor source
categories listed in this regulation, NSPS
development had been initiated before
the priority list was available, and
completion of standards development
for these sources is considered justified.
5. Stationary Fuel Combustion/Waste
Incineration. Two State agencies felt
that stationary fuel combustion and
waste incineration should have a high
priority because of source activity
growth in their respective States. In the
promulgated list, both of these source
categories are given high priority based
on the most recent growth rates
available. Given the concern expressed
by these agencies, the Administrator has
already initiated standard development
studies for these source categories.
6. Chemical Products Manufacture/
Fuel Conversion. One commenter felt
that the growth rate and, therefore, the
need for coal gasification plant NSPS is
overestimated. High Btu coal
gasification was reexamined; although
no commercial-scale plants currently
exist in this country, environmental
programs need to keep pace with the
emphasis on energy programs. The fuel
conversion processes have been
removed from the priority list for special
study.
7. Chemical Products Manufacture/
Printing Ink Manufacture. One
commenter indicated that neither
existing conditions within the printing
ink industry nor projections of future
growth of the industry justify its
categorization as a major source. The
Administrator has examined the new
data provided, and has reclassified
printing ink manufacturing plants as a
minor source category. As was
discussed earlier, however, the
Administrator may still develop
standards for "minor" source categories,
especially those which, in aggregate,
represent a significant quantity of
emissions.
8. Wood Processing/NSSC and Acid
Sulfite Pulping. One commenter
indicated that acid sulfite pulp
production is a declining growth
industry and therefore should not be
included in the priority list. The
Administrator agrees with this
comment, based on examination of acid
sulfite pulp production projections in a
new screening study. In addition, the
screening study indicates that NSSC
pulping is, in effect, controlled by the
promulgated NSPS for Kraft pulp mills,
resulting in little or no further emission
reduction from promulgation of an NSSC
NSPS. Therefore, both acid sulfite and
NSSC pulping have been removed from
the list.
Development of Standards
The Administrator has undertaken a
program to promulgate NSPS for the
source categories on this priority list by
August 7,1982. Development of
standards has already been initiated for
nearly two-thirds of the source
categories listed; work on the remaining
source categories will be initiated within
the next year.
The priority ranking is indicated by
the number to the left of each source
category and will be used to decide the
order in which new projects are
initiated, although this is not necessarily
an indication of the order in which
projects will be completed. In fact,
higher priority source categories often
present difficult technical and regulatory
problems, and may be among the later
source categories for which standards
are promulgated.
It should be pointed out that several
of the source categories listed could be
subject to standards which may be
adopted under section 112 of the Clean
Air Act, national emission standards for
hazardous air pollutants (NESHAP).
Included are byproduct coke ovens and
several source categories within the
petroleum transport and marketing
industry. If standards are developed
under section 112 for these or any other
source categories on the promulgated
list, then standards may not be
-developed for those source categories
under section 111.
Promulgation of this list not only
fulfills the section lll(f) requirements
concerning establishment of priorities,
but also constitutes notice that all
source categories on the priority list are
considered significant sources of air
pollution and are hereby listed in
accordance with section lll(b)(l)(A) 11
should be noted, however, that the
source categories identified on this
priority list, even though listed in
accordance with section lll(b)(l)(A),
are not subject to the provisions of
section lll(b)(l)(B), which would
require proposal of an NSPS for each
listed source category within 120 days of
adoption of the list. Rather, the
promulgation of standards for sources
contained on this priority list will be
undertaken in accordance with the time
schedule prescribed in section lll(f)(l)
of the Clean Air Act Amendments. That
is, NSPS for 25 percent of these source
categories are to be promulgated by
August 1980, 75 percent by August 1981,
and all of the NSPS by August 1982.
Dated August 15,1979.
Douglas M. Costle,
Administrator.
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
by adding § 60.16 to Subpart A as
follows:
§60.16 Priority list.
Prioritized Major Source Categories
Priority Number'
Source Category
1. Synthetic Organic Chemical Manufacturing
(a) Unit processes
(b) Storage and handling equipment
(c) Fugitive emission sources
(d) Secondary sources
2. Industrial Surface Coating Cans
3. Petroleum Refineries Fugitive Sources
4. Industrial Surface Coating Paper
5. Dry Cleaning
(a) Perchloroethylene
(b) Petroleum soKent
6. Graphic Arts
7. Polymers and Resins Acrylic Resins
B. Mineral Wool
9. Stationary Internal Combustion Engine-.
10. Industrial Surface Coating- Fabric
11. Fossil-Fuel-Fired Steam Generators
Industrial Boilers
12. Incineration: Non-Municipal
13. Non-Metallic Mineral Processing
14. Metallic Mineral Processing
' Low numbers have highest priority e g N
high priority. No 59 is low priority
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Federal Register / Vol. 44, No. 163 / Tuesday. August 21.1979 / Rules and Regulations
IS. Secondary Copper
16. Phosphate Rock Preparation
17. Foundriet: Steel and Gray Iron
18. Polymers and Resins: Polyethylene
19. Charcoal Production
10. Synthetic Rubber
(a) Tire manufacture
(bj SBR production
21. Vegetable Oil
22. Industrial Surface Coating: Metal Coil
23. Petroleum Transportation and Marketing
24. By-Product Coke Ovens
26. Synthetic Fibers
26. Plywood Manufacture
27. Industrial Surface Coating: Automobiles .
26. Industrial Surface Coating: Large
Appliances
29. Crude Oil and Natural Gas Production
30. Secondary Aluminum
31. Potash
32. Sintering: Clay and Fly Ash
33. Glass
34. Gypsum
35. Sodium Carbonate
36. Secondary Zinc
37. Polymers and Resins: Phenolic
38. Polymers and Resins: Urea—Melamme
39. Ammonia
40. Polymers and Resins: Polystyrene
41. Polymers and Resins: ABS-SAN Resins
42. Fiberglass
43. Polymers and Resins: Polypropylene
44. Textile Processing
45. Asphalt Roofing Plants
46. Brick and Related Clay Products
47. Ceramic Clay Manufacturing
48. Ammonium Nitrate Fertilizer
49. Castable Refractories
60. Borax and Boric Acid
51. Polymers and Resins Polyester Resins
52. Ammonium Sulfate
S3. Starch
54 Perlite
55. Phosphoric Acid: Thermal Process
56. Uranium Refining
57. Animal Feed Defluorination
SB. Urea (for fertilizer and polymers)
59. Detergent
Other Source Categories
Lead acid battery manufacture"
Organic solvent cleaning"
Industrial surface coating metal furniture"
Stationary gas turbines'"
(Sec. Ill, 301(a). Clean Air Act as amended
(42US.C. 7411. 7601))
|FR Doc 79-26656 Filed B-20-79. 8 45 am]
MLUNG COOt (MO-01-M
" Minor source category but included on list
unce an NSPS it being developed for that source
category
"' Not prioritized, since an NSPS for thit major
»oim.e category has alreadv been nronnwd
100
40 CFR Part 60
[FRL 1231-3]
Standards of Performance for New
Stationary Sources: Asphalt Concrete;
Review of Standards
AGENCY: Environmental Protection
Agency (EPA)
ACTION: Review of Standards.
SUMMARY: EPA has reviewed tjie
standard of performance for asphalt
concrete plants (40 CFR 60.9, Subpart I).
The review is required under the Clean
Air Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent not to undertake revision of
the standards at this time.
DATES: Comments must be received by
October 29,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention-
Docket No. A-79-04.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271. The document "A Review of
Standards of Performance for New
Stationary Sources—Asphalt Concrete"
(EPA-450/3-79-014) is available upon
request from Mr. Robert Ajax (MD-13),
Emission Standards and Engineering
Division, U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711.
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Federal Register / Vol. 44, No. 171 / Friday. August 31. 1979 / Rules and Regulations
SUPPLEMENTARY INFORMATION:
Background
In June 1973, EPA proposed a
standard under Section 111 of the Clean
Air Act to control participate matter
emissions from asphalt concrete plants.
The standard, promulgated on March 8,
1974, limits the discharge of particulate
matter into the atmosphere to a
maximum of 90 mg/dscm from any
affected facility. The standard also
limits the opacity of emissions to 20
percent. The standard is applicable to
asphalt concrete plants which
commenced construction or
modification after June 11,1973.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. Following adoption of the
Amendments, EPA contracted with the
MITRE Corporation to undertake a
review of the asphalt concrete industry
and the current standard. The MITRE
review was completed in January 1979.
Preliminary findings were presented to
and reviewed by the National Air
Pollution Control Techniques Advisory
Committee at its meeting in Alexandria,
Virginia, on January 10,1979. This notice
announces EPA's decision regarding the
need for revision of the standard.
Comments on the results of this review
and on EPA's decision are invited.
Findings
Overview of the Asphalt Concrete
Industry
The asphalt concrete industry consists
of about 4,500 plants, widely dispersed
throughout the Nation. Plants are
stationary (60 percent), mobile (20
percent), or transportable (20 percent),
i.e., easily taken down, moved and
reassembled. Types of plants include
batch-mix (91 percent), continuous mix
(6 5 percent), or dryer-drum mix (2.5
percent). The d-yer-drum plants, which
are becoming increasingly popular,
differ from the others in that drying of
the aggregate and mixing with the liquid
asphalt both take place in the same
rotary dryer. It is estimated that within
the next few years, dryer-drum plants
will represent up to 85 percent of all
plants under construction.
Current national production is about
263 to 272 million metric tons (MG)/
year, with a continued rise expected in
the future. It is estimated that
approximately 100 new and 50 modified
plants become subject to the standard
each year. Operation is seasonal, with
plants reportedly averaging 666 hours/
year although many operate more
extensively.
Particulate Matter Emissions and
Control Technology
The largest source of particulate
emissions is the rotary dryer. Both dry
(fabric filters) and wet (scrubbers)
collectors are used for control and are
both capable of achieving compliance
with the standard. However, all systems
of these types have not automatically
achieved control at or below the level of
the standard.
Based on data from a total of 72
compliance tests, it was found that 53 or
about three-fourths of the tests for
particulate emissions showed
compliance. Thirty-three of the 53
produced results between 45 and 90
MgVdscm (.02 and .04 gr/dscf). Of the 47
tests of fabric filters or venturi scrubber
controlled sources over 80 percent
showed compliance. The available data
do not provide details on equipment
design and an analysis of the cause of
failures has not been performed.
However, EPA is not aware of any
instances in which a properly designed
and installed fabric filter system or high-
efficiency scrubber has failed to achieve
compliance with the standard. The fact
that certian facilities controlled by
fabric filters and high-efficiency
scrubbers have failed to comply is
attributed to faulty design, installation,
and/or operation. This conclusion and
these data are consistent with data and
findings considered in the development
of the present standard.
On the basis of these findings, EPA
concludes that the present standard for
particulate matter is appropriate and
that no revision is needed.
Much less test data are available for
opacity than for particulates. Of the 26
tests for which opacity levels are
reported, only 5 failed to show
compliance with the opacity standard.
However, none of these 5 met the
standard for particulate matter. Of the
21 plants reported as meeting the
current standard for opacity, 19 met the
particulate standard. On the basis of
these data, EPA concludes that the
opacity standard is appropriate and
should not be revised. While the data do
indicate that a tighter standard may be
possible, the rationale and basis used to
establish the present standard are
considered to remain valid.
Enforcement of the Standard
Because the cost of performance tests
which are required to demonstrate
compliance with the standard are
essentially fixed and are independent of
plant size, this cost is disproportionately
high for small plants. Due to this, the
issue was raised as to whether formal
testing could be waived and lower cost,
alternative means be established for
determining compliance at small plants.
Support for such a waiver can be found
in the fact that emission rates are
generally lower at these plants and
errors in compliance determinations
would not be large in terms of absolute
emissions. However, testing costs at all
sizes of plants are small in relation to
the cost of asphalt concrete production
over an extended period and these costs
can be viewed as a legitimate expense
to be considered by an owner at the
time a decision to construct is made. A
number of State agencies presently
require, under SIP regulations, initial
and in some cases annual testing of
asphalt concrete plants. Moreover,
available compliance test data show
that performance of control devices is
variable and even with installation of
accepted best available control
technology the standard can be
exceeded by a significant degree if the
control system is not properly designed,
operated, and maintained. Relaxing the
requirement for formal testing thus
could lead to a proliferation of low
quality or marginal control equipment
which would require costly repair or
retrofit at a later time.
A further performance testing problem
indentified in the review of the standard
concerns operation at less than full
production capacity during a compliance
test. When this occurs, EPA normally
accepts the test result as a
demonstration of compliance at the
tested production rate, plus 23 Mg (25
tons)/hr. To operate at a higher
production rate, an owner or operator
must demonstrate compliance by testing
at that higher rate. Industry
representatives view this limitation as
an unfair production penalty. It is noted
in particular that reduced production is
sometimes an unavoidable consequence
associated with use of high moisture
content aggregate. Furthermore, it is
argued that facilities which show
compliance at the maximum production
rate associated with a given moisture
level can be assumed to comply at
higher production rates when moisture
is lower. However, this argument
assumes that the uncontrolled emission
rate from the facility does not increase
as production rate increases and EPA is
not aware of data ,o support this
assumption.
As a general policy it is EPA's intent
to minimize administrative costs
imposed on owners and operators by a
standard, to the maximum extent thdt
this can be done without sacrificing the
Agency's responsibility for assuring
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Federal Register / Vol. 44, No. 171 / Friday, August 31, 1979 / Rules and Regulations
compliance. Specifically, in the cases
cited above, EPA does not intend to
impose costly testing requirements on
small facilities or any facilities if
compliance with the standard can be
determined through less costly means.
However, EPA at this time is not aware
of a procedure which could be employed
at a significantly lower cost to
determine compliance with an
acceptable degree of accuracy. Although
opacity correlators with grain loading
and serves as a valid means for
identifying excess emissions, due to
dependence on stack diameter and other
factors opacity alone is not adequate to
accurately assess compliance with the
mass rate standard. Similarly, the
purchase and installation of a baghouse
or venturi scrubber does not in itself
necessarily imply compliance. EPA is
concerned that approval of such
equipment without compliance test data
or a detailed assessment of design and
operating factors would provide an
incentive for installation of low cost,
under-designed equipment. This would
place vendors of more costly systems
which are well designed and properly
constructed and operated at a
competitive disadvantage; in the long
term this would not only increase
emissions but would be to the detriment
of the industry.
EPA has, however, concluded that a
study program to investigate alternative
compliance test and administrative
approaches for asphalt plants is needed.
An EPA contractor working for the
Office of Enforcement has initiated a
study designed to assess several
administrative aspects of the standard,
including possible low cost alternative
test methods; administrative
mechanisms to deal with the problem of
process variability during testing; and
physical constraints affecting the ability
to perform tests. If the results of this
program, which is scheduled to be
completed later in 1979, show that the
regulations or enforcement policies can
be revised to lower costs, such revisions
will be adopted.
Hydrocarbon Emissions
While the principal pollutant
associated with asphalt concrete
production is particulate matter, the
trend noted previously toward dryer-
drum mix plants has raised question as
to the significance of hydrocarbon
emissions from these facilities. In the
dryer-drum mix plant, drying of the
aggregate as well as mixing with asphalt
and additional fines takes place within a
rotary drum. Because the drying takes
place within the same container as the
mixing, emissions are partly screened by
the curtain of asphalt added so that the
uncontrolled particulate emissions from
the dryer are lower than from
conventional plants. In contrast, it has
been reported that the rate of
hydrocarbon emissions may be
substantially higher than from
conventional plants. However, data
recently reported from one test in a
plant equipped with fabric filters
showed only traces of hydrocarbons in
dust and condensate and did not
support this suggestion. Thus, while
these data do not indicate a need to
revise the standard, more definitive data
are needed on hydrocarbon emission
rates and related process variables. This
has been identified as an area for
further research by EPA.
An additional source of hydrocarbon
emissions in the asphalt industry is the
use of cutback asphalts. Although not
directly associated with asphalt
concrete plants, this represents a
significant source of hydrocarbon
emissions. As such, the need for
possible standards of performance
pertaining to use of cutback asphalt was
rasied in this review. The term cutback
asphalt refers to liquified asphalt
products which are diluted or cutback
by kerosene or other petroleum
distillates for use as a surfacing
material. Cutback asphalt emits
significant quantities of hydrocarbons—
at a high rate immediately after
application and continuing at a
diminishing rate over a period of years.
It is estimated that over 2 percent of
national hydrocarbon emissions result
from use of cutback asphalt.
The substitution of emulsified
asphalts, which consist of asphalt
suspended in water containing an
emulsifying agent, for cutback asphalt
nearly eliminates the release of volatile
hydrocarbons from paving operations.
This substitute for petroleum distillate is
approximately 98 percent water and 2
percent emulsifiers. The water in
emulsified asphalt evaporates during
curing while the non-volatile emulsifier
is retained in the asphalt.
Because cutback asphalt emissions
result from the use of a product rather
than from a conventional stationary
source, the feasibility of a standard of
performance is unclear and the Agency
has no current plans to develop such a
standard. However, EPA has issued a
control techniques guideline document,
Control of Volatile Organic Compounds
from Use of Cutback Asphalt (EPA-450/
2-77-037) and is actively pursuing
control through the State
Implementation Plan process in areas
where control is needed to attain
oxidant standards. Because of area-to-
area differences in experience with
IV-337
emulsified asphalt, availability of
suppliers, and ambient temperatures, the
Agency believes that control can be
implemented effectively by the States.
Asphalt Recycling Plants
A process for recycling asphalt paving
by crushing up old road beds for
reprocessing through direct-fired asphalt
concrete plants has been recently
implemented on an experimental basis.
Plants using this process, which uses
approximately 20 to 30 percent virgin
material mixed with the recycled
asphalt, are subject to the standard and
at least two have demonstrated
compliance. However, preliminary
indications are that the process may
have difficulty in routinely attaining the
allowable level of particulate emissions
and/or that the cost of control may be
higher than a conventional process. The
partial combustion of the recycled
asphalt cement reportedly produces a
blue smoke more difficult to control than
the mineral dusts of plants using virgin
material.
It is EPA's conclusion that there is no
need at this time to revise the standard
as it affects recycling, due to its limited
practice and due to the data showing
that compliance can be achieved at
facilities which recycle asphalt.
However, this matter is being studies
further under the previously noted study
by an EPA contractor.
Educational Program for Owners and
Operators
The asphalt industry consists of a
large number of facilities which in many
cases are owned and operated by smaii
businessmen who are not trained or
experienced in the operation, design, or
maintenance of air pollution control
equipment. Because of this, the need to
comply with emission regulations, and
the changing technology in the industry
(i.e., the introduction of dryer-drum
plants, recycling, the possible move
toward coal as a fuel, and the use of
emulsions), the need for a training and
educational program for owners and
operators in the operation and
maintenance of air pollution control
equipment has been voiced by industry.
This offers the potential for cost and
energy savings along with reduced
pollution.
To meet this need, EPA's Office of
Enforcement, in cooperation with the
National Asphalt Paving Association,
conducted a series of workshops in 1978
for asphalt plant owners and operators.
Only limited future workshops are
currently planned. However, EPA will
consider expansion of the programs if a
continued need exists.
Dated: August 23,1979.
Douglas Costle,
Administrator
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Federal Register / Vol. 44. No. 176 / Monday, September 10.1979 / Rules and Regulations
101
40 CFR Part 60
[FRL 1276-2]
Standards of Performance for New
Stationary Sources; Gas Turbines
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which limit
emissions of nitrogen oxides and sulfur
dioxide from new, modified and
reconstructed stationary gas turbines.
The standards implement the Clean Air
Act and are based on the
Administrator's determination that
stationary gas turbines contribute
significantly to air pollution. The
intended effect of this regulation is to
require new, modified and reconstructed
stationary gas turbines to use the best
demonstrated system of continuous
emission reduction. _^
EFFECTIVE DATE: September 10,1979.
ADDRESSES: The Standards Support and
Environmental Impact Statement
(SSEIS) may be obtained from the U.S.
EPA Library (MD-35), Research Triangle
Park, North Carolina 27711 (specify
Standards Support and Environmental
Impact Statement, Volume 2:
Promulgated Standards of Performance
for Stationary Gas Turbines, EPA-450/
2-77-017b).
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone No. (919) 541-5271.
SUPPLEMENTARY INFORMATION:
The Standards
The promulgated standards apply to
all new, modified, and reconstructed
stationary gas turbines with a heat input
at peak load equal to or greater than
10.7 gigajoules per hour (about 1,000
horsepower). The standards apply to
simple and regenerative cycle gas
turbines and to the gas turbine portion
of a combined cycle steam/electric
generating system.
The promulgated standards limit the
concentration of nitrogen oxides (NO,)
in the exhaust gases from stationary gas
turbines with a heat input from 10.7 to
and including 107.2 gigajoules per hour
(about 1,000 to 10,000 horsepower), from
offshore platform gas turbines, and from
stationary gas turbines used for oil or
gas transportation and production not
located in a Metropolitan Statistical
Area (MSA), to 0.0150 percent by
volume (150 PPM) at 15 percent oxygen
on a dry basis. The promulgated
standards also limit the concentration of
NO, in the exhaust gases from
stationary gas turbines with a heat input
greater than 107.2 gigajoules per hour,
and from stationary gas turbines used
for oil or gas transportation and
production located in an MSA, to 0.0075
percent by volume (75 PPM) at 15
percent oxygen on a dry basis (see
Table 1 for summary of NO, emission
limits). Both of these emission limits (75
and 150 PPM) are adjusted upward for
gas turbines with thermal efficiencies
greater than 25 percent using an
equation included in the promulgated
standards. These emission limits are
also adjusted upward for gas turbines
burning fuels with a nitrogen content
greater than 0.015 percent by weight
using a fuel-bound nitrogen allowance
factor included in the promulgated
standards, or a "custom" fuel-bound
nitrogen allowance factor developed by
the gas turbine manufacturer and
approved for use by EPA. Custom fuel-
bound nitrogen allowance factors must
be substantiated with data and
approved for use by the Administrator
before they may be used for determining
compliance with the standards.
The promulgated NO, emission limits
are referenced to International Standard
Organization (ISO) standard day
conditions of 288 degrees Kelvin, 60
percent relative humidity, and 101.3
kilopascals (1 atmosphert) pressure.
Measured NO, emission levels,
therefore, are adjusted to ISO reference
conditions by use of an ambient
condition correction factor included in
the standards, or by a custom ambient
condition correction factor developed by
the gas turbine manufacturer and
approved for use by EPA. Custom
ambient condition correction factors can
only include the following variables:
combustor inlet pressure, ambient air
pressure, ambient air humidity, and
ambient air temperature. These factors
must be substantiated with data and
approved for use by the Administrator
before they may be used for determining
compliance with the standards.
Stationary gas turbines with a heat
input at peak load from 10.7 to, and
including, 107.2 gigajoules per hour are
to be exempt from the NO, emission
limit included in the promulgated
standards for five years from the date of
proposal of the standards (October 3,
1977). New gas turbines with this heat
input at peak load which are
constructed, or existing gas turbines
with this heat input at peak load which
are modified or reconstructed during
this five-year period do not have to
comply with the NO, emission limit
included in the promulgated standards
at the end of this period. Only those new
gas turbines which are constructed, or
existing gas turbines which are modified
or reconstructed, following this five-year
period must comply with the NOX
emission limit.
Emergency-standby gas turbines.
military training gas turbines, gas
turbines involved in certain research
and development activities, and
firefighting gas turbines are exempt from
compliance with the NO, emission limits
included in the promulgated standards
In addition, stationary gas turbines
•sing wet controls are temporarily
exempt from the NO, emission limit
during those periods when ice fog
created by the gas turbine is deemed by
(he owner or operator to present a
traffic hazard, and during periods of
drought when water is not available.
None of the exemptions mentioned
above apply to the sulfur dioxide (SO2)
emission limit. The promulgated
standards limit the SO2 concentration in
the exhaust gases from stationary gas
turbines with a heat input at peak load
of 10.7 gigajoules per hour or more to
0.015 percent by volume (150 PPM)
corrected to 15 percent oxygen on a dry
basis. The standards include an
alternative SO2 emission limit on the
sulfur content of the fuel of 0.8 percenl
sulfur by weight | see Table 1 for
summary of exemptions and SO?
emission limits).
Table 1.—Summary of Gas Turtine New Source Performance Standard
Gas turbrne size and usage
NO. emis-
sion hlTHI '
Applicability date lor
NO,
SOi emission limit
Applicability dale 101
SO,
Less than 10 7 gigajoules/hour (all uses)
None Standard does not
apply
Between 10 7 and 107 2 gigajoules/hour (all 150 ppm . October 3, 1882
uses)
None
Standard does nol
apply
150ppmSOjOt tnea Octobers 1977
fuel with less man
0.8% suHuf
Greater than or equal to 107 2
giga|oules/nour
1 Gas and ml transportation or produc- 150 ppm October 3,1877 Same as above October 3 197?
ton not located m an MSA
2 Gas and oil transportation or produc- 75 ppm October 3,1S77 Same as above . October 3 t977
ton located m an MSA
3. All other uses 75 ppm October 3, 1977 Same as above . October 3, 1977
Emergency standby, firefighting, military None... Standard does not Same as above . Octobers 1977
(except for garrison facility), military tram- apply
no, and research and development tur-
bines
' NO, emission limit adjusted upward for gas turbines with thermal efficiencies greater than 25 percenl and tor gas turbines
firing tueto with a nitrogen content of more than 0.015 weight percent Measured NO, emissions adjusted to ISO conditions IP
determining compliance with the NO, emission limit
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Environmental, Energy, and Economic
Impact
The promulgated standards will
reduce NO, emissions by about 190,000
tons per year by 1982 and by 400,000
tons per year by 1987. This reduction
will be realized with negligible adverse
solid waste and noise impacts.
The adverse water pollution impact
associated with the promulgated
standards will be minimal. The quantity
of water or steam required for injection
into the gas turbine to reduce NO,
emissions is less than 5 percent of the
water consumed by a comparable size
steam/electric power plant using cooling
towers. There will be no adverse water
pollution impact associated with those
gas turbines which employ dry NO,
control technology.
The energy impact associated with the
promulgated standards will be small.
Gas turbine fuel consumption could
increase by as much as 5 percent in the
worst cases. The actual energy impact
depends on the rate of water injection
necessary to comply with the
promulgated standards. Assuming the
"worst case," however, the standards
would increase fuel consumption of
large stationary gas turbines (i.e.,
greater than 10,000 horsepower) by
about 5,500 barrels of fuel oil per day in
1982. The standards would increase fuel
consumption of small stationary gas
turbines (i.e., less than 10,000
horsepower) by about 7,000 barrels of
fuel oil per day in 1987. This is
equivalent to an increase in projected
1982 and 1987 national crude oil
consumption of less than 0.03 percent.
As mentioned, these estimates are
based on "worst case" assumptions. The
actual energy impact of the promulgated
standard is expected to be much lower
than these estimates because most gas
turbines will not experience anywhere
near a 5 percent fuel penalty due to
water or steam injection. In addition,
many gas turbines will comply with the
standards using dry control, which in
most cases has no energy penalty.
The economic impact associated with
the promulgated standards is considered
reasonable. The Standards will increase
the capital costs or purchase price of a
gas turbine for most installations by
about 1 to 4 percent. The annualized
costs will be increased by about 1 to 4
percent, with the largest application.
utilities, realizing less than a 2 percent
increase.
The promulgated standards will
increase the total capital investment
requirements for users of large
stationary gas turbines by about 36
million dollars by 1982. For the period
1982 through 1987, the standards will
increase the capital investment
requirements for users of both large and
small stationary gas turbines by about
67 million dollars. Total annualized
costs for these users of stationary gas
turbines will be increased by about 11
million dollars in 1982 and by about 30
million dollars in 1987. These impacts
will result in price increases for the end
products or services provided by
industrial and commercial users of
stationary gas turbines ranging from less
than 0.01 percent in the petroleum
refining industry, to about 0.1 percent in
the electric utility industry.
Public Participation
Prior to proposal of the standards,
interested parties were advised by
public notice in the Federal Register of
meetings of the National Air Pollution
Control Techniques Advisory
Committee to discuss the standards
recommended for proposal. These
meetings occurred on February 21,1973;
May 30,1973; and January 9,1974. The
meetings were open to the public and
each attendee was given ample
opportunity to comment on the
standards recommended for proposal.
The standards were proposed and
published in the Federal Register on
October 3,1977. Public comments were
solicited at that time and, when
requested, copies of the Standards
Support and Environmental Impact
Statement (SSEIS) were distributed to
interested parties. The public comment
period extended from October 3,1977, to
January 31,1978.
Seventy-eight comment letters were
received on the proposed standards of
performance. These comments have
been carefully considered and, where
determined to be appropriate by the
Administrator, changes have been made
in the standards which were proposed.
Significant Comments and Changes to
the Proposed Regulation
Comments on the proposed standards
were received from electric utilities, oil
and gas producers, gas turbine
manufacturers, State air pollution
control agencies, trade and professional
associations, and several Federal
agencies. Detailed discussion of these
comments can be found in Volume 2 of
the SSEIS. The major comments can be
combined into the following areas:
general, emission control technology,
modification and reconstruction,
economic impacts, environmental
impacts, energy impacts, and test
methods and monitoring.
General
Small stationary gas turbines (i.e,
those with a heat input at peak load
between 10.7 and 107.2 gigajoules per
hour—about 1,000 to 10,000 horsepower)
are exempt from the standards for a
period of five years following the date of
proposal. Some commenters felt it was
not clear whether small gas turbines
would be required to retrofit NO,
emissions controls after the exemption
period ended. These commenters felt
this was not the intent of the standards
and they recommended that this point
be clarified.
The intent of both the proposed and
the promulgated standards is to consider
small gas turbines which have
commenced construction on or before
the end of the five year exemption
period as existing facilities. These
facilities will not have to retrofit at the
end of the exemption period. This point
has been clarified in the promulgated
standards.
Several commenters requested
exemptions for temporary and
intermittent operation of gas turbines to
permit research and development into
advanced combustion techniques under
full scale conditions.
This is considered a reasonable
request. Therefore, gas turbines
involved in research and development
for the purpose of improving combustion
efficiency or developing emission
control technology are exempt from the
NO, emission limit in the promulgated
standards. Gas turbines involved in this
type of research and development
generally operate intermittently and on
a temporary basis. The standards have
been changed, therefore, to allow
exemptions in such situations on a case-
by-case basis.
Emissions Control Technology
The selection of wet controls, or water
injection, as the best system of emission
reduction for stationary gas turbines
was criticized by a number of
commenters. These commenters pointed
out that although dry controls will not
reduce emissions as much as wet
controls, dry controls will reduce NOS
emissions without the objectionable
results of water injection (i.e., increased
fuel consumption and difficulty in
securing water of acceptable quality).
These commenters, therefore,
recommended postponement of
standards until dry controls can be
implemented on gas turbines.
As pointed out in Volume 1 of the
SSEIS, a high priority has been
established for control of NO,
emissions. Wet and dry controls are
considered the only viable alternative
control techniques for reducing NO,
emissions from gas turbines. Control of
NO, emissions by either of these two
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alternatives clearly favored the
development of the standards of
performance based on wet controls from
an environmental viewpoint. Reductions
in NO, emissions of more than 70
percent have been demonstrated using
wet controls on many large gas turbines
used in utility and industrial
applications. Thus, wet controls can be
applied immediately to large gas
turbines, which account for 85-90
percent of NOX emissions from gas
turbines.
The technology of wet control is the
same for both large and small gas
turbines. The manufacturers of small gas
turbines, however, have not
experimented with or developed this
technology to the same extent as the
manufacturers of large gas turbines. In
addition, small gas turbines tend to be
produced or more of an assembly line
basis than large gas turbines.
Consequently, the manufacturers of
small gas turbines need a lead time of
five years (based on their estimates) to
design, test, and incorporate wet
controls on small gas turbines.
Even with a five-year delay in
application of standards to small gas
turbines, standards of performance
based on wet controls will reduce
national NO, emissions by about 190,000
tons per year by 1982. Therefore, the
reduction in NO, emissions resulting
from standards based on wet controls is
significant.
Dry controls have demonstrated NO,
emissions reduction of only about 40
percent in laboratory and combustor rig
tests. Because of the advanced state of
research and development into dry
control by the manufacturers of large
gas turbines, the much longer lead time
involved in ordering large gas turbines,
and the greater attention that can be
given to "custom" engineering designs of
large gas turbines, dry controls can be
implemented on large gas turbines
immediately. Manufacturers of small gas
turbines, however, estimate that it
would take them as long to incorporate
dry controls as wet controls on small
gas turbines. Basing the standards only
on dry controls, therefore, would
significantly reduce the amount of NO,
emission reductions achieved.
The economic impact of standards
based on wet controls is considered
reasonable for large gas turbines. (See
Economic Impact Discussion.) Thus, wet
controls represent ". . . the best system
of continuous emission reduction . . .
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements). . ."
for large gas turbines.
The economic impact of standards
based on wet controls, however, is
considered unreasonable for small gas
turbines, gas turbines located on
offshore platforms, and gas turbines
employed in oil or gas production and
transportation which are not located in
a Metropolitan Statistical Area. The
economic impact of standards based on
dry controls, on the other hand, is
considered reasonable for these gas
turbines. (See Economic Impact
Discussion.) Thus, dry controls
represent ". . . the best system of
continuous emission reduction . . .
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements). . ."
for small gas turbines, gas turbines
located on offshore platforms, and gas
turbines employed in oil or gas
production and transportation which are
not located in a Metropolitan Statistical
Area.
Volume 1 of the SSE1S summarizes the
data and information available from the
literature and other nonconfidential
sources concerning the effectiveness of
dry controls in reducing NO, emissions
from stationary gas turbines. More
recently, additional data and
information have been published in the
Proceedings of the Third Stationary
Source Combustion Symposium (EPA-
600/7-79-050C). Advanced Combustion
Systems for Stationary Gas Turbines
(interim report) prepared by the Pratt
and Whitney Aircraft Group for EPA
(Contract 68-02-2136), "Experimental
Clean Combustor Program Phase III"
(NASA CR-135253) also prepared by the
Pratt and Whitney Aircraft Group for
the National Aeronautics and Space
Administration (NASA), and "Aircraft
Engine Emissions" (NASA Conference
Publication 2021). These data and
information show that dry controls can
reduce NO, emissions by about 40
percent. Multiplying this reduction by a
typical NO, emission level from an
uncontrolled gas turbine of about 250
ppm leads to an emission limit for dry
controls of 150 ppm. This, therefore, is
the numerical emission limit included in
the promulgated standards for small gas
turbines, gas turbines located on
offshore platforms, and gas turbines
employed in oil or gas production or
transportation which are not located in
Metropolitan Statistical Areas.
The five-year delay from the date of
proposal of the standards in the
applicability date of compliance with
the NO, emission limit for small gas
turbines has been retained in the
promulgated standards. As discussed
above, manufacturers of small gas
turbines have estimated that it will take
this long to incorporate either wet or dry
controls on these gas turbines.
Several commenters criticized the
fuel-bound nitrogen allowance included
in the proposed standards. It was felt
that greater flexibility in the equations
used to calculate the fuel-bound
nitrogen NO, emissions contribution
should be permitted, due to the limited
data on conversion of fuel-bound
nitrogen to NO,. These commenters
recommended that manufacturers of gas
turbines be allowed to develop their
own fuel-bound nitrogen allowance.
As discussed in Volume I of the
SSEIS, the reaction mechanism by which
fuel-bound nitrogen contributes to NOX
emissions is not fully understood. In
addition, emission data are limited with
respect to fuels containing significant
amounts of fuel-bound nitrogen. The
problem of quantifying the fuel-bound
nitrogen contribution to total NO,
emissions is further complicated by the
fact that the amount of nitrogen in the
fuel has an effect on this contribution.
In light of this sparsity of data, the
commenters' recommendations seem
reasonable. Therefore, a provision has
been added to the standards to allow
manufacturers to develop custom fuel-
bound nitrogen allowances for each gas
turbine model. The use of these factors,
however, must be approved by the
Administrator before the initial
performance test required by Section
60.8 of the General Provisions. Petitions
by manufacturers for approval of the use
of custom fuel-bound nitrogen
allowance factors must be supported by
data which clearly provide a basis for
determining the contribution of fuel-
bound nitrogen to total NO, emissions.
In addition, in no case will EPA approve
a custom fuel-bound nitrogen allowance
factor which would permit an increase
in NO, emissions of more than 50 ppm.
(See Energy Impact Discussion.) Notice
of approval of the use of these factors
for various gas turbine models will be
given in the Federal Register.
Modification and Reconstruction
Some commenters felt that existing
gas turbines which now burn natural gas
and are subsequently altered to burn oil
should be exempt from consideration as
modifications. The high cost and
technical difficulties of compliance with
the standards would discourage fuel
switching to conserve natural gas
supplies.
As outlined in the General Provisions
of 40 CFR Part 60, which are applicable
to all standards of performance, most
changes to an existing facility which
result in an increase in emission rate to
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the atmosphere are considered
modifications. However, according to
section 60.14(e)(4) of the General
Provisions, the use of an alternative fuel
or raw material shall not be considered
a modification if the existing facility
was designed to accommodate that
alternative use. Therefore, if a gas
turbine is designed to fire both natural
gas and oil, then switching from one fuel
to the other would not be considered a
modification even if emissions were
increased. If a gas turbine that is not
designed for firing both fuels is switched
from firing natural gas to firing oil,
installation of new injection nozzles
which increase mixing to reduce NO,
production, or installation of new NO,
combustors currently on the market,
would in most cases maintain emissions
at their previous levels. Since emissions
would not increase, the gas turbine
would not be considered modified, and
the real impact of the standards on gas
turbines switching from natural gas to
oil will probably be quite small.
Therefore, no special provisions for fuel
switching have been included in the
promulgated standards.
Economic Impact
Several commenters stated that water
injection could increase maintenance
costs significantly. One reason cited
was that chemicals and minerals in the
water would likely be deposited on
internal surfaces of gas turbines, such as
turbine blades, leading to downtime for
repair and cleaning. In addition, the
commenters felt that higher
maintenance requirements could be
expected due to the increased
complexity of a gas turbine with water
injection.
As pointed out in Volume 1 of the
SSE1S, to avoid deposition of chemicals
and minerals on gas turbine blades, the
water used for water injection must be
treated. Costs for water treatment were
included in the overall costs of water
injection and, for large gas turbines,
these costs are considered reasonable.
Actual maintenance and operating
costs for gas turbines operating with
water or steam injection are limited.
Several major utilities, however, have
accumulated significant amounts of
operating time on gas turbines using
water or steam injection for control of
NO, emissions. There have been some
problems attributable to water or steam
injection, but based on the data
available, these problems have been
confined to initial periods of operation
of these systems. Most of these reported
problems such as turbine blade damage,
flame-outs, water hammer damage, and
ignition problems, were easily corrected
by minor redesign of the equipment
hardware. Because of the knowledge
gained from these systems, such
problems should not arise in the future.
As mentioned, some utilities have
accumulated substantial operating
experience without any significant
increase in maintenance or operating
costs or other adverse effects. One
utility, for example, has used water
injection on two gas turbines for over
55,000 hours without making any major
changes to their normal maintenance
and operating procedures. They
followed procedures essentially
identical to those required for a similar
gas turbine not using water injection,
and the plant experienced no outages
attributable to the water injection
system. Another company has
accumulated over 92,000 hours of
operating time with water injection on
17 gas turbines with approximately 116
hours of outage attributable to their
water injection system. Increased
maintenance costs which can be
attributed to these water injection
systems are not available, as such costs
were not accounted for separately from
normal maintenance. However, they
were not reported as significant.
Some commenters exresssed the
opinion that the cost estimates for
controlling NO, emissions from large
gas turbines were too low. Accordingly,
these commenters felt that wet control
technology should not be the basis of
the standards for large stationary gas
turbines.
The costs associated with wet control
technology for large gas turbines were
reassessed. In a few cases, it appeared
the water-to-fuel ratio used in Volume 1
of the SSEIS was somewhat low. In
these cases, the capital and annualized
operating costs associated with wet
control on large gas turbines were
revised to reflect injection of more water
into the gas turbine. None of these
revisions, however, resulted in a
significant change in the projected
economic impact of wet controls on
large gas turbines. Thus, depending on
the size and end use of large gas
turbines, wet controls are still projected
to increase capital and annualized
operating costs by no more than 1 to 4
percent. Increases of this order of
magnitude are considered reasonable in
light of the 70 percent reduction in NO,
emissions achieved by wet controls.
Consequently, the basis of the
promulgated standards for large gas
turbines remains the same as that for
the proposed standards—wet controls.
A number of commenters also
expressed the opinion that the cost
estimates for wet controls to reduce NO,
emissions from small gas turbines were
too low. Therefore, the standards for
small gas turbines should not be based
on wet controls.
Information included in the comments
submitted by manufacturers of small gas
turbines indicated the costs of
redesigning these gas turbines for water
injection are much greater than those
included in Volume 1 of the SSEIS.
Consequently, it appears the costs of
water injection would increase the
capital cost of small gas turbines by
about 16 percent, rather than about 4
percent as originally estimated. Despite
this increase in capital costs, it does not
appear water injection would increase
the annualized operating costs of small
gas turbines by more than 1 to 4 percent
as originally estimated, due to the
predominance oT fuel costs in operating
costs. An increase of 16 percent in the
capital cost of small gas turbines,
however, is considered unreasonable.
Very little information was presented
in Volume 1 of the SSEIS concerning the
costs of dry controls. The conclusion
was drawn, however, that these costs
would undoubtedly be less than those
associated with wet controls.
Little information was also included in
the comments submitted by the
manufacturers of small gas turbines
concerning the costs of dry controls.
Most of the cost information dealt with
the costs of wet controls. One
manufacturer, however, did submit
limited information which appears to
indicate that the capital cost impact of
dry controls on small gas turbines might
be only a quarter of that of wet controls.
Thus, dry controls might increase the
capital costs of small gas turbines by
only about 4 percent. The potential
impact of dry controls on annualized
operating costs would certainly be no
greater than wet controls, and would
probably be much less. Consequently, it
appears dry controls might increase the
capital costs of small gas turbines by
about 4 percent and the annualized
operating costs by about 1 to 4 percent.
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The magnitude of these impacts is
essentially the same as those originally
associated with wet controls in Volume
1 of the SSEIS, and they are considered
reasonable. Consequently, the basis of
the promulgated standards for small gas
turbines is dry controls.
A number of commenters stated that
the costs associated with wet controls
on gas turbines located on offshore
platforms, and in arid and remote
regions were unreasonable. These
commenters felt that the costs of
obtaining, transporting, and treating
water in these areas prohibited the use
of water injection.
As mentioned by the commenters, the
costs associated with water injection on
gas turbines in these locations are all
related to lack of water of acceptable
quality or quantity. Review of the costs
included in Volume 1 of the SSEIS for
water injection on gas turbines located
on offshore platforms, indicates that the
required expenditures for platform
space were not incorporated into these
estimates. Based on information
included in the comments, platform
space is very expensive, and averages
approximately $400 per square foot.
When this cost is included, the use
water treatment systems to provide
water for NO, emissions control would
increase the capital costs of a gas
turbine located on an offshore platform
by approximately 33 percent. This is
considered an unreasonable economic
impact.
Dry controls, unlike wet controls,
would not require additional space on
offshore platforms. Although most gas
turbines located on offshore platforms
would be considered small gas turbines
under the standards, it is possible that
some large gas turbines might be located
on offshore platforms. Therefore, all the
information available concerning the
costs associated with standards based
on dry controls for large gas turbines
was reviewed.
Unfortunately, no additional
information on the costs of dry controls
was included in the comments
submitted by the manufacturers of large
gas turbines. As mentioned above, the
information presented in Volume 1 of
the SSEIS is very limited concerning the
costs of dry controls, although the
conclusion is drawn that these costs
would undoubtedly be less than the
costs of wet controls. It also seems
reasonable to assume that the costs of
dry controls on large gat turbines would
certainly be less than the costs of dry
controls on small gas turbines.
Consequently, standards based on dry
controls should not increase the capital
and annualized operating costs of large
gas turbines by more than the 1 to 4
percent projected for small gas turbines.
This conclusion even seems
conservative in light of the projected
increase in capital and annualized
operating costs for wet controls on large
gas turbines of no more than 1 to 4
percent. In any event, the costs of
standards based on dry controls for
large gas turbines are considered
reasonable. Therefore, the promulgated
standards for gas turbines located on
offshore platforms are based on dry
controls.
In many arid and remote regions, gas
turbines would have to obtain water by
trucking, installing pipelines to the site,
or by construction of large water
reservoirs. While costs included in
Volume 1 of the SSEIS do not show
trucking of water to gas turbine sites to
be unreasonable, these costs are not
based on actual remote area conditions.
That is, these costs are based on paved
road conditions and standard ICC
freight rates. Gas turbines located in
arid and remote regions, however, are
not likely to have good access roads.
Consequently, it is felt that the costs of
trucking water, laying a water pipeline,
or constructing a water reservoir would
be unreasonable for most arid and
remote areas.
As discussed above, the economic
impact of standards based on dry
controls for both large and small gas
turbines in considered reasonable.
Consequently, provisions have been
included in the promulgated standards
which essentially require gas turbines
located in arid and remote areas to
comply with an NO, emission limit
based on the use of dry controls. A
number of options were considered
before the specific provisions included
in the promulgated standards were '
selected.
The first option considered was
defining the term "arid and remote."
While this is conceptually
straightforward, it proved impossible to
develop a satisfactory definition for
regulatory purposes. The second option
considered was defining all gas turbines
located more than a certain distance
from an adequate water supply as "arid
and remote" gas turbines. Defining the
distance and an adequate water supply,
however, proved as impossible as
defining the term "arid and remote." The
third option considered was a case-by-
case exemption for gas turbines where
the costs of wet controls exceeded
certain levels. This option, however,
would provide incentive to owners and
operators to develop grossly inflated
costs to justify exemption and would
require detailed analysis of each case on
the part of the Agency to insure this did
not occur. In addition, the numerous
disputes and disagreements which
would undoubtedly arise under this
option would lead to delays and
demands on limited resources within
both the Agency and industry to resolve.
Analysis of the end use of most gas
turbines located in arid and remote
regions gave rise to a fourth option.
Generally, gas turbines located in arid
or remote regions are used for either oil
and gas production, or oil and gas
transportation. Consequently, the
promulgated standards require gas
turbines employed in oil and gas
production or oil and gas transportation,
which are not located in a Metropolitan
Statistical Area [MSA), to meet an NO,
emission limit based on the use of dry
controls. The promulgated standards,
however, require gas turbines employed
in oil and gas production or oil and gas
transportation which are located in a
MSA to meet the 75 ppm NO, emission
limit. This emission limit is based on the
use of wet controls and in an MSA a
suitable water supply for water injection
will be available.
Environmental Impact
A number of commenters felt gas
turbines used as "peaking" units should
be exempt. Peaking units operate
relatively few hours per year. According
to commenters, use of water injection
would result in a very small reduction in
annual NO, emissions and negligible
improvement in .ground level
concentrations.
As pointed out in Volume 1 of the
SSEIS, about 90 percent of all new gas
turbine capacity is expected to be
installed by electric utility companies to
generate electricity, and possibly as
much as 75 percent of all NO, emissions
from stationary gas turbines are emitted
from these installations. Of these
electric utility gas turbines, a large
majority are used to generate power
during periods of peak demand.
Consequently, by their very nature,
peaking gas turbines tend to operate
when the need for emission control is
greatest, that is, when power demand is
highest and air quality is usually at its
worst. Therefore, it does not seem
reasonable to exempt peaking gas
turbines from compliance with the
standards.
A number of commenters also ftlt that
small gas turbines should be exempt
from the standards because they emit
only about 10 percent of the total NO,
emissions from all stationary gas
turbines and therefore, the
environmental impact of not regulating
these turbines would be small.
A high priority has been established
for NO, emission control and dry control
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techniques are considered a
demonstrated and economically
reasonably means for reducing NO,
emissions from small gas turbines.
Therefore, the promulgated standards
limit NO, emissions from small gas
turbines to 150 ppm based on the use of
dry control technology.
Energy Impact
A number of writers commented on
the potential impact of the standards on
the use of the oil-shale, coal-derived,
and other synthetic fuels. It was
generally felt that these types of fuels
should not be covered by the the
standards at this time, since this could
hinder their development.
Total NO, emissions from any
combustion source, including stationary
gas turbines, are comprised of thermal
NOE and organic NO,. Thermal NO, is
formed in a well-defined high
temperature reaction between oxygen
and nitrogen in the combustion air.
Organic NO, is produced by the
combination of fuel-bound nitrogen with
oxygen during combustion in a reaction
that is not yet fully understood. Shale
oil, coal-derived, and other synthetic
fuels generally have high nitrogen
contents and, therefore, will produce
relatively high organic NO, emissions
when combusted.
Neither wet nor dry control
technology for gas turbines is effective
in reducing organic NO, emissions. As
discussed in Volume I of the SSEIS, as
fuel-bound nitrogen increases, organic
NO, emissions from a gas turbine
become the predominant fraction of
total NO l, emissions. Consequently,
emission standards must address in
some manner the contribution to NO,
emissions of fuel-bound nitrogen.
Low nitrogen fuels, such as premium
distillate fuel oil and natural gas, are
now being fired in nearly all stationary
gas turbines. Energy supply
considerations, however, may cause
more gas turbines to fire heavy fuel oils
and synthetic fuels in the future. A
standard based on present practice of
firing low nitrogen fuels, therefore,
would too rigidly restrict the use of high
nitrogen fuel, especially in light of the
uncertainty in world energy markets.
Since control technology is not in
reducing organic NO, emissions from
gas turbines, the possibility of basing
standards on removal of nitrogen from
the fuel prior to combustion was
considered. The cost of removing
nitrogen from fuel oil, however, ranges
from $2.00 to $3.00 per barrel. Another
alternative considered was exempting
gas turbines using high nitrogen fuels, as
some commenters requested. Exempting
gas turbines based on the type of fuel
used, however, would not require the
use of beat control technology in all
cases.
A third alternative considered was the
use of a fuel-bound nitrogen allowance.
Beyond some point it is simply not
reasonable to allow combustion of high
nitrogen fuels in gas turbines. In
addition, high nitrogen fuels, including
shale oil and coal-derived fuels, can be
used in other combustion devices where
some control of organic NO, emissions
is possible. Greater reduction of
nationwide NO, emissions could be
achieved by utilizing these fuels in
facilities where organic NO, emission
control is possible than in gas turbines
where organic NO, emissions are
essentially uncontrolled. This approach,
therefore, balances the trade-off
between allowing unlimited selection of
fuels for gas turbines controlling NO,
emissions.
A limited fuel-bound nitrogen
allowance which would allow increased
NO, emissions above the numerical NO,
emissions limits including in the
promulgated standards seems most
reasonable. An upper limit on this
allowance of 50 ppm NO, was selected.
Such a limit would allow approximately
50 percent of existing heavy fuel oils to
be fired in stationary gas turbines. (See
Volume I of the SSEIS.) This approach is
considered a reasonable means of
allowing flexibility hi the selection of
fuels while achieving reductions hi NO,
emissions from stationary gas turbines.
(See Control Technology for further
discussion.)
A number of commenters felt the
efficiency correction factor included to
the standards should use the overall
efficiency of a gas turbine installation
rather than the thermal efficiency of the
gas turbine itself. For example, many
commenters recommended that the
overall efficiency of a combined cycle
gas turbine installation be used in this
correction factor.
Section 111 of the Clean air Act
requires that standards of performance
for new sources reflect the use of the
best system of emission reduction. With
the few exceptions noted above, water
injection is considered the best system
of emission control for reducing NO,
emissions from stationary gas turbines.
To be consistent with the intent of
section 111, the standards must reflect
the use of water injection independent
of any ancillary waste heat recovery
equipment which might be associated
with a gas turbine to increase its overall
efficiency. To allow an upward
adjustment in the NO, emission limit
based on the overall efficiency of a
combined cycle gas turbine could mean
that water injection might not have to be
applied to the gas turbine. Thus, the
standards would not reflect the use of
the best system of emission reduction.
Therefore, the efficiency factor must be
based on the gas turbine efficiency
itself, not the overall efficiency of a gas
turbine combined with other equipment.
Test Methods and Monitoring
A large number of commenters
objected to the amount of monitoring
required. The proposed standards called
for daily monitoring of sulfur content,
nitrogen content and lower heating
value of the fuel The commenters were
generally in favor of less frequent
periodic monitoring.
These comments seem reasonable.
Therefore, the standards have been
changed to permit determination of
sulfur content, nitrogen content, and
lower heating value only when a fresh
supply of fuel is added to the fuel
storage facilities for a gas turbine.
Where gas turbines are fueled without
intermediate storage, such as along oil
and gas transport pipelines, daily
monitoring is still required by the
standards unless the owner or operator
can show that the composition of the
fuel does not fluctuate significantly. In
these cases, the owner or operator may
develop an individual monitoring
schedule for determining fuel sulfur
content nitrogen content and lower
heating value. These schedules must be
substantiated by data and submitted to
the Administrator for approval on a
case-by-case basis.
Several commenters stated that the
standards should be clarified to allow
the performance test to be performed by
the gas turbine manufacturer in lieu of
the owner/operator. To simplify
verification of compliance with the
standards and to reduce costs to
everyone involved, the recommendation
was made that each gas turbine be
performance tested at the
manufacturer's site. The commenters
maintained that gas turbines should not
be required to undergo a performance
test at the owner/operator's site if they
have been shown to comply with the
standard by the gas turbine
manufacturer.
Section 111 of the Clean Air Act is not
flexible enough to permit the use of a
formal certification program such as that
described by the commenter.
Responsibility for complying with the
standards ultimately rests with the
owner/operator, not with the gas turbine
manufacturers. The general provisions
of 40 CFR Part 60, however, which apply
to all standards of performance, allow
the use of approaches other than
performance tests to determine
compliance on a case-by-case basis. The
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alternate approach must demonstrate to
the Administrator's satisfaction that the
facility is in compliance with the
standard. Consequently, gas turbine
manufacturers' tests may be considered,
on a case-by-case basis, in lieu of
performance tests at the owner/
operator's site to demonstrate
compliance with the standards. For a
gas turbine manufacturers^ test to be
acceptable in lieu of a performance test,
as a minimum the operating conditions
of the gas turbine at the installation site
would have to be shown to be similar to
those during the. manufacturer's test In
addition, this would not preclude the
Administrator from requiring a
performance test at any time to
demonstrate compliance with the
standards.
Miscellaneous
It should be noted that standards of
performance for new stationary sources
established under section 111 of the
Clean Air Act reflect:
". . . application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environment
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, [section lll(a)(l)]
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
a more stringent emission standard in
several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources located in
nonattainment areas, i.e., those areas
where statutorily mandated health and
welfare standards are being violated. In
this respect, section 173 of the act
requires that a new or modified source
constructed in an area which exceeds
the National Ambient Air Quality
Standard (NAAQS) must reduce
emissions to the level which reflects the
"lowest achievable emission rate"
(LAER), as defined in section 171(3), for
such category of source. The statute
defines LAER as that rate of emission
which reflects:
(A) 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
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source,
whichever is more stringent
In no event can the emission rate
exceed any applicable new source
performance standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (part C). These provisions
require that certain sources (referred to
in section 169(1)) employ "best available
control technology" (as defined in
section 169(3)) for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all events, State implementation
plans (SIPs) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIPs must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
This regulation will be reviewed 4
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emissions control technology.
No economic impact assessment
under Section 317 was prepared on this
standard. Section 317(a) requires such
an assessment only if "the notice of
proposed rulemaking in connection with
such standard ... is published in the
Federal Register after the date ninety
days after August 7,1977." This
standard was proposed in the Federal
Register on October 3,1977, less than
ninety days after August 7,1977, and an
assessment was therefore not required.
Dated: August 28.1979.
Douglas M. Costle,
Administrator,
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
1. By adding subpart GG as follows:
Subpart GG—Standard* of performance for
Stationary Gas Turbines
Sec.
60.330 Applicability and designation of
affected facility.
60.331 Definitions.
60.332 Standard for nitrogen oxides.
60.333 Standard for sulfur dioxide.
60.334 Monitoring of operations.
60.335 Test methods and procedures.
Authority: Sees. Ill and 301 (a) of the Clean
Air Act, as amended, [42 U.S.C. 1857c-7,
1857g(a)], and additional authority as noted
below.
Subpart GG—Standards of
Performance for Stationary Gas
Turbines
S 60.330 Applicability and designation of
affected facility.
The provisions of this subpart are
applicable to the following affected
facilities: all stationary gas turbines
with a heat input at peak load equal to
or greater than 10.7 gigajoules per hour,
based on the lower heating value of the
fuel fired.
S 60.331 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Stationary gas turbine" means
any simple cycle gas turbine,
regenerative cycle gas turbine or any
gas turbine portion of a combined cycle
steam/electric generating system that is
not self propelled. It may, however, be
mounted on a vehicle for portability.
(b) "Simple cycle gas turbine" means
any stationary gas turbine which does
not recover heat from the gas turbine
exhaust gases to preheat the inlet
combustion air to the gas turbine, or
which does not recover heat from the
gas turbine exhaust gases to heat water
or generate steam.
(c) "Regenerative cycle gas turbine"
means any stationary gas turbine which
recovers heat from the gas turbine
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exhaust gases to preheat the inlet
combustion air to the gas turbine.
(d) "Combined cycle gas turbine"
means any stationary gas turbine which
recovers heat from the ga* turbine
exhaust gases to heat water or generate
steam.
(e) "Emergency gas turbine" means
any stationary gas turbine which
operates as a mechanical or electrical
power source only when the primary
power source for a facility has been
rendered inoperable by an emergency
situation.
(f) "Ice fog" means an atmospheric
suspension of highly reflective ice
crystals.
(g) "ISO standard day conditions"
means 288 degrees Kelvin, 60 percent
relative humidity and 101.3 kilopascals
pressure.
(h) "Efficiency" means the gas turbine
manufacturer's rated heat rate at peak
load in terms of heat input per unit of
power output based on the lower
heating value of the fuel.
(i) "Peak load" means 100 percent of
the manufacturer's design capacity of
the gas turbine at ISO standard day
conditions.
0) "Base load" means the load level at
which a gas turbine is normally
operated.
(k) "Fire-fighting turbine" means any
stationary gas turbine that is used solely
to pump water for extinguishing fires.
(!) "Turbines employed in oil/gas
production or oil/gas transportation"
means any stationary gas turbine used
to provide power to extract crude oil/
natural gas from the earth or to move
crude oil/natural gas, or products
refined from these substances through
pipelines.
(m) A "Metropolitan Statistical Area"
or "MSA" as defined by the Department
of Commerce.
(n) "Offshore platform gas turbines"
means any stationary gas turbine
located on a platform in an ocean.
(o) "Garrison facility" means any
permanent military installation.
(p) "Gas turbine model" means a
group of gas turbines having the same
nominal air flow, combuster inlet
pressure, combuster inlet temperature,
firing temperature, turbine inlet
temperature and turbine inlet pressure.
§60.332 Standard for nitrogen oxides.
(a) On and after the date on which the
performance test required by § 60.8 is
completed, every owner or operator
subject to the provisions of this subpart,
as specified in paragraphs (b), (c), and
(d) of this section, shall comply with one
of the following, except as provided in
paragraphs (e), (f), (g), (h), and (i) of this
section.
(1) No owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the
atmosphere from any stationary gas
turbine, any gases which contain
nitrogen oxides in excess of:
(14 4)
STD = 0.0075 + p
32
where:
STD=aBowable NO, emissions (percent by
volume at 15 percent oxygen and on a
dry basis).
Y= manufacturer's rated heat rate at
manufacturer's rated load [kilojoules per
watt how) or, actual measured heat rate
based on lower heating value of fuel as
measured at actual peak load for the
facility. The value of Y shall not exceed
14.4 kilojoules per watt hour.
F=NO, emission allowance for fuel-bound
nitrogen as defined in part (3) of this
paragraph.
t2) No owner or operator subject to the
provisions of this subpart shall cause to be
discharged into the atmosphere from any
stationary gas turbine, any gases which
contain nitrogen oxides in excess of:
STD = 0.0150 (-) + F
where:
STD=allowable NO, emissions (percent by
Toiume at 15 percent oxygen and on a
dry basis).
Y = manufacturer's rated heat rate at
manufacturer'i rated peak load
(kilajoules per watt hour), or actual
measured heat rate based on lower
heating value of fuel as measured at
actual peak load for the facility. The
value of Y shall not exceed 14.4
kilojoules per watt hour.
F=NO, emission allowance for fuel-bound
nitrogen as defined in part (3) of this
paragraph.
(3) F shall be defined according to the
nitrogen content of the fuel as follows:
Fuel-Bound Nitrogen F
(percent by neigM) {NO percent by »olume)
N < 0 0)5
0 015 < H < 0 1
0 1 « N ; 0 ?5
N > 0.25
0 04(M)
0.004 •• 0 0067(N-O.I)
0.005
where:
N = the nitrogen content of the fuel (percent
by weight).
Manufacturers may develop custom
fuel-bound nitrogen allowances for each
ga* turbine model they manufacture.
These fuel-bound nitrogen allowances
shall be substantiated with data and
must be approved for use by the
Administrator before the initial
performance test required by 5 60.8.
Notices of approval of custom fuel-
bound nitrogen allowances will be
published in the Federal Register.
(b) Stationary gas turbines with a heat
input at peak loed greater than 107.2
gigajoules per hour (100 million Btu/
hour] based on the lower heating value
of the fuel fired except as provided in
§ 60.332(d) shall comply with the
provisions of § 60.332(a)(l).
(c) Stationary gas turbines with a heat
input at peak load equal to or greater
than 10.7 gigajoules per hour (10 million
Btu/hour) but less than or equal to 107.2
gigajoules per hour (100 million Btu/
hour} based on the lower heating value
of the fuel fired, shall comply with the
provisions of § 60.332(a)(2).
(d) Stationary gas turbines employed
in oil/gas production or oil/gas
transportation and not located in
Metropolitan Statistical Areas; and
offshore platform turbines shall comply
with the provisions of § 60.332(a)(2).
(e) Stationary gas turbines with a heat
input at peak load equal to or greater
than 10.7 gigajoules per hour (10 million
Btu/hour) but less than or equal to 107.2
gigajoules per hour (100 million Btu/
hour) based on the lower heating value
of the fuel fired and that have
commenced construction prior to
October 3,1962 are exempt from
paragraph (a) of this section.
(f) Stationary gas turbines using water
or steam injection for control of NO,
emissions are exempt from paragraph
(a) when ice fog is deemed a traffic
hazard by the owner or operator of the
gas turbine.
(g) Emergency gas turbines, military
gas turbines for use in other than a
garrison facility, military gas turbines
installed for use as military training
facilities, and fire fighting gas turbines
are exempt from paragraph (a) of this
section.
(h) Stationary gas turbines engaged by
manufacturers in research and
development of equipment for both gas
turbine emission control techniques and
gas turbine efficiency improvements are
exempt from paragraph (a) on a case-by-
case basis as determined by the
Administrator.
(i) Exemptions from the requirements
of paragraph (a) of this section will be
granted on a case-by-case basis as
determined by the Administrator in
specific geographical areas where
mandatory water restrictions are
required by governmental agencies
because of drought conditions. These
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exemptions will be allowed only while'
the mandatory water restrictions are in
effect.
5 60.333 Standard for sulfur dioxide.
On and after the date on which the
performance test required to be
conducted by § BO.ff is completed, every
owner or operator subject to the
provision of this subpart shall comply
with one or the other of the following
conditions:
(a) No owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the
atmosphere from any stationary gas
turbine any gases which contain sulfur
dioxide in excess of 0.015 percent by
volume at 15 percent oxygen and on a
dry basis.
(b) No owner or operator subject to
the provisions of this subpart shall burn
in any stationary gas turbine any fuel
which contains sulfur in excess of 0.8
percent by weight.
§ 60.334 Monitoring of operations.
(a) The owner or operator of any
stationary gas turbine subject to the
provisions of this subpart and using
water injection to control NO, emissions
shall install and operate a continuous
monitoring system to monitor and record
the fuel consumption and the ratio of
water to fuel being fired in the turbine.
This system shall be accurate to within
±5.0 percent and shall be approved by
the Administrator.
(b) The owner or operator of any
stationary gas turbine subject to the
provisions of this subpart shall monitor
sulfur content and nitrogen content of
the fuel being fired in the turbine. The
frequency of determination of these
values shall be as follows:
(1) If the turbine is supplied its fuel
from a bulk storage tank, the values
shall be determined on each occasion
that fuel is transferred to the storage
tank from any other source.
(2) If the turbine is supplied its fuel
without intermediate bulk storage the
values shall be determined and recorded
daily. Owners, operators or fuel vendors
may develop custom schedules for
determination of the values based on the
design and operation of the affected
facility and the characteristics of the
fuel supply. These custom schedules
shall be substantiated with data and
must be approved by the Administrator
before they can be used to comply with
paragraph (b) of this section.
(c) For the purpose of reports required
under § 60.7(c), periods of excess
emissions that shall be reported are
defined as follows:
(1) Nitrogen oxides. Any one-hour
period during which the average water-
to-fuel ratio, as measured by the
continuous monitoring system, falls
below the water-to-fuel ratio determined
to demonstrate'compliance with 8 60.332
by the performance test required in .
8 60.8 or any period during which the
fuel-bound nitrogen of the fuel is greater
than the maximum nitrogen content
allowed by the fuel-bound nitrogen
allowance used during the performance
test required hi 8 60.8. Each report shall
include the average water-to-fuel ratio,
average fuel consumption, ambient
conditions, gas turbine load, and
nitrogen content of the fuel during the
period of excess emissions, and the
graphs or figures developed under
8 60.335[a).
(2) Sulfur dioxide. Any daily period
during which the sulfur content of the.
fuel being fired in the gas turbine
exceeds 0.8 percent.
(3) Ice fog. Each period during which
an exemption provided in 8 60.332(g) is
in effect shall be reported in writing to
the Administrator quarterly. For each
period the ambient conditions existing
during the period, the date and time the
air pollution control system was
deactivated, and the date and time the
air pollution control system was
reactivated shall be reported. All
quarterly reports shall be postmarked by
the 30th day following the end'of each
calendar quarter.
(Sec. 114 of the Clean Air Act as amended [42
U.S.C. 1857C-9]).
$ 60.335 Test methods and procedures.
(a) The reference methods in
Appendix A to this part, except as
provided in § 60.8(b], shall be used to
determine compliance with the
standards prescribed in § 60.332 as
follows:
(1) Reference Method 20 for the
concentration of nitrogen oxides and
oxygen. For affected facilities under this
subpart, the span value shall be 300
parts per million of nitrogen oxides.
(i) The nitrogen oxides emission level
measured by Reference Method 20 shall
be adjusted to ISO standard day
conditions by the following ambient
condition correction factor:
NOV- (N0v
Obs
Obs
(Hobs - 0.00633)
'AMB j.53
where:
NO, = emissions of NO, at 15 percent oxygen
and ISO standard ambient conditions,
NOIOM=measured NO, emissions at 15
percent oxygen, ppmv.
Pref=reference combuster inlet absolute
pressure at 101.3 kilopascals ambient
pressure.
FOB. = measured combustor inlet absolute
pressure at test ambient pressure.
H,,,, = specific humidity of ambient air at test.
e = transcendental constant (2.718).
TAKE = temperature of ambient air at test.
The adjusted NO, emission level shall
be used to determine complianre with
§ 60.332.
(ii) Manufacturers may develop
custom ambient condition correction
factors for each gas turbine model they
manufacture in terms of combustor inlet
pressure, ambient air pressure, ambient
air humidity and ambient air
temperature to adjust the nitrogen
oxides emission level measured by the
performance test as provided for in
i 60.8 to ISO standard day conditions.
These ambient condition correction
factors shall be substantiated with data
and must be approved for use by the
Administrator before the initial
performance test required by § 60.8.
Notices of approval of custom ambient
condition correction factors will be
published in the Federal Register.
(iii) The water-to-fuel ratio necessary
to comply with § 60.332 will be
determined during the initial
performance test by measuring NO,
emission using Reference Method 20 and
the water-to-fuel ratio necessary to
comply with $ 60.332 at 30, 50, 75, and
100 percent of peak load or at four
points in the normal operating range of
the gas turbine, including the minimum
point in the range and peak load. All
loads shall be corrected to ISO
conditions using the appropriate
equations supplied by the manufacturer.
(2) The analytical methods and
procedures employed to determine the
nitrogen content of the fuel being fired
shall be approved by the Administrator
and shall be accurate to within ±5
percent.
(b) The method for determining
compliance with 8 60.333, except as
provided in § 60.8(b), shall be as
follows:
(1) Reference Method 20 for the
concentration of sulfur dioxide and
oxygen or
(2) ASTM D2880-71 for the sulfur
content of liquid fuels and ASTM
D1072-70 for the sulfur content of
gaseous fuels. These methods shall also
be used to comply with § 60.334(b).
(c) Analysis for the purpose of
determining the sulfur content and the
nitrogen content of the fuel as required
by § 60.334(b), this subpart, maybe
performed by the owner/operator, a
service contractor retained by the
owner/operator, the fuel vendor, or any
other qualified agency provided that the
analytical methods employed by these
agencies comply with the applicable
paragraphs of this section.
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(Sec. 114 of the Clean Air Act as amended [42
U.S.C. 18570-81]).
Appendfc A—Reference Methods
2, Part 60 is amended by adding
Reference Method 20 to Appendix A as
follows:
*****
Method 20—Determination of Nitrogen
Oxides, Sulfur Dioxide, and Oxygen
Emissions from Stationary Gas Turbines
I. Applicability and Principle
1.1 Applicability. This method is
applicable for the determination of nitrogen
oxides (NO,), sulfur dioxide (SO:,), and
oxygen (O?) emissions from stationary gas
turbines. For the NO, and Oa determinations.
this method includes: (1) measurement
system design criteria, (2) analyzer
performance specifications and performance
test procedures; and (3) procedures for
emission testing.
1.2 Principle. A gas sample is
continuously extracted from the exhaust
ttream of a stationary gas turbine; 8 portion
of the sample stream is conveyed to
instrumental analyzers for determination of
NO, and O> content. During each NO, and
OO> determination, a separate measurement
of SO, emissions is made, using Method 6, or
it equivalent. The Oa determination is used to
adjust the NO, and SOj concentrations to a
reference condition.
2. Definitions
2.1 Measurement System. The total
equipment required for the determination of a
gas concentration or a gas emission rate. The
system consists of the following major
subsystems:
2.1.1 Sample Interface. That portion of a
system that is used for one or more of the
following: sample acquisition, sample
transportation, sample conditioning, or
protection of the analyzers from the effects of
the stack effluent.
2.1.2 NO, Analyzer. That portion of the
system that senses NO, and generates an
output proportional to the gas concentration.
2.1.3 Oj Analyzer. That portion of the
system that senses O2 and generates an
output proportional to the gas concentration.
2.2 Span Value. The upper limit of a gas
concentration measurement range that is
specified for affected source categories in the
applicable part of the regulations.
23 Calibration Gas. A known
concentration of a gas in an appropriate
diluent gas.
2/4 Calibration Error. The difference
bet ween the gas concentration indicated by
the measurement system and the known
concentration of the calibration gas.
2.6 Zero Drift The difference in the
measurement system output readings before
and after a stated period of operation during
which no unscheduled maintenance, repair,
or adjustment took place and the input
concentration at the time of the
measurements was zero.
2.6 Calibration Drift. The difference in the
measurement system output readings before
and after a stated period of operation during
which no unscheduled maintenance, repair,
or adjustment took place and the input at the
time of the measurements was a high-level
value.
2.7 Residence Time. The elapsed time
from the moment the gas sample enters the
probe tip to the moment the same gas sample
reaches the analyzer inlet.
2.8 Response Time. The amount of time
required for the continuous monitoring
system to display on the data output 95
percent of a step change in pollutant
concentration.
2.9 Interference Response. The output
response of the measurement system to a
component in the sample gas, other than the
gas component being measured.
3. Measurement System Performance
Specifications
3.1 NO, to NO Converter. Greater than 90
percent conversion efficiency of NOa to NO.
. 3.2 Interference Response. Less than ± 2
percent of the span value.
3.3 Residence Time. No greater than 30
seconds.
3.4 Response Time. No greater than 3
minutes.
3.5 Zero Drift. Less than ± 2 percent of
the span value.
3.6 Calibration Drift. Less than ± 2
percent of the span value.
4. Apparatus and Reagents
4.1 Measurement System. Use any
measurement system for NO, and O2 that is
expected to meet the specifications in this
method. A schematic of an acceptable
measurement system is shown in Figure 20-1.
The essential components of the
measurement system are described below:
Figure 20 1. Measurement system design for stationary gas turbines.
EXCESS
SAMPLE TO VENT
4.1.1 Sample Probe. Heated stainless
steel, or equivalent, open-ended, straight tube
of rofflcient length to traverse the sample
points.
4.1.2 Sample Line. Heated (>95'C)
stainless steel or Teflon *,bing to transport
the sample gas to the sample conditioners
and analyzers.
4.1.3 Calibration Valve Assembly. A
three-way valve assembly to direct the zero
and calibration gases to the sample
conditioners and to the analyzers. The
calibration valve assembly shall be capable
of blocking the sample gas flow and of
introducing calibration gases to the
measurement system when in the calibration
mode.
4.1.4 NOa to NO Converter. That portion
of the system that converts the nitrogen
dioxide (NOi) in the sample gas to nitrogen
oxide (NO). Some analyzers are designed to
measure NO, as NO* on a wet basis and can
be used without an NO, to NO converter or n
moisture removal trap provided the sample
line to the analyzer is heated (>95'C) to thv
inlet of the analyzer. In addition, an NOs to
NO converter is not necessary if the NOj
portion of the exhaust gas is less than 5
percent of the total NO, concentration. As «<
guideline, an NO, to NO converter is not
necessary if the gas turbine is operated at 90
percent or more of peak load capacity. A
converter is necessary under lower load
conditions.
4.1.5 Moisture Removal Trap. A
refrigerator-type condenser designed to
continuously remove condensate from the
sample gas. The moisture removal trap is not
necessary for analyzers that can measure
NO, concentrations on a wet basis; for these
analyzers, (a) heat the sample line up to the
inlet of the analyzers, (b) determine the
moisture content using methods subject to I hi
approval of the Administrator, and (c) correc-
the NO, and O, concentrations to a dry basis
4.1.6 Particulate Filter. An in-stack or an
out-of-stack glass fiber filter, of the type
specified in EPA Reference Method 5:
however, an out-of-stack filter is
recommended when the stack gas
temperature exceeds 250 to 300°C.
4.1.7 Sample Pump. A nonreactive leak
free sample pump to pull the sample gas
through the system at a flow rate sufficient t<
minimize transport delay. The pump shall be
made from stainless steel or coated with
Teflon or equivalent.
4.1.8 Sample Gas Manifold. A sample gdf-
manifold to divert portions of the sample g.ts
stream to the analyzers. The manifold may be
constructed of glass, Teflon, type 316
stainless steel, or equivalent.
4.1.9 Oxygen and Analyzer. An analyze)
to determine the percent Oi concentration of
the sample gas stream.
4.1.10 Nitrogen Oxides Analyzer. An
analyzer to determine the ppm NO,
concentration in the sample gas stream.
4.1.11 Data Output. A strip-chart recorder.
analog computer, or digital recorder for
recording measurement data.
4.2 Sulfur Dioxide Analysis. EPA
Reference Method 6 apparatus and reagent*
4.3 NO, Caliberation Gases. The
calibration gases for the NO, analyzer may
be NO in N,, NO, in air or N,, or NO and NO,
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in Nj. For NOX measurement analyzers thai
require oxidation of NO to NOt, the
calibration gases must be in the form of NO
in Nj. Use four calibration gas mixtures as
specified below:
4.3.1 High-level Gas. A gas concentration
that is equivalent to 80 to 90 percent of the
span value.
4.3.2 Mid-level Gas. A gas concentration
that is equivalent to 45 to 55 percent of the
span value.
4.3.3 Low-level Gas. A gas concentration
that is equivalent to 20 to 30 percent of the
span value.
4.3.4 Zero Gas. A gas concentration of
less than 0.25 percent of the span value.
Ambient air may be used for the NO, zero
grtS.
44 O» Calibration Gases. Use ambient air
•it 20.9 percent as the high-level O, gas. Use a
gas concentration that is equivalent to 11-14
percent O2 for the mid-level gas. Use purified
nitrogen for the zero gas.
4.5 NO3/NO Gas Mixture. For
determining the conversion efficiency of thr
\O, to NO converter, use a calibration gas
mixture of NO2 and NO in N,. The mixture
uill be known concentrations of 40 to 60 ppm
NO* and 90 to 110 ppm NO and certified by
the gas manufacturer. This certification of gds
concentration must include a brief
description of the procedure followed in
determining the concentrations.
5. Measurement System Performance Trsl
Procedures
Perform the following procedures prior to
measurement of emissions (Section 6] and
only once for each test program, i.e./the
series of all test runs for a given gas turbine
engine.
5.1 Calibration Gas Checks. There are
two alternatives for checking the
concentrations of the calibration gases, (a)
The first is to use calibration gases that are
documented traceable to National Bureau of
Standards Reference Materials. Use
Traceability Protocol for Establishing True
Concentrations of Gases Used for
Calibrations and Audits of Continuous
Source Emission Monitors (Protocol Number
1) that is available from the Environmental
Monitoring and Support Laboratory. Quality
Assurance Branch. Mail Drop 77,
Environmental Protection Agency, Research
Triangle Park, North Carolina 27711. Obtain a
certification from the gas manufacturer that
the protocol was followed. These calibration
gases are not to be analyzed with the
Reference Methods, (b) The second
alternative is to use calibration gases not
prepared according to the protocol. If this
alternative is chosen, within 1 month prior to
the emission test, analyze each of the
calibration gas mixtures in triplicate using
Reference Method 7 or the procedure outlined
in Citation B.I for NO, and use Reference
Method 3 for O». Record the results on a data
sheet (example is shown in Figure 20-2). For
the low-level, mid-level, or high-level gas
mixtures, each of the individual NO,
an.ilytir.rfl results must be within 10 percent
(or 10 ppm. whichever is greater) of the
triplit.tu- set average (O, test results must be
within 0.5 percent O,); otherwise, discard the
entire set and repeat the triplicate analyses.
If the average of the triplicate reference
method lest results is within 5 percent for
NO, gas or 0.5 percent Oi for the O» gas of
the calibration gas manufacturer's tag value,
use the tag value; otherwise, conduct at least
three additional reference method test
analyses until 1he results of six individual
NO, runs (the three original plus three
additional) agree within 10 percent (or 10
ppm, whichever is greater) of the average (Oj
test results must be within 0.5 percent Oz).
Then use this average for the cylinder value.
5.2 Measurement System Preparation.
Prior to the emission test, assemble the
measurement system following the
manufacturer's written instructions in
preparing and operating the NOi to NO
Converter, the NO, analyzer, the Ot analyzer,
and other components.
Date.
.(Must be within 1 month prior to the test period)
Reference method used.
Sample run
1
2
3
Average
Maximum % deviation'1
Gas concentration, ppm
Low level*
Mid leveJb
High level0
3 Average must b*20 to 30% of span value.
b Average must be 45 to 55% of span value
c Average must be 80 to 90% of span value.
d Must be < ± 10% of applicable average or 10 ppm.
whichever is greater.
Figure 20-2. Analysis of calibration gases
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5.3 Calibration Check. Conduct the
calibration checks for both the NO, and the
O, analyzers as follows:
5.3.1 After the measurement system has
been prepared for use (Section 5.2), introduce
zero gases and the mid-level calibration
gases; set the analyzer output responses to
the appropriate levels. Then introduce each
of the remainder of the calibration gases
described in Sections 4.3 or 4.4, one at a time.
to the measurement system. Record the
responses on a form similar to Figure 20-3.
5.3.2 If the linear curve determined from
the zero and mid-level calibration gas
responses does not predict the actual
response of the low-level (not applicable for
the Ot analyzer] and high-level gases within
±2 percent of the span value, the calibration
shall be considered invalid. Take corrective
measures on the measurement system before
proceeding with the test.
5.4 Interference Response. Introduce the
gaseous components listed in Table 20-1 into
the measurement system separately, or as gas
mixtures. Determine the total interference
output response of the system to these
components in concentration units; record the
values on a form similar to Figure 20-4. If the
sum of the interference responses of the test
gases for either the NO, or Oi analyzers is
greater than 2 percent of the applicable span
value, take corrective measure on the
measurement system.
Tabto 20-1.—Interference Test Gas Concentration
CO 500±50 ppm.
SO, „ 200±20 ppm.
CO, ,. 10± 1 percent
O.. 20 9± 1
percent
DttMol «*' .
Fiqut* 20 4 In1i-r1«rence re>po<>M
Turbine type:
Date:
Identification number,
Test number
Analyzer type:.
Identification number.
Cylinder Initial analyzer Final analyzer Difference:
value, response, responses, initial-final,
ppm or % ppm or % ppm or % ppm or %
Zero gas
Low - level gas
Mid - level gas
High - level gas
Percent drift =
Figure 20-3.
Absolute difference
X100.
Span value
Zero and calibration data.
Conduct an interference response test of
each analyzer prior to its initial use in the
field. Thereafter, recheck the measurement
system if changes are made in the
instrumentation that could alter the
interference response, e.g., changes in the
type of gas detector.
In lieu of conducting the interference
response test, instrument vendor data, which
demonstrate that for the test gases of Table
20-1 the interference performance
specification is not exceeded, are acceptable.
5.5 Residence and Response Time.
5.5.1 Calculate the residence time of the
sample interface portion of the measurement
system using volume and pump flow rate
information. Alternatively, if the response
time determined as defined in Section 5.5.2 is
less than 30 seconds, the calculations are not
necessary.
5.5.2 To determine response time, first
introduce zero gas into the system at the
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talibration valve until all readings are stable
then, switch to monitor the stack effluenl
until a stable reading can be obtained.
Record the upscale response time. Next,
introduce high-level calibration gas into the
system. Once the system has stabilized at the
high-level concentration, switch to monitor
the stack effluent and wait until a stable
value is reached. Record the downscale
response time. Repeat the procedure three
times A stable value is equivalent to a
change of less than 1 percent of span value
for 30 seconds or less than 5 percent of the
measured average concentration for 2
minutes. Record the response time data on a
form similar to Figure 20-5, the readings of
the upscale or downscale reponse time, and
report the greater time as the "response time"
for the analyzer. Conduct a response time
test prior to the Initial field use of the
measurement system, and repeat if changes
are made in the measurement system.
Date of test.
Analyzer type.
S/IM
Span gas concentration.
Analyzer span setting_
Upscale
1.
2.
3.
ppm
.seconds
. seconds
.seconds
Average upscale response.
1
Downscale 2
3
. seconds
. seconds
. seconds
. seconds
Average downscale response.
. seconds
System response time = slower average time =.
.seconds.
Figure 20-5 Response time
5 0 NO* NO Conversion Efficiency
Introduce to the system, at the calibration
i«lve assembly the NO2/NO gas mixtuie
(Section 4 5) Record the response of the, NO,
analyzer If the instrument response indicates
less than 90 percent NO2 to NO conversion.
make corrections to the measurement system
and repeat the check. Alternatively, the NO;
In \'O converter check described in Title 40
I1,111 86 Certification and Test Procedures fur
I Ii'ovy-Duty Engines for 1979 and Later
Wui1?I Years may be used. Other alternate
procedures may be used with approval of the
Adnimifttiator.
i> Km.main Measurement Test Procedure
b 1 Preliminaries
G l 1 Selection of a Sampling Site. Select a
sampling site as close as practical to the
exhaust of the turbine. Turbine geometry.
stack configuration, internal baffling and
point of introduction of dilution air will vary
for different turbine designs. Thus, each of
these factors must be given special
consideration in order to obtain a
representative sample. Whenever possible,
the sampling site shall be located upstream of
the point of introduction of dilution air into
the duct. Sample ports may be located before
or after the upturn elbow, in order to
accommodate the configuration of the turning
vanes and baffles and to permit a complete.
unobstructed traverse of the stack. The
sample ports shall not be located within 5
feet or 2 diameters (whichever is less) of the
gas discharge to atmosphere. For
supplementary-fired, combined-cycle plants.
the sampling site shall be located between
the gas turbine and the boiler. The diameter
of the sample ports shall be sufficient to
allow entry of the sample probe.
6.1.2 A preliminary O2 traverse is made
for the purpose of selecting low Ot values.
Conduct this test at the turbine condition that
is the lowest percentage of peak load
operation included in the program Follow the
procedure below or alternative procedures
subject to the approval of the Administrator
may be used:
6.1.2.1 Minimum Number of Points. Select
a minimum number of points as follows: (1)
eight, for stacks having cross-sectional areas
less than 1 5m2(161 ft2); (2) one sample point
for each 0.2 m2(2.2 ft2 of areas, for stacks of
1.5 m2 to 10.0 m' (16.1-107.6 ft=) in cross-
sectional area; and (3) one sample point for
each 0.4 ni'-'(4.4 ft2) of area, for stacks greater
than 10.0 m - (107.6 ft *) in cross-sectional
area. Note that for circular ducts, the number
of sample points must be a multiple of 4. and
for rectangular ducts, the number of points
must be one of those listed in Table 20-2:
therefore, round off the number of points
(upward), when appropriate.
6.1.2.2 Cross-sectional Layout and
Location of Traverse Points. After the numbtr
of traverse points for the preliminary O3
sampling has been determined, use Method 1
to located the traverse points.
6.1.2.3 Preliminary O"Measurement
While the gas turbine is operating at she
lowest percent of peak load, conduct a
preliminary O2 measurement as follows.
Position the probe at the first traverse point
and begin sampling The minimum sampling
time at each point shall be 1 minute plus the
average system response time. Determine the
average steady-state concentration of O2at
each point and record the data on Figrre 20-
6.
6.1.2.4 Selection of Emission It;;.)
Sampling Points Select the eight sampling
points at which the lowest O" conct r.lration
were obtained Use these same points for all
the test runs at the different turbine load
conditions More than eight points rray lie
used, if desired
Tabte 20-2.—Cross-secUona: Layout to
Rectangular Stacks
No of traverse poinls
9
12
16
20
25
30
36
42.. . .
49
iayojt
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Location:
Plant.
Date.
City, State.
Turbine identification:
Manufacturer
Model, serial number.
Sample point
Oxygen concentration, ppm
Figure 20-6. Preliminary oxygen traverse.
6.2 NO, and O, Measurement. This test is
to be conducted at each of the specified load
conditions. Three te'st runs 3t each load
condition constitute a complete test.
6.21 At the beginning of each NO, test
run and, as applicable, during the run, record
turbine data as indicated m Figure 20-7. Also.
record the location and number of the
traverse points on a diagram.
•ILLING CODE 6MO-01-M
6.2.2 Position the probe at the tirst point
determined in the preceding section and
begin sampling. The minimum sampling time
at each point shall be at least 1 minute plus
the average system response time Determine
the average steady-state concentration of O,
and NO, at each point and record the data on
Figure 2O-8
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TURBINE OPERATION RECORD
Test operator Date
Turbine identification:
Type
Serial No
Location:
Plant
City
Ultimate fuel
Analysis C
H
N
Ambient temperature.
Ambient humidity
Test time start
Ash
H2O
Trace Metals
Na
Test time finish.
Fuel flow ratea_
Va
etcD
Water or steam.
Flow rate3
Ambient Pressure.
Operating load.
"Describe measurement method, i.e., continuous flow meter,
start finish volumes, etc.
bi.e., additional elements added for smoke suppression.
Figure 20-7. Stationary gas turbine data.
Turbine identification: Test operator name.
Serial N
Mndpl, sprial No . . ,._... .... _ NOu instnimp
Serial N
Location:
Sample
Tity State
Amhipnt prp«nrp _
Hato
Tp«t timp -start ,
n
n
Time,
mm.
f
NO*.
ppm
Test time - finish.
aAverage steady-state value from recorder or
instrument readout.
Figure 20-8. Stationary gas turbine sample point record.
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6.2.3 After sampling the last point,
conclude the test run by recording the final
turbine operating parameters and by
determining the zero and calibration drift, as
follows:
Immediately following the test run at each
load condition, or if adjustments are
necessary for the measurement system during
the tests, reintroduce the zero and mid-level
calibration gases as described in Sections 4.3,
and 4.4, one at a time, to the measurement
system at the calibration valve assembly.
(Make no adjustments to the measurement
system until after the drift checks are made).
Record the analyzers' responses on a form
similar to Figure 20-3. If the drift values
exceed the specified limits, the test run
preceding the check is considered invalid and
will be repeated following corrections to the
measurement system. Alternatively, the test
results may be accepted provided the
measurement system is recalibrated and the
calibration data that result in the highest
corrected emission rate are used.
6.3 SO2 Measurement. This test is
conducted only at the 100 percent peak load
condition. Determine SOj using Method 6, or
equivalent, during the test. Select a minimum
of six total points from those required for the
NO. measurements; use two points for each
sample run. The sample time at each point
shall be at least 10 minutes. Average the Oi
readings taken during the NO, test runs at
sample points corresponding to the SOj
traverse points (see Section 6.2.2) and use
this average Oi concentration to correct the
integrated SO2 concentration obtained by
Method 6 to 15 percent O2 (see Equation 20-
1).
If the applicable regulation allows fuel
sampling and analysis for fuel sulfur content
to demonstrate compliance with sulfur
emission unit, emission sampling with
Reference Method 6 is not required, provided
the fuel sulfur content meets the limits of the
regulation.
7. Emission Calculations
7.1 Correction to 15 Percent Oxygen.
Using Equation 20-1, calculate the NO, and
SOi concentrations (adjusted to 15 percent
Ot). The correction to 15 percent O2 is
sensitive to the accuracy of the O2
measurement. At the level of analyzer drift
specified in the method (±2 percent of full
scale), the change in the O> concentration
correction can exceed 10 percent when the Oj
content of the exhaust is above 16 percent Oi.
Therefore Oi analyzer stability and careful
calibration are necessary.
adj
(Equat10n
Where:
C«u=Pollutant concentration adjusted to
15 percent Oj (ppm)
Cn>««i=Pollutant concentration measured,
dry basis (ppm)
5.9=20.9 percent Oz -15 percent O2, the
defined O2 correction basis
Percent O2=Percent Oz measured, dry
basis (%}
7.2 Calculate the average adjusted NO,
concentration by summing the point values
and dividing by the number of sample points.
8. Citations
8.1 Curtis, F. A Method for Analyzing NO,
Cylinder Gases-Specific Ion Electrode
Procedure, Monograph available from
Emission Measurement Laboratory, ESED,
Research Triangle Park, N.C. 27711, October
1978.
[FR Doc 78-27993 Filed 9-7-7ft 8 45 am]
BILLING CODE (560-01-M
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Federal Register / Vol. 44, No. 187 / Tuesday, September 25, 1979 / Rules and Regulations
102
40 CFR Part 60
IFRL 1327-8]
Standards of Performance for New
Stationary Sources; General
Provisions; Definitions
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final Rule.
SUMMARY: This document makes some
editorial changes and rearranges the
definitions alphabetically in Subpart
A—General Provisions of 40 CFR Part
60. An alphabetical list of definitions
will be easier to update and to use.
EFFECTIVE DATE: September 25,1979.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION: The
"Definitions" section (I 60.2) of the
General Provisions of 40 CFR Part 60
now lists 28 definitions by paragraph
designations. Due to the anticipated
increase in the number of definitions to
be added to the General Provisions in
the future, continued use of the present
system of adding definitions by
paragraph designations at the end of the
Hst could become administratively
cumbersome and could make the list
difficult to use. Therefore, paragraph
designations are being eliminated and
the definitions are rearranged
alphabetically. New definitions will be
added to { 60.2 of the General
Provisions jn alphabetical order
automatically.
Since this rule simply reorganizes
existing provisions and has no
regulatory impact, it is not subject to the
procedural requirements of Executive
Order 12044.
Dated. September 19,1979.
Edward F. Tuerk,
Acting Assistant Administrator for Air, Noise,
and Radiation.
40 CFR 60.2 is amended by removing
all paragraph designations and by
rearranging the definitions in
alphabetical order as follows:
{60.2 Definitions.
The terms used in this part are
defined in the Act or in this section as
follows:
"Act" means the Clean Air Act (42
U.S.C. 1857 et seq., as amended by Pub.
L. 91-604, 84 Stat. 1676).
"Administrator" means the
Administrator of the Environmental
Protection Agency or his authorized
representative.
"Affected facility" means, with
reference to a stationary source, any
apparatus to which a standard is
applicable.
"Alternative method" means any
method of sampling and analyzing for
an air pollutant which is not a reference
or equivalent method but which has
been demonstrated to the
Administrator's satisfaction to, in
specific cases, produce results adequate
for his determination of compliance.
"Capital expenditure" means an
expenditure for a physical or
operational change to an existing facility
which exceeds the product of the
applicable "annual asset guideline
repair allowance percentage" specified
in the latest edition of Internal Revenue
Service Publication 534 and the existing
facility's basis, as defined by section
1012 of the Internal Revenue Code.
"Commenced" means, with respect to
the definition of "new source" in section
lll(a)(2) of.the Act, that an owner or
operator has undertaken a continuous
program of construction or modification
or that an owner or operator has entered
into a contractual obligation to
undertake and complete, within a
reasonable time, a continuous program
of construction or modification.
"Construction" means fabrication.
erection, or installation of an affected
facility.
"Continuous monitoring system"
means the total equipment, required
under the emission monitoring sections
in applicable subparts, used to sample
and condition (if applicable), to analyze,
and to provide a permanent record of
emissions or process parameters.
"Equivalent method" means any
method of sampling and analyzing for
an air pollutant which has been
demonstrated to the Administrator's
satisfaction to have a consistent and
quantitatively known relationship to the
reference method, under specified
conditions.
"Existing facility" means, with
reference to a stationary source, any
apparatus of the type for which a
standard is promulgated in this part, and
the construction or modification of
which was commenced before the date
of proposal of that standard; or any
apparatus which could be altered in
such a way as to be of that type.
"Isokinetic sampling" means sampling
in which the linear velocity of the gas
entering the sampling nozzle is equal to
that of the undisturbed gas stream at the
sample point.
"Malfunction" means any sudden and
unavoidable failure of air pollution
control equipment or process equipment
or of a process to operate in a normal or
usual manner. Failures that are caused
entirely or in part by poor maintenance,
careless operation, or any other
preventable upset condition or
preventable equipment breakdown shall
not be considered malfunctions.
"Modification" means any physical
change in, or change in the method of
operation of, an existing facility which
increases the amount of any air
pollutant (to which a standard applies)
emitted into the atmosphere by that
facility or which results in the emission
of any air pollutant (to which a standard
applies) into the atmosphere not
previously emitted.
"Monitoring device" means the total
equipment, required under the
monitoring of operations sections in
applicable subparts, used to measure
and record (if applicable) process
parameters.
"Nitrogen oxides" means all oxides of
nitrogen except nitrous oxide, as
measured by test methods set forth in
this part.
"One-hour period" means any 60-
minute period commencing on the hour.
"Opacity" means the degree to which
emissions reduce the transmission of
light and obscure the view of an object
in the background.
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Federal Register / Vol. 44, No. 187 / Tuesday, September 25. 1979 / Rules and Regulations.
"Owner or operator" means any
person who owns, leases, operates,
controls, or supervises an affected
facility or a stationary source of which
an affected facility is a part.
"Particulate matter" means any finely
divided solid or liquid material, other
than uncombined water, as measured by
the reference methods specified under
each applicable subpart, or-an
equivalent or alternative method.
"Proportional sampling" means
sampling at a rate that produces a
constant ration of sampling rate to stack
gas flow rate.
"Reference method" means any
method of sampling and analyzing for
an air pollutant as described in
Appendix A to this part.
"Run" means the net period of time
during which an emission sample is
collected. Unless otherwise specified, a
run may be either intermittent or
continuous within the limits of good
engineering practice.
"Shutdown" means the cessation of
operation of an affected facility for any
purpose.
"Six-minute period" means any one of
the 10 equal parts of a one-hour period.
"Standard" means a standard of
performance proposed or promulgated
under this part.
"Standard conditions" means a
temperature of 293 K (68°F) and a
pressure of 101.3 kilopascals (29.92 in
Hg).
"Startup" means the setting in
operation of an affected facility for any
purpose.
"Stationary source" means any
building, structure, facility, or
installation which emits or may emit
any air pollutant and which contains
any one or combination of the following:
(a) Affected facilities.
(b) Existing facilities.
(c) Facilities of the type for which no
standards have been promulgated in this
part.
(Sec. 111. 301(a), Clean Air Act as amended
(42 U.S.C. 7411 and 7601(a))
|FRDoc 79-29769 Filed 9-24-79 8 45 am)
•ILLING CODE 6SCO-01-M
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Federal Register J Vol. 44. No. 208 / Thursday, October 25,1979 / Rules and Regulations
103
40 CFR Part 60
IFRL 1331-5]
Standards of Performance for New
Stationary Sources; Petroleum
Refinery Claus Sulfur Recovery Plants;
Amendment
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action deletes the
requirement that a Claus sulfur recovery
plant of 20 long tons per day (LTD) or
less must be associated with a "small
petroleum refinery" in order to be
exempt from the new source
performance standards for petroleum
refinery Claus sulfur recovery plants.
This action will result in only negligible
changes in the environmental, energy,
and economic impacts of the standards
EFFECTIVE DATE: October 25, 1979
ADDRESS: All comments received on the
proposal are available for public
inspection and copying at the EPA
Central Docket Section (A-130), Room
2903B, Waterside Mall, 401 M Street,
S.W., Washington, D.C. 20460. The
docket number is OAQPS-79-10.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
On March 15, 1978, EPA promulgated
new source performance standards for
petroleum refinery Claus sulfur recovery
plants. These standards did not apply to
Claus sulfur recovery plants of 20 LTD
or less associated with a small
pe iroleum refinery, 40 CFR 60.100 (1978).
"Small petroleum refinery" was defined
as a "petroleum refinery which has a
crude oil processing capacity of 50.000
barrels per stream day or less, and
which is owned or controlled by a
refiner with a total combined crude oil
processing capacity of 137.500 barrels
per stream day or less," 40 Cl-'R
60 101 (m) (1978).
On May 12, 1978, two oil companies
filed a Petition for Review of these now
source performance standards. One
issue was whether the definition of
"small petroleum refinery" was unduly
restrictive.
On March 20,1979, EPA proposed to
amend trie definition of "small
petroleum refinery" by deleting the
requirement that it be "owned or
controlled by a refiner with a total
combined crude oil processing capacity
of 137,500 barrels per stream day (BSDJ
or less," 44 FR 17120. This proposal
would have had a negligible effect on
sulfur dioxide (SO2) emissions, casts,
and energy consumption. The oil
company petitioners agreed to dismiss
their entire Petition for Review if tbe
final regulation did not differ
substantively from this proposal.
EPA provided a 60 day period for
comment on the proposal and the
opportunity for interested personi to
request a hearing. The comment period
closed May 21,1979. EPA received six
written comments and no requests for a
hearing
Summary of Amendment
The promulgated amendment deletes
the requirement that a Claus sulfur
recovery plant of 20 LTD or less must be
associated with a "small petroleum
refinery" in order to be exempt from the
new source performance standards for
such plants. Thus, Ihe final standard wiU
apply to any petroleum refinery Glaus
sulfur recovery plant of more than 20
LTD processing capacity. This
amendment will apply, like the
.standards themselves, to affected
facilities, the construction or
modification of which commenced after
October 4,1976, the date the standards
of performance for petroleum refinery
Clans sulfur recovery plants were
proposed.
Environmental. Energy, and Ecomonic
Impacts
The promulgated amendment will
result in a negligible increase in
nationwide sulfur dioxide emissions
compared to the proposed amendment
and the existing standard. The
promulgated amendment will also have
essentially no impact on other aspects of
environmental quality, such as solid
waste disposal, water pollution, or
noise Finally, the promulgated
amendment will have essentially no
impact on nationwide energy
consumption or refinery product prices.
Summary of Comments and Rationale
All six comments received were from
the petroleum refinery industry. Two
commenters expressed agreement with
the proposal. The other four also were
not opposed to the proposal, but felt the
definition of "small petroleum refinery"
was still too restrictive, as explained
below
Two of the four argued for deletion of
Hie 50,000 BSD refinery size cutoff and
also that sulfur recovery plant size was
not only a function of refinery size (as
they felt EPA had apparently assumed
in establishing the refinery size cutoff),
but depended on such factors as the
crude oil sulfur content and actual crude
oil throughput.
Tbe other two commenters, each
planning to construct small Claus sulfur
recovery plants, objected that the
environmental benefits of subjecting
small Claus sulfur recovery plants to the
standards was not substantial even
when a Claus sulfur recovery plant was
associated with a petroleum refinery of
more that 50,000 BSD capacity. EPA
agrees. Accordingly, EPA believes it is
appropriate under the circumstances to
delete the refinery size requirement.
Thus, the promulgated standard
would exempt from coverage by the
standards any Claus sulfur recovery
plant of 20 LTD or less. Alternatively,
the standards of performance for
petroleum refinery Claus sulfur recovery
plants would apply to all plants of more
than 20 LTD processing capacity.
Deletion of the refinery size
requirement from the standards will not
result in a significant increase in the
emissions of Sd from petroleum
refinery Claus sulfur recovery plants.
This, is due to the small number of small
Claus sulfur recovery plants (i.e., 20 LTD
or less capacity) that are likely to be
built at refineries of more than 50,000
BSD and the fact that most of these
exempted plants will still be required by
State regulations to achieve 99.0 percent
control of SO2 (compared to the 99.9
percent control required for large Claus
sulfur recovery plants). In many cases
the exempted Claus sulfur recovery
plants would be required to achieve
greater than 99.0 percent control of SO;
due to prevention of significant
deterioration (PSD) requirements This
change will also result in a negligible-
decrease in costs and essentially no
impart on energy and economic impacts.
compared to the proposed amendment.
Docket
Docket No OAQPS-79-10, containing
all supporting information used by EPA.
is available for public inspection and
copying between 8:00 a.m. and 4:00 p m.,
Monday through Friday, at EPA's
Central Docket Section. Room 2903B
(see ADDRESS Section of this
preamble).
The docketing system is intended to
allow members of the public and
industries involved to readily identify
and locate documents so that they can
intelligently and effectively participate
in the rulemaking process. Along with
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Federal Register / Vol. 44. No. 208 / Thursday. October 25. 1979 / Rules and Regulations
the statement of basis and purpose of
the promulgated rule and EPA responses
to comments, the contents of the dockets
will serve as the record in case of
judicial review [Section 307(d)(a)].
Miscellaneous
The effective date of this regulation is
October 25,1979. Section lll(b)(l)(B) of
the Clean Air Act provides that
standards of performance become
effective upon promulgation and apply
to affected facilities, construction or
modification of which was commenced
after the date of proposal on October 4,
1976 (41 FR 43866).
EPA will review this regulation four
years from the date of promulgation.
This jeview will include an assessment
of such factors as the need for
integration with other programs the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
It should be noted that standards of
performance for new stationary sources
established under Section 111 of the
Clean Air Act reflect: "* * * application
of the best technological system of
continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
non-air quality health and
environmental impact and energy
requirements) the Administrator
determines has been adequately
demonstrated." [Section lll(a)(l)]
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate inachievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
a more stringent emission standard in
several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources locating in
nonattainment areas, i.e., those areas
where statutorily mandated health and
welfare standards are being violated. In
this respect, Section 173 of the Act
requires that a new or modified source
constructed in an area which exceeds
the National Ambient Air Quality
Standard (NAAQS) must reduce
emissions to the level which reflects the
"lowest achievable emission rate"
(LAER), as defined in Section 171(3), for
such category of source. The statute
defines LAER as that rate of emissions
based on the following, whichever is
more stringent:
(A) 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
(B) the most stringent emission
limitation which is achieved in practice
by such class or category of source. In
no event can the emission rate exceed
any applicable new source performance
standard [Section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (part C). These provisions
require that certain sources [referred to
in Section 169(1)] employ "best
available control technology" [as
defined in Section 169(3)] for all
pollutants regulated under the Act. Best
available control technology (BACT)
must be determined on a case-by-case
basis, taking energy, environmental, and
economic impacts and costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to
Section 111 (or 112) of the Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under Section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under Section
116 of the Act to establish even more
stringent emission limits than those
established under Section 111 or those
necessary to attain or maintain the
NAAQS under Section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under Section 111; and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act
requires the Administrator to, among
other things, prepare an economic
assessment for revisions to new source
performance standards determined to be
substantial. Executive Order 12044
requires certain analyses of significant
regulations. Since this amendment lacks
the economic impact and significance to
require additional analyses, it is not
subject to the above requirements.
Dated: October 16, 1979.
Douglas M. Costle,
Administrator.
Part 60 of chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. § 60.100 is amended by revising
paragraph (a), as follows:
f 60.100 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the following affected
facilities in petroleum refineries: fluid
catalytic cracking unit catalyst
regenerators, fuel gas combustion
devices, and all Glaus sulfur recovery
plants except Claus plants of 20 long
tons per day (LTD) or less. The Claus
sulfur recovery plant need not be
physically located within the boundaries
of a petroleum refinery to be an affected
facility, provided it processes gases
produced within a petroleum refinery.
(b) * * *
2. $ 60.101 is amended by revoking
and reserving paragraph (m), as follows:
§ 60.101 Definitions
*****
(m) [Reserved]
(Sec. Ill, 301(a), Clean Air Act as amended
(42 U.S.C. 7411, 7601(a)].)
|FR Doc. 79-32778 Filed 10-24-79: 845 am)
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Federal Register / Vol. 44. No. 219 / Friday, November 9, 1979 / Rules and Regulations
104
[FRL 1342-6}
Regulations for Ambient Air Quality
Monitoring and Data Reporting
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Amendment to final rule.
SUMMARY: This action amends air
quality monitoring and reporting
regulations which were promulgated
May 10,1979 (44 FR 27558). The
amendments correct several technical
errors that were made in the
promulgation notice. The amendments
reflect the intent of the regulations as
discussed in the preambles to the
proposed (August 7,1978, 43 FR 34892)
and final regulations.
DATES: These amendments are effective
November 9,1979.
FOR FURTHER INFORMATION CONTACT:
Stanley Sleva, Monitoring and Data
Analysis Division, (MD-14)
Environmental Protection Agency,
Research Triangle Park, N.C. 27711.
telephone number 919-541-5351.
SUPPLEMENTARY INFORMATION: On May
10,1979, EPA promulgated a new 40 CFR
Part 58 entitled, "Ambient Air Quality
Surveillance." The new regulations
consist of requirements for monitoring
ambient air quality and reporting data to
EPA as well as other regulations such as
public reporting of a daily air quality
index. The requirements replace § 51.17
and portions of § 51.7 from 40 CFR Part
51 and make necessary reference
changes in Parts 51, 52, and 60. Other
accompanying changes were made to
Part 51, such as restructuring the
unchanged portion of § 51.7 into a new
subpart, adding regulations concerning
public notification of air quality
information, and applying quality
assurance requirements to such
monitoring as may be required by the
prevention of significant deterioration
program.
These amendments to the May 10,
1979, regulations correct technical errors
which were discovered after
promulgation. The corrections are
consistent with the intent of the
rulemaking and are therefore not being
proposed.
The last correction is in Part 60. The
correction involves a change of
references in § 60.25. The change was
proposed with the other regulations on
August 7,1978, but was inadvertently
left out of the final promulgation.
Part 60 of Title 40, Code of Federal
Regulations, is amended as follows:
Section 60.25, paragraph (e), is
amended by changing the reference to a
semi-annual report required by § 51.7 to
an annual report required by § 51.321.
As amended, | 60.25 reads as follows:
§ €0.25 Emission inventories, source
surveillance, reports.
*****
(e) The State shall submit reports on
progress in plan enforcement to the
Administrator on an annual (calendar
year) basis, commencing with the first
full report period after approval of a
plan or after promulgation of a plan by
the Administrator. Information required
under this paragraph must be included
in the annual report required by § 51.321
of this chapter.
*****
(Sec. 110, 301(a), 319 of the Clean Air Act as
amended [42 U S C 7410. 7601(a). 7619))
|FR Dor 70-34525 Filed 11-8-79 8 45 am]
Federal Register / Vol. 44, No. 233 / Monday. December 3, 1979
10 5
40 CFR Part 60
[FRL 1369-3]
New Source Performance Standards;
Delegation of Authority to the State of
Maryland
AGENCY: Environmental Protection
Agency.
ACTION: Final rulemaking.
SUMMARY: Pursuant to the delegation of
authority for New Source Performance
Standards (NSPS) to the State of
Maryland on September 15,1978, EPA is
today amending 40 CFR 60.4, Address, to
reflectJhis delegation.
EFFECTIVE DATE: December 3,1979.
FOR FURTHER INFORMATION CONTACT:
Tom Shiland, 215 597-7915.
SUPPLEMENTARY INFORMATION: A Notice
announcing this delegation is published
today elsewhere in this Federal Register.
The amended 60.4 which adds the
address of the Maryland Bureau of Air
Quality to which all reports, requests,
applications, submittals. and
communications to the Administrator
pursuant to this part must also be
addressed, is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected. The delegation which is
reflected by this administrative
amendment was effective on September
15,1978, and it serves no purpose to
delay the technical change of this
address to the Code of Federal
Regulations.
This rulemaking is effective
immediately, and is issued under the
authority of Section 111 of the Clean Air
Act, as amended, 42 U.S.C. 7411.
Dated: November 14,1979.
Douglas M. Costle,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising Subparagraph (V) to read as
follows:
§60.4 Address.
*****
(b) * * *
(AHU)' * *
(V) State of Maryland: Bureau of Air
Quality and Noise Control, Maryland State
Department of Health and Mental Hygiene,
201 West Preston Street, Baltimore, Maryland
21201.
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Federal Register / Vol. 44. No. 237 / Friday. December 7. 1979 / Rules and Regulations
106
40 CFR Part 60
[FRL 1353-2]
Standards of Performance for New
Stationary Sources; Delegation of
Authority to State of Delaware
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends 40
CFR 60.4 to reflect delegation to the
State of Delaware of authority to
implement and enforce certain
Standards of Performance for New
Stationary Sources.
EFFECTIVE DATE: December 7,1979.
FOR FURTHER INFORMATION CONTACT:
Joseph Arena, Environmental Scientist,
Air Enforcement Branch, Environmental
Protection Agency, Region III, 6th and
Walnut Streets, Philadelphia,
Pennsylvania 19106, Telephone (215)
597-4561.
SUPPLEMENTARY INFORMATION:
I. Background
On October 5,1978, the State of
Delaware requested delegation of
authority to implement and enforce
certain Standards of Performance for
New Stationary Sources for Sulfuric
Acid Plants. The request was reviewed
and on October 9,1979 a letter was sent
to John E. Wilson III, Acting Secretary,
Department of Natural Resources and
Environmental Control, approving the
delegation and outlining its conditions
The approval letter specified that if
Acting Secretary Wilson or any other
representatives had any objections to
the conditions of delegation they were
to respond within ten (10) days after
receipt of the letter. As of this date, no
objections have been received.
II. Regulations Affected by this
Document
Pursuant to the delegation of authority
for certain Standards of Performance for
New Stationary Sources to the State of
Delaware, EPA is today amending 40
CFR 60.4, Address, to reflect this
delegation. A Notice announcing this
delegation is published today in the
Notices Section of this Federal Register.
The amended § 60.4, which adds the
address of the Delaware Department of
Natural Resources and Environmental
Control, to which all reports, requests,
applications, submittals, and
communications to the Administrator
pursuant to this part must also be
addressed, is set forth below.
III. General
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemakmg effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected. The delegation which is
reflected by this administrative
amendment was effective on October 9,
1979, and it serves no purpose to delay
the technical change of this address to
the Code of Federal Regulations
This rulemaking is effective
immediately, and is issued under the
authority of Section 111 of the Clean Air
Act as amended, 42 U.S.C. 7411.
Dated: December 3,1979.
Douglas M. Costle,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (I) to read as
follows:
§ 60.4 Address.
*****
(b) * ' *
(A)-(H) ' * *
(I) Stale of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants, asphalt concrete plants; storage
vessels for petroleum liquids; sulfuric acid
plants; and sewage treatment plants only.
Delaware Department of Natural Resources
and Environmental Control, Edward Tatnall
Building, Dover, Delaware 19901.
|FR Doc 79-37655 Filed 12-6-79. 8:45 am)
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Federal Register / Vol. 44, No. 250 / Friday, December 28, 1979 / Rules and Regulations
107
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
(FRL 1366-3]
Standards of Performance for New
Stationary Sources; Adjustment of the
Opacity Standard for a Fossil Fuel-
Fired Steam Generator
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action adjusts the NSPS
opacity standard (40 CFR Part 60,
Subpart D) applicable to Southwestern
Public Service Company's Harrington
Station Unit #1 in Amarillo, Texas. The
action is based upon Southwestern's
demonstration of the conditions that
entitle it to such an adjustment under 40
CFR 60.11(e).
EFFECTIVE DATE: December 28,1979.
ADDRESS: Docket No. EN-79-13,
containing material relevant to this
rulemaking, is located in the U.S.
Environmental Protection Agency,
Central Docket Section, Room 2903 B,
401 M St., SW., Washington, D.C. 20460.
The docket may be inspected between 8
a.m. and 4 p.m. on weekdays, and a
reasonable fee may be charged for
copying.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
the Administrator in the development of
this rulemaking. The docketing system is
intended to allow members of the public
and industries involved to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process.
FOR FURTHER INFORMATION CONTACT:
Richard Biondi, Division of Stationary
Source Enforcement (EN-341),
Environmental Protection Agency, 401 M
Street. SW., Washington, DC 20460,
telephone No. 202-755-2564.
SUPPLEMENTARY INFORMATION:
Background
The standards of performance for
fossil fuel-fired steam generators as
promulgated under Subpart D of Part 60
on December 23.1971 (36 FR 24876) and
amended on December 5,1977 [42 FR
61537) allow emissions of up to 20%
opacity (6-minute average), except that
27% opacity is allowed for one 6-minute
period in any hour. This standard also
requires continuous opacity monitoring
and requires reporting as excess
emissions all hourly periods during
which there are two or more 6-minute
periods when the average opacity
exceeds 20%
On December 15.1977, Southwestern
Public Service Company (SPSC) of
Amarillo, Texas, petitioned the
Administrator under 40 CF'R 60.11(e) to
adjust the 20% opacity standard
applicable to its Harrington Station
coal-fired Unit #1 in Amarillo. Texas.
The Administrator proposed, on June 29,
1979 (44 FR 37960), to grant the prtition
for adjustment, concluding that SPSC
had demonstrated the presence at its
Harrington Station Unit #1 of the
conditions that entitle it to such relief,
as specified in 40 CFR 60.11(e)(3).
These final regulations are identical to
the proposed ones. EPA hereby grants
SPSC's petition for adjustment for
Harrington Station Unit #1 from
compliance with the opacity standard of
40 CFR 60.42[a)(2). As an alternative,
SPSC shall not cause to be discharged
into the atmosphere from the Harrington
Station Unit #1 any gases which exhibit
greater than 35% opacity (6-minute
average), except that a maximum of 42%
opacity shall be permitted for not more
than one 6-minute period in any hour.
This adjustment will not relieve SPSC of
its obligation to comply with any other
federal, state or local opacity
requirements, or particulate matter, SO2
or NO, control requirements.
Comments
Two comment letters were received,
both from industry and both supporting
the proposed action. One industry
representative approved of EPA efforts
to adjust NSPS to account for well-
known opacity difficulties found in large
steam electric generating units which
have hot side electrostatic precipitators
and combust low-sulfur western coal.
A second industry representative
suggested that the use of Best Available
Control Technology on coal-fired units
has not assured compliance with
applicable opacity standards, and that
opacity standards do not complement
standards for particulate emissions. EPA
disagrees with this comment. Violations
of opacity standards generally reflect
violations of mass emission standards,
and EPA will continue to impose opacity
standards as a valued tool in insuring
proper operation and maintenance of air
pollution control devices.
Miscellaneous
This revision is promulgated under the
authority of Section 111 and 301(a) of
the Clean Air Act, as amended (42
U.S.C. 7411 and 7601(a)).
Dated: December 17. 1979.
Douglas M. Costle,
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
40 CFR part 60 is amended as follows:
Subpart D—Standards of Performance
for Fossil Fuel-Fired Steam Generators
1. Section 60.42 is amended by adding
paragraph (b)(l) as follows:
§ 60.42 Standard for particulate matter.
(a) * * *
(b)(l) On and after (the date of
publication of this amendment), no
owner or operator shall cause to be
discharged into the atmosphere from the
Southwestern Public Service Company's
Harrington Station Unit #1, in Amarillo,
Texas, any gases which exhibit greater
than 35% opacity, except that a
maximum of 42% opacity shall be
permitted for not more than 6 minutes in
any hour.
(Sec. Ill, 301(a), Clean Air Act as amended
(42, U.S.C. 7411, 7601))
2. Section 60.45(g)(l) is amended by
adding paragraph (i) as follows:
§ 60.45 Emission and fuel monitoring.
* * * * *
(8) * * *
(I)''*
(i) For sources subject to the opacity
standard of § 60.42(b)(l), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 35 percent opacity,
except that one six-minute average per
hour of up to 42 percent opacity need
not be reported.
|FR Doc 78-J9509 Filed 12-27-78 B 45 am |
108
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1392-6]
Standards of Performance for New
Stationary Sources; Delegation of
Authority to Commonwealth of
Pennsylvania
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends 40
CFR 60.4 to reflect delegation to the
Commonwealth of Pennsylvania for
authority to implement and enforce
certain Standards of Performance for
New Stationary Sources.
EFFECTIVE DATE: January 16,1980.
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Federal Register / Vol. 45, No. 11 / Wednesday, January 16, 1980 / Rules and Regulations
FOR FURTHER INFORMATION CONTACT:
Joseph Arena, Environmental Scientist,
Air Enforcement Branch, Environmental
Protection Agency, Region III, 6th and
Walnut Streets, Philadelphia,
Pennsylvania 19106, Telephone (215)
597-4561.
SUPPLEMENTARY INFORMATION:
I. Background
On October 1,1979, the
Commonwealth of Pennsylvania
requested delegation of authority to
implement and enforce certain
Standards of Performance for New
Stationary Sources. The request was
reviewed and on December 7,1979 a
letter was sent to Clifford L. Jones,
Secretary, Department of Environmental
Resources, approving the delegation and
outlining its conditions. The approval
letter specified that if Secretary Jones or
any other representatives had any
objections to the conditions of
delegation they were to respond within
ten (10) days after receipt of the letter.
As of this date, no objections have been
received.
II. Regulations Affected by This
Document
Pursuant to the delegation of authority
for Standards of Performance for New
Stationary Sources to the
Commonwealth of Pennsylvania, EPA is
today amending 40 CFR 60.4, Address, to
reflect this delegation. A Notice
announcing this delegation is published
today in the Federal Register. The
amended § 60.4, which adds the address
of the Pennsylvania Department of
Environmental Resources, to which all
reports, requests, applications,
submittals, and communications to the
Administrator pursuant to this part must
also be addressed, is set forth below.
III. General
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected. The delegation which is
reflected by this administrative
amendment was effective on December
7,1979, and it serves no purpose to
delay the technical change of this
address to the Code of Federal
Regulations.
This rulemaking is effective
immediately, and is issued under the
authority of Section 111 of the Clean Air
Act, as amended, 42 U.S.C. 7411.
Dated: December 7,1979.
R. Sarah Compton,
Director, Enforcement Division.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (OO) to read
as follows:
§60.4 Address.
*****
(b) * * *
(A)-{NN] * * *
(OO) Commonwealth of Pennsylvania:
Department of Environmental Resources,
Post Office Box 2063, Harrisburg,
Pennsylvania 17120.
[FR Doc 80-1468 Filed 1-15-80; M5 am)
109
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1374-2]
Standards of Performance for New
Stationary Sources; Modification,
Notification, and Reconstruction;
Amendment and Correction
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This amendment revokes the
bubble concept as a means of
determining what constitutes a
"modified" source for the purpose of
applying new source performance
standards promulgated under the Clean
Air Act. The United States Court of
Appeals for the District of Columbia
Circuit rejected the bubble concept in
ASARCO v. EPA, 578 F.2d 319. The
intent of this action is to comply with
the Court's ruling. This action also
amends the definition of "capital
expenditure" and updates a statutory
reference.
EFFECTIVE DATE: January 23,1980.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Background
On December 16,1975 (40 FR 58416),
EPA promulgated amendments to the
general provisions of 40 CFR Part 60.
The purpose of those amendments was,
in part, to clarify the definition of
"modification" in the Clean Air Act
(hereafter referred to as the Act) with
regard to a stationary source. The
general provisions of 40 CFR Part 60
apply to all standards of performance
for new, modified, and reconstructed
stationary sources promulgated under
section 111 of the Act.
"Modification" is defined in those
amendments as any physical change in
the method of operation of an existing
facility which increases the amount of
any air pollutant (to which a standard
applies) emitted into the atmosphere by
that facility or which results in the
emission of any air pollutant (to which a
standard applies) into the atmosphere
not previously emitted. "Existing
facility" means any apparatus of the
type for which a standard of
performance is promulgated in 40 CFR
Part 60, but the construction or
modification of which was commenced
before the date of proposal of that
standard. Upon modification, an existing
facility becomes an "affected facility,"
the basic unit to which a standard of
performance applies. Depending on the
circumstances of each particular
regulation, EPA may designate an entire
plant as an affected facility of an
individual production process or piece
of equipment within a plant as an
affected facility.
The amendments to the general
provisions of 40 CFR Part 60 also
expanded the statutory definition of
"stationary source" to reflect EPA's
interpretation of the language of the Act.
"Stationary source" is defined in the Act
as a "building, facility, or installation
which emits or may emit any air
pollutant" [section lll(a){3)]. The
amendments expanded this definition
with the addition, "and which contains
any one or combination of the following:
(1) Affected facilities.
(2) Existing facilities.
(3) Facilities of the type for which no
standards have been promulgated in this
part."
Thus, a distinction was made between
"affected facility," any apparatus to
which a standard applies, and
"stationary source," which could be a
combination of affected, existing, and
other facilities.
Based on these interpretive
definitions, 5 60.14(d) of the
amendments allowed an existing facility
to undergo a physical or operational
change but not be considered modified if
emission increases associated with the
physical or operational change were
offset by emission decreases of the same
pollutant from other affected and
existing facilities at the same stationary
source. This is referred to as the "bubble
concept."
In effect, a "bubble" could be placed
over an entire plant when determining if
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Federal Register / Vol. 45, No. 16 / Wednesday, January 23, 1980 / Rules and Regulations
• physical or operational change to an
existing facility within the plant
constituted a modification. Emissions of
a pollutant from an existing facility
could increase as a result of a physical
or operational change but that facility
would not be deemed "modified" as
long as emissions of that pollutant
coming out of the "bubble" over all
affected and existing facilities at the
plant did not increase.
EPA did not extend the bubble
concept to new-facility construction at
existing plant sites.
Challenges to the bubble concept
The Sierra Club challenged EPA's use
of the bubble concept in determining if a
modification of an existing facility had
taken place for the purpose of applying
standards of performance for new,
modified, and reconstructed stationary
sources promulgated under section 111
of the Act. The Sierra Club contended
that the interpreted definition of
"stationary source" promulgated by
EPA, and essential to EPA's use of the
bubble concept, was inconsistent with
the language of section 111 of the Act.
Sierra Club argued that the Act defines
a stationary source as an individual
building, structure, facility or
installation as distinguished from a
combination of such units. Sierra Club
claimed that once EPA had chosen the
affected facility to which standards of
performance apply, it could not
subsequently examine a combination of
existing and affected facilities for the
purpose of determining if a particular
existing facility had been modified, and
was therefore subject to standards.
ASARCO also challenged this use of
the bubble concept by EPA, but for a
different reason. ASARCO claimed that
the bubble concept should be extended
to cover new source construction at
existing plant sites rather than to
modifications only.
In a decision rendered January 27,
1978, the United States Court of Appeals
for the District of Columbia Circuit
agreed with the Sierra Club and rejected
the bubble concept as a means of
determining if a modification to an
existing facility had occurred for the
purpose of applying standards of
performance under section 111 of the
Act (ASARCO v. EPA, 578 F.2d 319). The
Court held that EPA had no authority to
change the basic unit to which the NSPS
apply from a single building, structure,
facility or installation as specified in the
Act to a combination of such units. In
addition, the Court ruled that since
EPA's use of the bubble concept for
determining modifications was illegal to
begin with, the bubble concept could not
be extended to cover new sources as
requested by industry.
In response to the Court's decision,
EPA is, with this action, deleting the
portions of § 60.14 of the general
provisions of 40 CFR Part 60 which
implement the bubble concept. The
definition of "stationary source" in
S 60.2 is also deleted. For the purposes
of regulations promulgated in 40 CFR
Part 60, the term "stationary source"
will hereafter have the same meaning as
in the Act.
Miscellaneous
The definition of "capital
expenditure" in § 60.2 is being amended
with the qualification that when
computing the total expenditure for a
physical or operational change to an
existing facility, it must not be reduced
by any "excluded additions" as defined
in IRS Publication 534, as would be done
for tax purposes. This qualification was
noted in the preamble to the original
regulation but not included in the
regulation text as intended.
Finally, the reference to "section
119(d)(5)" of the Act in § 60.14(e}(4) is
changed to "section lll(a)(8)" to reflect
changes in the 1977 Clean Air Act
Amendments (Public Law 95-95, August
7,1977).
Since these actions reflect the
mandate of the Court, correct an
unintentional omission, and update a
statutory reference, notice and public
comment thereon is unnecessary and
good cause exists for making them
effective immediately.
Dated: January 16,1980.
Douglas M. Costle,
Administrator.
40 CFR Part 60 is amended as follows:
1. Section 60.2 is amended by deleting
the definition of "Stationary source" and
by revising the definition of "Capital
expenditure" as follows:
§ 60.2 Definitions.
*****
"Capital expenditure" means an
expenditure for a physical or
operational change to an existing facility
which exceeds the product of the
applicable "annual asset guideline
repair allowance percentage" specified
in the latest edition of Internal Revenue
Service (IRS) Publication 534 and the
existing facility's basis, as defined by
section 1012 of the Internal Revenue
Code, However, the total expenditure
for a physical or operational change to
an existing facility must not be reduced
by any "excluded additions" as defined
in IRS Publication 534, as would be done
for tax purposes.
§60.7 [Amended]
2. In § 60.7, the first sentence in
paragraph (a)(4) is amended by deleting
the phrase, " and the exemption is not
denied under § 60.14(d)(4)."
§60.14 [Amended]
3. In § 60.14, the first sentence of,
paragraph (a) is amended, paragraph (d)
is revoked and reserved, the last
sentence of paragraph (e)(4) is amended,
and paragraph (g) is amended as
follows:
§60.14 Modification.
(a) Except as provided under
paragraphs (e) and (f) of this section,
any physical or operational change to an
existing facility which results in an
increase in the emission rate to the
atmosphere of any pollutant to which a
standard applies shall be considered a
modification within the meaning of
section 111 of the Act. * * *
*****
(d) [Reserved]
(e) * * *
(4) * * * Conversion to coal required
for energy considerations, as specified
in section lll(a)(8) of the Act, shall not
be considered a modification.
*****
(g) Within 180 days of the completion
of any physical or operational change
subject to the control measures specified
in paragraph (a) of this section,
compliance with all applicable
standards must be achieved.
(Sec. Ill, 301(a) of the Clean Air Act as
amended [42 U.S.C. 7411, 7801(a)]).
(FR Doc 80-2122 Filud 1-22-80; 8 45 am)
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL -M04-6J
Standards of Performance for New
Stationary Sources; Electric Utility
Steam Generating Units; Decision in
Response to Petitions for
Reconsideration
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Denial of Petitions for
Reconsideration of Final Regulations.
SUMMARY: The Environmental Defense
Fund, Kansas City Power and Light
Company, Sierra Club, Sierra Pacific
Power Company and Idaho Power
Company, State of California Air
Resources Board, and Utility Air
Regulatory Group submitted petitions
for reconsideration of the revised new
source performance standards for
electric utility steam generating units
that were promulgated on June 11,1979
(44 FR 33580). The petitions were
evaluated collectively since the
petitioners raised several overlapping
issues. When viewed collectively, the
petitioners sought reconsideration of the
standards of performance for sulfur
dioxide (SO^), particulate matter, and
nitrogen oxides (NO,). In denying the
petitions, the Administrator found that
the petitioners had failed to satisfy the
statutory requirements of section
307(d)(7)(B) of the Clean Air Act. That
is, the petitioners failed to demonstrate
either (1) that it was impractical to raise
their objections during the period for
public comment or (2) that the basis of
their objection arose after the close of
the period for public comment and the
objection was of central relevance to the
outcome of the rule. This notice also
responds to certain procedural issues
raised by the Environmental Defense
Fund (EOF). It should be noted that the
Natural Resources Defense Council
(NRDC) filed a July 9, 1979, letter in
which they concurred with the
procedural issues raised by EDF.
DATES: Effective February 6,1980.
Interested persons may advise the
Agency of any technical errors by
March 7,1980.
ADDRESSES: EPA invites information
from interested persons. This
information should be sent to: Mr. Don
R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
Docket Number OAQPS-78-1
contains all supporting materials used
by EPA in developing the standards,
including public comments and
materials pertaining to the petitions for
reconsideration. The docket is available
for public inspection and copying
between 9:00 a.m. and 4:00 p.m., Monday
through Friday at EPA's Central Docket
Section, Room 2903B, Waterside Mall,
401 M Street, SW., Washington. D.C.
20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
On September 19,1978, pursuant to
Section 111 of the Clean Air Act
Amendments of 1977, EPA proposed
revised standards of performance to
limit emissions of sulfur dioxide (SO2),
particulate matter, and nitrogen oxides
(NOi) from new, modified, and
reconstructed electric utility steam
generating units (43 FR 42154). A public
hearing was held on December 12 and
13,1978. In addition, on December 8,
1978, EPA published additional
information on the proposed rule (43 FR
57834). In this notice, the Administrator
set forth the preliminary results of the
Agency's analysis of the environmental,
economic, and energy impacts
associated with several alternative
standards. This analysis was also
presented at the public hearing on the
proposed standards. The public
comment period was extended until
January 15,1979, to allow for comments
on this information.
After the Agency had carefully
evaluated the more than 600 comment
letters and related documents, the
Administrator signed the final standards
on June 1,1979. In turn, they were
promulgated in the Federal Register on
June 11,1979.
On June 1,1979, the Sierra Club filed a
petition for judicial review of the
standards with the United States Court
of Appeals for the District of Columbia.
Additional petitions were filed by
Appalachian Power Company, et al., the
Environmental Defense Fund, and the
State of California Air Resources Board
before the close of the filing period on
August 10,1979.
In addition, pursuant to section
307(d)(7)(B) of the Clean Air Act, the
Environmental Defense Fund, Kansas
City Power and Light Company, Sierra
Club, Sierra Pacific Power Company and
Idaho Power Company, State of
California Air Resources Board, and
Utility Air Regulatory Group petitioned
the Administrator for reconsideration of
the revised standards.
Section 307(d)(7)(B) of the Act
provides that:
Only an objection to a rule or procedure
which was raised with reasonable specificity
during the period for public comment
(including any public hearing] may be raised
during judicial review. If the person raising
an objection can demonstrate to the
Administrator that it was impracticable to
raise such objection within such time or if the
grounds for such objection arose after the
period for public comment (but within the
time specified for judicial review) and if such
objection is of central relevance to the
outcome of the rule, the Administrator shall
convene a proceeding for reconsideration of
the rule and provide the same procedural
rights as would have been afforded had the
information been available at the time the
rule was proposed. If the Administrator
refuses to convene such a proceeding, such
person may seek review of such refusal in the
United Stales Court of Appeals for the
appropriate circuit (as provided in subsection
(b)).
The Administrator's findings and
responses to the issues raised by the
petitioners are presented in this notice.
Summary of Standards
Applicability
The standards apply to electric utility
steam generating units capable of firing
more than 73 MW (250 million Btu/hour)
heat input of fossil fuel, for which
construction is commenced after
September 18,1978. Industrial
cogeneration facilities that sell less than
25 MW of electricity, or less than one-
third of their potential electrical output
capacity, are not covered. For electric
utility combined cycle gas turbines,
applicability of the standards is
determined on the basis of the fossil-fuel
fired to the steam generator exclusive of
the heat input and electrical power
contribution of the gas turbine.
SO, Standards
The SOz standards are as follows:
(1) Solid and solid-derived fuels
(except solid solvent refined coal): SO2
emissions to the atmosphere are limited
to 520 ng/J (1.20 Ib/million Btu) heat
input, and a 90 percent reduction in
potential SO2 emissions is required at all
times except when emissions to the
atmosphere are less than 260 ng/J (0.60
Ib/million Btu) heat input. When SO,
emissions are less than 260 ng/J (0.60 lb/
million Btu) heat input, a 70 percent
reduction in potential emissions is
required. Compliance with the emission
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limit and percent reduction requirements
is determined on a continuous basis by
using continuous monitors to obtain a
30-day rolling average. The percent
reduction is computed on the basis of
overall SOS removed by all types of SO2
and sulfur removal technology, including
flue gas desulfurization (FGD) systems
and fuel pretreatment systems (such as
coal cleaning, coal gasification, and coal
liquefaction). Sulfur removed by a coal
pulverizer or in bottom ash and fly ash
may be included in the computation.
(2) Gaseous and liquid fuels not
derived from solid fuels: SO» emissions
into the atmosphere are limiteed to 340
ng/J (0.80 Ib/million Btu) heat input, and
a 90 percent reduction in potential SO,
emissions is required. The percent
reduction requirement does not apply if
SO2 emissions into the atmosphere are
less than 86 ng/J (0.20 Ib/million Btu)
heat input. Compliance with the SOi
emission limitation and percent
reduction is determined on a continuous
basis by using continuous monitors to
obtain a 30-day rolling average.
(3) Anthracite coal: Electric utility
steam generating units firing anthracite
coal alone are exempt from the
percentage reduction requirement of the
SO? standard but are subject to the 520
ng/J (1.20 Ib/million Btu) heat input
emission limit on a 30-day rolling
average, and all other provisions of the
regulations including the particulate
matter and NO, standards.
(4) Noncontinental areas: Electric
utility steam generating units located in
noncontinental areas (State of Hawaii,
the Virgin Islands, Guam, American
Samoa, the Commonwealth of Puerto
Rico, and the Northern Marina Islands)
are exempt from the percentage
reduction requirement of the SOj
standard but are subject to the
applicable SO, emission limitation and
all other provisions of the regulations
including the particulate matter and NO,
standards.
(5) Resource recovery facilities:
Resource recovery facilities which
incorporate electric utility steam
generating units that fire less than 25
percent fossil-fuel on a quarterly (90-
day) heat input basis are not subject to
the percentage reduction requirements
but are subject to the 520 ng/J (1.20 lb/
million Btu) heat input emission limit.
Compliance with the emission limit is
determined on a continuous basis using
continuous monitoring to obtain a 30-
day rolling average. In addition, such
facilities must monitor and report their
heat input by fuel type.
(6) Solid solvent refined coal: Electric
utility steam generating units firing solid
solvent refined coal (SRC I) are subject
to the 520 ng/J (1.20 Ib/million Btu) heat
input emission limit (30-day rolling
average) and all requirements under the
NO, and particulate matter standards.
Compliance with the emission limit is
determined on a continuous basis using
a continuous monitor to obtain a 30-day
rolling average. The percentage
reduction requirement, which is
obtained at the refining facility itself, is
85 percent reduction in potential SOa
emissions on a 24-hour (daily) averaging
basis. Compliance is to be determined
by Method 19. Initial full-scale
demonstration facilities may be granted
a commercial demonstration permit
establishing a requirement of 80 percent
reduction in potential emissions on a 24-
hour (daily) basis.
Particulate Matter Standards
The particulate matter standard limits
emissions to 13 ng/J (0.03 Ib/million Btu)
heat input. The opacity standard limits
the opacity of emissions to 20 percent (6-
minute average). The standards are
based on the performance of a well-
designed and operated baghouse or
electrostatic precipitator.
M3, Standards
The NO, standards are based on
combustion modification and vary
according to the fuel type. The
standards are:
(1) 86 ng/J (0.20 Ib-million Btu) heat
input from the combustion of any
gaseous fuel, except gaseous fuel
derived from coal;
(2) 130 ng/J (0.30 Ib/million Btu) heat
input from the combustion of any liquid
fuel, except shale oil and liquid fuel
derived from coal;
(3) 210 ng/J (0.50 Ib/million Btu) heat
input from the combustion of
subbituminous coal, shale oil, or any
solid, liquid, or gaseous fuel derived
from coal;
(4) 340 ng/J (0.80 Ib/million Btu) heat
input from the combustion in a slag tap
furnace of any fuel containing more than
25 percent, by weight, lignite which has
been mined in North Dakota, South
Dakota, or Montana;
(5) Combustion of a fuel containing
more than 25 percent, by weight, coal
refuse is exempt from the NO, standards
and monitoring requirements; and
(6) 260 ng/J (0.60 Ib/million Btu) heat
input from the combustion of anthracite
coal, bituminous coal, or any other solid
fuel not specified under (3), (4), or (5).
Continuous compliance with the NO,
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
with the NO, emission limits will assure
compliance with the percent reduction
requirements.
Emerging Technologies
The standards include provisions
which allow the Administrator to grant
commercial demonstration permits to
allow less stringent requirements for the
initial full-scale demonstration plants of
certain technologies. The standards
include the following provisions:
(1) Facilities using SRC I are subject to
an emission limitation of 520 ng/J (1.20
Ib/million Btu) heat input, based on a
30-day rolling average, and an emission
reduction requirement of 85 percent,
based on a 24-hour average. However,
the percentage reduction allowed under
a commercial demonstration permit for
the initial full-scale demonstration plant
using SRC I would be 80 percent (based
on a 24-hour average). The plant
producing the SRC I would monitor to
ensure that the required percentage
reduction (24-hour average) is achieved
and the power plant using the SRC I
would monitor to ensure that the 520 ng/
Jlieat input limit (30-day rolling
average) is achieved.
(2) Facilities using fluidized bed
combustion (FBC) or coal liquefaction
would be subject to the emission
limitation and percentage reduction
requirement of the SO2 standard and to
the particulate matter and NO,
standards. However, the reduction in
potential SO2 emissions allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using FBC would be 85 percent
(based on a 30-day rolling average). The
NO, emission limitation allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using coal liquefaction would be
300 ng/J (0.70 Ib/million Btu) heat input,
based on a 30-day rolling average.
(3) No more than 15,000 MW
equivalent electrical capacity would be
allotted for the purpose of commercial
demonstration permits. The capacity
will be allocated as follows:
Technology
Equivalent electrical
Pollutant capacity MW
Solid solvent-refined coal . .. .
Fluidized bed combustion
(atmospheric)
Fluidized bed combustion
(pressunzed)
Coal liquefaction
SO,
SO,
so.
NO,
6.000-10.000
400-3,000
400-1 200
750-10000
Compliance Provisions
Continuous compliance with the SO*
and NO, standards is required and is to
be determined with continuous emission
monitors. Reference methods or other
approved procedures must be used to
supplement the emission data when the
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conlinuous emission monitors
malfunction in order to provide emission
data for at Irast 18 hours of each day for
at least 22 days out of any 30
consecutive days of boiler operation.
A malfunctioning FGD system may be
b\ passed under emergency conditions.
Compliance with the paniculate
standard is determined through
performance tests. Continuous monitors
are required to measure and record the
opacity of emissions. The continuous
op;icity data will be used to identify
excess emissions to ensure that the
particulate matter control system is
being properly operated and maintained.
Issues Raised in the Petitions for
Reconsideration
1. SOi Maximum Emission Limitation of
520 ng/J (1.2 Ib/Millton BtuJ Htiat Input
The Environmental Defense Fund
(EOF), Siena Club, and State of
California Air Resources Board (CARD)
requested that a proceeding be
convened to reconsider the maximum
SO2 emission limitation of 520 ng/J (1.2
Ib/million Btu) heat input. In their
petition, EDF stt forth several
procedural questions as the basis for
their request. First, they maintained that
they did not have the opportunity to
comment on certain information which
was submitted to EPA by the National
Coal Association at an April 5,1979,
meeting and in subsequent
correspondence. The information
pertained to the impacts that different
emission limitations will have on coal
production in the Midwest and Northern
Appalachia. They argued that this
information materially influenced the
Administrator's final decision. Further,
they maintained that the
Administrator's decision in setting the
emission limitation was based on ex
parte communications and improper
congressional pressure.
The Sierra Club also raised objections
to information developed during the
post-comment period. They cited the
information supplied by the National
Coal Association, and the EPA staff
analysis of the impact that different
emission limitations would have on
burnable coal reserves. In addition, they
challenged the assumption that
conservatism in utility perceptions of
scrubber peiformance could create a
significant disincentive against the
burning of high-sulfur coal reserves The
Sierra Club maintained that this
inforrr.dtion is of "central relevance"
since it formed the basis of the
establishment of the final emission
limitation and that the Sierra Club was
denied the opportunity to comment on
Ihis information. Finally, the Sierra Club
and CARB subscribed fully to arguments
presented by EDF concerning ex parte
communications.
Background
The potential impact that the emission
limitation may have on high-sulfur coal
reserves did not arise for the first time in
the post-comment period. It was an
issue throughout the rulemaking. In the
proposal, the Agency stated that two
factors had to be taken into
consideration when selecting the
emission limitation—FGD efficiency and
the impact of the emission limitation on
high-sulfur coal reserves (43 FR 42160,
middle column). The proposal also
indicated that, in effect, scrubber
performance determines the maximum
sulfur content of coals that can be fired
in compliance with emission limitation
even when coal preparation is
employed. From the discussion it is clear
that the Administrator recognized that
midwestern high-sulfur coal reserves
could be severely impacted if the
emission limitation was not selected
with care (43 FR 42160, middle column).
In addition, the Administrator also
specifically sought comment on the
related question of new coal production
as it pertained to consideration of coal
impacts in the final decision (43 FR
42155, right column).
At the December 1978 public hearing
on the proposed standards, the Agency
specifically sought to solicit information
on the impact that lower SOZ emission
limits (below 520 ng/J (1.2 Ib/million
Btu) heat input) would have on high-
sulfur coal reserves. In response to
questions from an EPA panel member
and the audience, Mr. Hoff Stauffer of
ICF. Inc. (an EPA consultant) testified
that the potential impact of lower
emission limitations on high-sulfur coal
reserves would be greater in certain
states than was indicated by the results
of the macroeconomic analysis
conducted by his firm. He added further
that if the degree of reduction
achievable through coal preparation or
scrubbers changed from the values
assumed in the analysis (35 percent for
coal preparation on high-sulfur coal and
90 percent for scrubbers) the coal
impacts would vary accordingly. That is,
if greater reduction could be achieved
by either coal preparation or by
scrubbers the impacts would be
reduced. Conversely, if the degree of
reduction achievable by either coal
preparation or scrubbers was less than
the values assumed, the impacts would
be more severe (public hearing
transcript, December 12, 1978, pages 46-
47).
The subject was bicached again when
Mr. Richard Ayres, representing the
Natural Resources Defense Council and
serving as introductory spokesperson for
other public health and environmental
organizations, was asked by the panel
what effect lowering the emission
limitation would have on local high-
sulfur coal reserves. Mr. Ayres
responded that a lower emission
limitation may have the effect of
requiring certain coals to be scrubbed
more than required by the standard. He
added that the utilities would have an
economic choice of either buying local
high-sulfur coal and scrubbing more or
buying lower-sulfur coal which may not
be local and scrubbing less. He further
indicated that it was not clear that a
lower limitation would have the effect of
precluding any coal. In doing so, he
noted that the "conclusion depended
entirely on assumptions about the
possible emission efficiencies of
scrubbers." Finally, Mr. Ayres was
asked whether as long as production in
a given region increased that the
requirement of the Act to maximize the
use of local coal was satisfied. He
responded that it was a "matter of
degree" and that he would not say as
long as production in a given region did
not decline the statute was served
(public hearing transcript, December 12,
1978, pages 77-80).
Mr. Robert Rauch, representing the
Environmental Defense Fund, also
recognized in his testimony that
lowering the emission limitation to the
level recommended by EDF (340 ng/J
(0.8 Ib/million Btu) heat input) would
adversely impact high-sulfur coal
reserves. In his testimony he stated
"Adoption of the proposed lower ceiling
would result in the exclusion of certain
high-sulfur coal reserves from use in
power plants subject to the revised
standard." He added that the use of
adipic acid and other slurry additives
would enhance scrubber performance,
thereby alleviating the impacts on high-
sulfur coal (public hearing transcript,
December 13,1978, pages 189-191).
Mr. Joseph Mullan of the National
Coal Association testified in response to
a question from the hearing panel that
lowering the emission limitation from
520 ng/J (1.2 Ib/million Btu) heat input
would preclude the use of certain high-
sulfur coals. He added that the National
Coal Association would furnish data on
such impacts (public hearing transcript,
December 13,1978, page 246).
Turning now to the written comments
on the proposed standard submitted
jointly by the Natural Resources
Defense Council and the Environmental
Defense Fund, we see that they carefully
assessed the potential impacts on high-
sulfur coal reserves that could result
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from various emission limitations. They
concluded, "Generally, the higher the
percent removal requirement, the
smaller the percentage of coal reserves
which are effectively eliminated for use
by utility generating units." They went
on to argue that if their recommended
standard of 95 percent reduction in
potential SO2 emission was accepted a
lower emission limitation could be
adopted without adverse impacts on
coal reserves (OAQPS-78-1. IV-D-631,
page V-128).
Rationale for the Maximum Emission
Limit
The testimony presented at the public
hearing and the written comments
served to confirm the Agency's initial
position that scrubber performance and
potential impacts on high-sulfur coal
reserves had to be carefully considered
when establishing the emission
limitation. Meanwhile, it became
apparent that the analysis performed by
EPA's consultant on emission limits
below 520 ng/J (1.2 Ib/million Btu) heat
input might not fully reflect the impacts
on major high-sulfur coal production
areas. This finding was evident by study
of the consultant's report (OAQPS-78-1,
IV-A-5, Appendix D) which showed
that the model used to estimate coal
production in Appalachia and the
Midwest was relatively insensitive to
broad variations in the emission ceiling.
The Agency then concluded that the
macroeconomic model was adequate for
assessing national impacts on coal use,
but lacked the specificity to assess
potential dislocations in specific coal
production regions. In effect the analysis
tended to mask the impacts in specific
coal producing regions through
aggregation. Concern was also raised as
to the validity of the modeling
assumption that a 35 percent reduction
in potential SO2 emissions can be
achieved by coal washing on all high-
sulfur coal reserves.
In view of these concerns, EPA
concluded shortly after the close of the
comment period that additional analysis
was needed to support the final
emission limitation. In February, EPA
began analyzing the impacts of
alternative emission limits on local high-
sulfur coal reserves. To account for
actual and perceived efficiencies of
scrubbers, the staff assumed three levels
of scrubber control—85 percent, 90
percent, and 95 percent. In addition, two
levels of physical coal cleaning were
reflected. The first level was crushing to
1.5 inch top-size and the second was
crushing to % inch top-size, both
followed by wet beneficiation. In
addition, by using seam-by-seam data
on coal reserves and their sulfur
reduction potential (developed for EPA's
Office of Research and Development) it
was possible to estimate the sulfur
content of the final product coal based
on reported chemical properties of coals
in the reserve base (OAQPS-78-1, IV-E-
12). Since this approach did not require
the staff to assume a single level of
sulfur reduction for all coal preparation
plants, it introduced a major refinement
to the analysis previously performed by
EPA's consultant. The analysis was
substantially completed in March 1979
(OAQPS-78-1, IV-B-57 and IV-B-72).
The April 5,1979, meeting was called
to discuss coal reserve data and the
degree of sulfur removal achievable
with physical coal cleaning (OAQPS-
78-1, IV-E-10). The meeting gave EPA
the opportunity to present the results of
its analysis and to verify the data and
assumptions used with those persons
who are most knowledgeable on coal
production and coal preparation. EPA
sought broad representation at the
meeting. Invitees including not only the
National Coal Association but
representatives from the Environmental
Defense Fund, Natural Resources
Defense Council, Sierra Club, Utility Air
Regulatory Group, United Mine Workers
of America, and other interested parties.
The invitees were furnished copies of
the materials presented at the meeting,
subsequent correspondence from the
National Coal Association, and minutes
of the meeting.
The meeting served to confirm that
the coal reserve and preparation data
developed independently by the EPA
staff were in close agreement with those
prepared by the National Coal
Association (NCA). In addition, the
discussion led EPA to conclude that coal
preparation technology which required
crushing to 3/s-inch top-size would be
unduly expensive, lead to unacceptable
energy losses, and pose coal handling
problems (OAQPS-78-1, IV-E-11). As a
result, the Administrator revised his
assessment of state-of-art coal cleaning
technology (44 FR 33596, left column).
In an April 19,1979, letter to the
Administrator (OAQPS-78-1, IV-D-763).
attorneys for the Environmental Defense
Fund and the Natural Resources
Defense Council submitted comments on
the information presented by the
National Coal Association at the April 5,
1979, meeting and in a subsequent NCA
letter to the Administrator dated April 6,
1979. In their comments, they were
critical of the National Coal
Association's assumptions concerning
scrubber performance and the removal
efficiencies of coal preparation plants.
They also noted that the Associaton's
data was based on a small survey of the
total coal reserves in the Midwest and
Northern Appalachia. They argued
further that coal blending could serve to
reduce the adverse impact on high-sulfur
coal caused by a lower emission limit. In
doing so, they recognized that the
application of coal blending would have
to be undertaken on a case-by-case
basis. Finally, they maintained that
there is no evidence that the coal
industry would be unable to meet
increases in coal demand even if the
National Coal Association's reserve
data on coal preclusions were accepted
In conclusion, they noted that the
Association's data was of questionable
relevance since it was predicated on a
maximum removal efficiency of 90
percent.
Subsequent correspondence from the
National Coal Association served to
reaffirm a point that had been made
earlier in the rulemaking. That is,
utilities would have a choice of either
buying lower-sulfur coal and scrubbing
to meet the percent removal requirement
or buying higher-sulfur coal and
scrubbing more than required by the
standard in order to meet the emission
limitation. In addition, they cited the
conservative nature of utilities and
stressed that this would be reflected in
their coal buying practices. As was
discussed at the public hearing and in
the written comments such behavior by
utilities would result in adverse impacts
on the use of certain local high-sulfur
coals.
In reaching final conclusions about
the impact oi the SO2 standard on coal
production, the Administrator judged
that utilities would be inclined to select
coals that would meet the emission hmi!
with no more than 90 percent reduction
in potential SO2 emissions ' (44 FR
33590, left column). With this
assumption, the analysis revealed that
an emission limit of less than 520 r.g/J
(1.20 Ib/million Btj) heat input would
create a disincentive to burn a
significant portion of the coal reserves
in the Midwest and Northern
Appalachia (OAQPS-78-1, IV-B-72). If
the emission limit had been set at 430
ng/J (1.0 Ib/million Btu) heat input, 15
percent of the total reserve base in the
Eastern Midwest (Illinois, Indiana, and
Western Kentucky) would have been
impacted. The impact in Northern
Appalachia would be 6 percent and this
impact would have been concentrated in
the areas of Ohio and the northern part
of West Virginia. If only currently
'The previous version of the EPA anahsis had
assumed either 85 or 90 percent control levels in
addition to coal washing That approach
disregarded the fact that the net reduction in
potential SO? emissions may have been greater th
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
owned coal reserves are considered, up
to 19 percent of the high-sulfur coals in
some regions would be impacted
(OAQPS-78-1, IV-B-72). The
Administrator judged that such impacts
are unacceptable.
The final point made by NCA was
that utility coal buying practice typically
incorporates a margin of safety to
ensure compliance with SOj emission
limitations. Rather than purchasing a
high-sulfur coal that would barely
comply with the emission limit, the
prudent utility would adopt a more
conservative approach and purchase
coal that would meet the emission limit
with a margin of safety in order to
account for uncertainty in coal sulfur
variability. This approach, which
reflects sound engineering principles,
could result in the dislocation of some
high-sulfur coal reserves.
The Administrator determined that
consideration of a margin of safety in
coal buying practice was reasonable.
Using NCA's recommendation of an 8.5
percent margin (reported as "about 10
percent" in the preamble to
promulgation), coal impacts were
reanalyzed. This study showed
additional coal market dislocations
(OAQPS-78-1, IV-B-72). For example, in
Illinois, Indiana, and Western Kentucky,
the impact on coal reserves by a 430 ng/
J (1.0 Ib/million Btu) heat input emission
limit increased from 15 percent without
the margin to 22 percent when the
margin was assumed. Considering only
currently owned reserves, the impact
increased from 19 percent to 30 percent.
Even with the margin, the analysis
predicted no significant impact for a 520
ng/J (1.2 Ib/million Btu) heat input
standard.
Having determined the extent of the
potential coal impacts associated with a
lower emission limit, the Agency then
as.-essed the potential environmental
benefits. The assessment revealed that
by 1995 an emission limit of 430 ng/J (1.0
Ib/million Btu) heat input would reduce
national emissions by only 50 thousand
tons per year relative to the 520 ng/J (1.2
Ib/million Btu) heat input limit. That is,
the projected emissions from new plants
would be reduced from 3.10 million tons
to a 3.05 million tons as a result of the
more stringent emission limit (OAQPS-
78-1, IV-B-75).
The petitions providing no information
to either refute the assumptions or the
findings of the final coal impact
analysis. The Sierra Club argued that
EPA had misinterpreted its own analysis
of coal impacts (Sierra Club petition,
page 9). They maintained that the EPA
figures presented at the April 5 meeting
(OAQPS-78-1, IV-E-11, attachment 3)
supported establishment of a 340 ng/J
(0.8 Ib/million Btu) heat input standard.
In doing so the Sierra Club ignored the
analysis performed by the Agency after
the April 5 meeting, particularly with
respect to the Administrator finding that
utilities would purchase coal which
would meet the emission limit (with
margin) with no more than 90 percent
reduction in potential SO2 emissions.
In conclusion, the decision as to the
appropriate level of emission limitation
rested squarely on two factors. First, the
Administrator's finding that a 90 percent
reduction in potential SOj emissions,
measured as a 30-day rolling average,
represented the emission reduction
achievable through the use of the best
demonstrated system of emission
reduction, and second, that the marginal
environmental benefit of a 430 ng/J (1.0
Ib/million Btu) heat input standard
coupled with a 90 percent reduction in
potential SO2 emissions could not be
justified in light of the potential impacts
on high-sulfur coal reserves. If he had
determined, as some petitioners
suggested, that higher removal
efficiencies were achievable on high-
sulfur coals, the emission limitation
could have been established at a lower
level without significant impacts on
local high-sulfur coal reserves.
Environmental Defense Fund Procedural
Issues
EDF's petition objected to the fact that
after the close of the public comment
period, representatives of the National
Coal Association and a number of
members of Congress talked to EPA
officials and submitted documents to
EPA arguing that the ceiling should be
set at 520 ng/J (1.2. Ibs/million Btu) heat
input. EDF objected to these
communications on a number of
grounds. First, they argued that it was
improper, under Section 307(d) of the
Act, for the Agency to consider
information submitted more than 30
days after the public hearing. Second,
they objected that the Agency failed to
make transcripts of the oral
communications, and that, in any event,
the summaries of those communications
that the Agency placed in the docket
were inadequate. Third, they implied
that Agency officials received additional
oral communications which were not
documented in the rulemaking docket.
Fourth, they objected that these written
and oral communications were exparte
and therefore improper, citing, for
example, United States Lines, Inc. v.
FMC, 584 F. 2d 519 (D.C. Cir., 1978).
Fifth, they argued that the
Administrator's decision on the ceiling
was based in part on information
obtained in ex parte discussions and
thus not placed in the docket as of the
date of promulgation, in violation of
Section 307(d). Finally, they argued that
the communications from members of
Congress constituted improper pressure
on the Administrator's decision, citing,
for example, D.C. Federation of Civic
Associations \. Volpe, 459 F. 2d 1231
(D.C. Cir. 1972). EDF argued that these
alleged procedural errors were of
central relevance to the outcome of the
rule, and that the Agency should
therefore convene a proceeding to
reconsider.
The Administrator does not believe
that the procedures cited by EDF were
improper. Moreover, as discussed
below, any arguable errors were not of
central relevance to the outcome of the
rule, and therefore do not constitute
grounds for granting EDF's petition to
reconsider.
First, it was not improper for the
Administrator to consider information
submitted more than 30 days after the
public hearing. Section 307(d)(5) requires
that the Administrator consider
documents submitted up to 30 days after
the hearing. It does not forbid the
Administrator to consider additional
comments submitted after that 30-day
period.
Second, the Agency's summaries of
oral communications were adequate.
Section 307(d){5) does not require, as
EDF argues, that Agency officials keep
transcripts of their oral discussions with
persons outside the Agency. It simply
requires the Agency to make a transcript
of the public hearing on a proposed
rulemaking. Third, Agency officials
wrote memoranda of all significant oral
communcalions between Agency
officials and persons outside the
executive branch, such as the two
meetings with Senator Byrd, and the
memoranda were promptly placed in the
rulemaking docket. These memoranda
accurately reflect the information and
arguments communicated to the Agency.
Fourth, the oral and written
communications cited by EDF were not
exparte. The Agency promptly placed
the written comments in the rulemaking
docket where they were available to the
public. Also, the NCA sent copies of its
written comments directly to the
principal parties to the rulemaking,
including EDF and NRDC. Similarly, the
Agency placed the memoranda of oral
communcations in the docket where
they were available to the public. Any
member of the public has had the
opportunity to submit a petition for
reconsideration if that information was
used erroneously by EPA in setting the
standard, and several persons have
done so.
Fifth, contrary to EDF's assertion, the
Administrator's decision on the
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
emission ceiling was not based on any
information not in the docket
Finally, it was not improper for the
Administrator to listen to and consider
the views of Senators and Congressmen,
including Senator Byrd. It is not unusual
for members of Congress to express
their views on the merits of Agency
rulemaking, and it is entirely proper for
the Administrator to consider those
views.
F.DF objects particularly to a meeting
the Administrator attended with Senator
Byrd on April 26,1979, arguing that the
contact was exparle and improperly
influenced the Administrator's decision.
Neither contention is correct. A
memorandum summarizing the
discussion at the meeting was placed in
the docket, and members of the public
have had the opportunity to comment on
it, as EDF has done. No new information
was presented to the Administrator al
the meeting.
Senator Byrd's comments at this
meeting also did not improperly
influence the Administrator. Although
the Senator strongly urged the
Administrator to set the emission ceiling
at a level that would not preclude the
use of any significant coal reserves, the
Administrator had already concluded
from the 1977 Amendments to the Clean
Air Act that the revised standards
should not preclude significant reserves.
This view was based on the
Administrator's interpretation of the
legislative intent of the 1977
Amendments and was reflected in the
proposed emission ceiling of 520 ng/J
(1.2 Ibs/million Btu) heat input as
discussed in the preamble to the
proposed standards (43 FR 42160).
This view was reaffirmed in the final
rulemaking, based on the intent of the
1977 Amendments (44 FR 33595-33596).
Although the Administrator was aware
(as he would have been even in the
absence of a meeting) of Senator Byrd's
concern that a ceiling lower then 520 ng/
] (1.2 Ibs/million Btu) heat input would
inappropriately preclude significant coal
reserves, the Administrator's decision
was not based on Senator Byrd's
expression of concern. The
Administrator had already concluded
that anything more than a minimal
preclusion of the use of particular coal
reserves would, in the absence of
significant resulting emission reductions,
be inconsistent with the intent of the
1977 Amendments. Because the
Agency's analysis showed that even an
emission limit of 430 ng/J (1.0 Ibs/
million Btu) heat input could preclude
the use of up to 22 percent of certain
coal reserves without significantly
reducing overall emissions, the
Administrator's judgment was that a
ceiling lower than 520 ng/J (1.2 Ibs/
million Btu) heat input was not justified.
Thus, the views of Senator Byrd and
other members of Congress, at most,
served to reinforce the Administrator's
own judgment that the proper level for
the standard was 520 ng/J (1.2 Ibs/
million Btu) heat input. Even assuming
therefore, that it was improper for the
Administrator to consider the views of
members of Congress, this procedural
"error" was not of central relevance tc
the outcome of the rule.
//. SOj Minimum Control Level (70
Percent Reduction of Potential
Emissions)
The Kansas City Power and Light
Company (KCPL), Sierra Club, and
Utility Air Regulatory Group (UARG)
requested that a proceeding be
convened to reconsider the 70 percent
minimum control level which is
applicable when burning low-sulfur
coals. Both the Sierra Club and UARG
maintained that they did not have an
opportunity to fully comment on either
the final regulatory analysis or dry SO2
scrubbing technology since the phase 3
macroeconomic analysis of the standard
(44 FR 33603, left column) and
supporting data were entered into the
record after the close of the public
comment period Both claimed that their
evaluation of this additional information
provided insights which are of central
relevance to the Administrator's final
decision and that reconsideration of the
standard is warranted. The KCPL
petition did not allege improper
administrative procedures, but asked for
reconsideration based on their
evaluation of the merits of the standard.
In seeking a more stringent minimum
reduction requirement, the Sierra Club
contended that dry SO2 scrubbing is not
a demonstrated technology and,
therefore, no basis exists for a variable
control standard. Alternatively, the
Sierra Club maintained that if dry
technology is considered demonstrated
the record supports a more stringent
minimum control level With respect to
the regulatory analysis, the petition
charged that faulty analytical
methodology and assumptions led the
Agency to erroneous conclusions about
the impacts of the promulgated standard
relative to the more stringent uniform or
full control alternative. They suggested
that analysis performed -using proper
assumptions would support adoption of
a uniform standard.
In support of a less stringent minimum
reduction requirement, the UARG
petition presented a regulatory analysis
which was prepared by their consultant,
National Economic Research Associates
(NERA). Based on this study. UARG
argued that a 50 percent minimum
requirement would be superior in terms
of emissions, costs, and energy impacts.
Finally, they argued that a lower percent
reduction would provide greater
opportunity to develop dry SO2
scrubbing technology.
In (heir petition KCPL sought either «n
ehminalion of the percent reduction
requirement when emissions are 520
ng/J (1.2 Ib/million Btu) heat input or
less, or, as an alternative, a reduction m
the 70 percent requirement. In support of
their request, KCPL set forth several
arguments. First, they cited the
economic and energy impacts
associated with the application of
scrubbing technology on low sulfur
coals Second, they noted that a
significant portion of sulfur in the coal
they plan to burn will be removed in the
fly ash. Finally, they asserted that health
and welfare considerations do not
warrant scrubbing of low sulfur coals
since (heir uncontrolled SO2 emissions
are less than the emissions allowed by
the standard for high-sulfur coals with
90 percent scrubbing.
The primary basis for the UARG and
Sierra Club requests for reconsideration
of the minimum control level was the
Agency's phase 3 economic modeling
analysis (44 FR 33602). Because the
phase 3 analysis was completed after
the close of the public comment period,
it is important that the results of that
study are viewed in proper perspective
to their role in the Administrator's
decision. The petitioners implied that
the adoption of the 70 percent variable
control standard was based solely on
the phase 3 analysis and that the phase
3 analysis was a new venture by the
Agency, and therefore, the public was
excluded from active participation in the
decision process. This notion is false.
Contrary to views of the UARG and
the Sierra Club, the phase 3 study did
not mark a significant departure from
the Agency's earlier analysis of the
issue of uniform versus variable control.
No new economic modeling concepts
were introduced nor were any modeling
input assumptions changed from those
presented in the phase 2 analysis.
Instead, the phase 3 study served merely
•(a) to refine the analysis by
incorporating consideration of dry SO2
scrubbing in response to public
comments and (b) to facilitate
specification of the final standard. In
effect, phase 3 brought together the
results of an analysis that had
proceeded under close public scrutiny
for more than a year. In order to
consider the full range of applicability of
dry SOj scrubbing systems, it was
necessary to introduce a new alternative
standard—the variable control standard
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
with a 70 percent minimum control level.
Introduction of this option was
considered appropriate since it raised
the same kind of economic, legal, and
technical policy issues as the earlier
analyses of 33, 50, and 90 percent
minimum control options.
Within this context, many of the
objections to the economic modeling are
inappropriate grounds under section
307(d)(7)(B) for reconsideration since
they do not involve information on
which it was impracticable to comment
during the public comment period. For
example, the Sierra Club's comments
regarding modeling assumptions merely
restated those that had been
incorporated by reference into their
January 1979 comments (OAQPS-78-1,
IV-D-631 and IV-D-626). The only new
modeling issue raised during phase 3
was the application and cost of dry SOZ
scrubbing. These problems
notwithstanding each of the issues
raised by the various petitions were
evaluated carefully and are discussed
below.
Dry Scrubbing Technology
The Sierra Club and UARG both
raised issues concerning dry SO2
scrubbing technology in their petitions
for reconsideration. While UARG
concurred with EPA's basic approach
with respect to dry scrubbing, they
maintained that the Agency's objective
of developing the full potential of this
technology would be better served by a
50 percent minimum reduction
requirement. On the other hand, the
Sierra Club was most critical of EPA's
consideration of dry scrubbing in the
rulemaking. They maintained that the
public was not afforded sufficient
opportunity to comment on dry
scrubbing technology. They argued that
EPA had not identified dry scrubbing as
a demonstrated technology nor had the
Agency set forth any regulatory options
that embraced the technology. They also
asserted that the treatment of dry
scrubbing in the rulemaking was
inconsistent with Agency actions
concerning other emerging technologies
such as the establishment of commercial
demonstration permits for solvent
refined coal and fluidized bed
combustion, and the rejection of
catalytic ammonia injection for NO,
control on the grounds that it had not
been employed on a full-scale facility.
They also maintained that EPA had
shown little interest in dry scrubbing
prior to the spring of 1979 and seized
upon it only after the need arose to
justify a 70 percent minimum reduction
requirement. Finally, the Sierra Club
asserted that even if one assumed dry
scrubbing is adequately demonstrated.
the 70 percent reduction requirement is
too low. In doing so, they cited
information (Sierra Club petition, page
8) in the record that indicated that "up
to 90 percent reduction" can be
achieved with such systems.
A review of the public record belies
these charges. The preamble to the
proposed standards identified dry SO»
scrubbing, including spray drying, as an
alternative to wet FGD system; (43 FR
42160, left column). Subsequently, a
number of individuals and organizations
either submitted written comment or
presented testimony at the public
hearing in support of a variable control
standard since it would not foreclose the
development of dry SOj control
technology. For example, the spokesman
for the Public Service Company of
Colorado (PSCC) testified that his firm
was actively pursuing dry SO2 control
technology (dry injection of sodium-
based reagents upstream of a baghouse)
because it offered a number of
advantages compared to wet
technology. Advantages included lower
energy consumption, fewer maintenance
problems, and simplified waste disposal
(public hearing transcript, December 13,
1978, pages 92-94). When questioned by
the hearing panel, PSCC testified that 70
percent removal is achievable with dry
scrubbing and that they would pursue
the technology if a 70 percent
requirement was adopted (public
hearing transcript, December 13,1978,
page 102). Similarly, Northern States
Power testified that adoption of a sliding
scale would give impetus to their
examination of dry SO2 control systems
which employ a spray absorber and a
fabric filter (public hearing transcript,
December 13,1978, page 226). Finally,
the Department of Public Utilities, City
of Colorado Springs testified that they
have a program to conduct on-site pilot
tests of a spray-drying system for SO2
control. It was also noted that if a
sliding scale approach was adopted "we
feel there is no question but that dry
techniques would be used" (public
hearing transcript, December 13, 1978,
pages 266-267).
The Air Pollution Control
Commission, Colorado Department of
Health urged in their written comments
that the proposed emission floor be
raised to 172 ng/J (0.40 Ib/million Btu)
heat input in order to permit the
development and application of dry
control techniques such as the injection
of dry absorbants into a baghouse. They
noted that their recommendation would
require approximately 65 percent
reduction on a typical western low-
sulfur coal (OAQPS-78-1, IV-D-212).
The Washington Public Power Supply
System also submitted written
comments that affirmed the Agency's
finding on dry scrubbers as set forth in
the proposal. They indicated that dry
scrubbing was superior to wet
technology when applied to western
low-sulfur coal. They noted that the
application of dry scrubbers would
result in lower capital, fuel, and
operation and maintenance costs, as
well as .lower water use and simplified
waste disposal. They indicated further
that the uncertainty of being able to
achieve the proposed 85 percent
reduction requirement would foreclose
the installation of dry scrubbing
technology. Therefore, they
recommended that the proposed
emission floor be raised to at least 210
ng/J (0.5 Ib/million Btu) heat input
(OAQPS-78-1, IV-D-330).
Because of these comments and the
public hearing testimony, the Agency
carried out additional investigations of
dry scrubbing technology during the
post-comment period. The findings of
the analysis (44 FR 33582 and EPA 450/
3-79-021, page 3-61) confirmed the
views of the commenters that the
adoption of a uniform percentage
reduction requirement would have
constrained the development of dry
scrubbing technology. After carefully
reviewing the available pilot plant data
and information on the three full-scale
units that are under construction, it was
the Administrator's judgment that the
technology employing spray dryers
could achieve 70 percent reduction in
potential SO2 emissions on both low-
sulfur alkaline and nonalkaline coals.
Data on higher emission reduction levels
such as those noted by the Sierra Club
were discounted since they reflected
short-term removal efficiencies (not
representative of longer periods of
performance) and they were achieved
when high-alkaline content coals were
fired. The Administrator's judgment was
also tempered in this regard by the
public comments which indicated that
removal requirements higher than 70
percent would discourage the continued
development of the technology.
Similarly, these same commenters
clearly indicated that the technology
was capable of exceeding the 50 percent
reduction requirement suggested by the
Utility Air Regulatory Group.
The Sierra Club commented that EPA
was inconsistent in its treatment of dry
scrubbing and catalytic ammonia
injection. In rejecting catalytic ammonia
injection for NO, control, the
Administrator noted that it had not been
adequately demonstrated. A review of
the record reveals that the primary
proponent of this technology, the State
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of California Air Resources Board, also
recognized that it was not sufficiently
advanced at this time to be considered.
Instead, they merely recommended that
the standard require plants to set aside
space so that catalytic ammonia
injection could be added at some future
date (OAQPS-78-1, JV-D-268). In
comparison, dry scrubbing has
undergone extensive testing at pilot
plants, and there are three full-scale
facilities under construction that will
begin operation in the 1981-82 period.
With respect to commercial
demonstration permits for solvent
refined coal and fluidized bed
combustion, the standard merely allows
initial, full-scale demonstration units
some flexibility. Subsequent commercial
facilities will be required to meet the
final standards. In adopting this
provision, the Administrator recognized
that initial full-scale demonstration units
often do not perform to design
specification, and therefore some
flexibility was required if these capital
intensive, front-end technologies were to
be pursued. On the other hand, the
Agency concluded that more
conventional devices such as dry
scrubbers could be scaled up to
commercial-sized facilities with
reasonable assurance that the initial
facilities would comply with the
applicable requirements. In view of this,
the inclusion of dry scrubbing under the
commercial demonstration permit
piovision was not appropriate.
Finally, in a letter dated September 17
1979, to the Administrator, the Sierra
Club submitted additional information
to buttress its argument that dry
scrubbing is not demonstrated
technology. This letter cited EPA's "FGD
quarterly Report" of Spring 1979. The
report indicates that the direct injection
of dry absorbents (such as nahcolite)
into the gas stream may be a
breakthrough, yet it calls for further pilot
plan! studies. The inference the Sierra
Club drew from the article was that the
EPA technical staff does not believe dry
scrubbing is sufficiently developed to be
considered in the rulemaking. The Sierra
Club failed to recognize that there are
several different dry scrubbing
approaches in different stages of
development. The "FGD Quarterly
Report" does not pertain to the
approach employing a spray dryer and
baghouse with lime absorbent which
serves as the basis for the
Administrator's finding [EPA-450/3-70-
021 at 3-61).
The Sierra Club also cited an article in
the Summer 1979 "FGD Quarterly
Report" on vendors' perspectives
toward dry scrubbing. In doing so, the
Sierra Club noted that the article
indicates that vendors expressed an
attitude of caution toward dry scrubbing
which led the Sierra Club to conclude
that the technology is not available. It
should be noted from the article that
only one of the vendors present was
actively engaged in dry scrubbing and
that firm was quite positive in their
remarks. Babcock and Wilcox, who had
conducted spray dryer pilot plant
studies and is pursuing contracts for
full-scale installations, commented thai
"while the dry scrubbing approach is
new, the technology is proven."
Economic Modeling
The Agency's regulatory analysis
concluded that the variable control
standard with a 70 percent minimum
control level would result in equal or
lower national sulfur dioxide emissions
than the uniform 90 percent standard
while having less impact on costs, waste
disposal, and oil consumption (44 FR
33607, middle column and 33608). The
Sierra Club petition charged that the
Agency used an unrealistic model and
faulty assumptions in reaching these
conclusions. The petition alleged that
utility behavior as predicted by the EPA
model is "incredible" and that this
incredible behavior leads to "the
outlandish notion that stricter emission
controls will lead to more emissions."
The Administrator finds this allegation
to be without merit.
The principle modeling concept being
challenged is whether or not increased
costs of constructing and operating a
new plant (due to increased pollution
control costs) will affect the utility
operator's decisions on boiler retirement
schedules, the dispatching of plants to
meet electrical demand, and the rate of
construction of new plants. The model
used for the analysis assumed that
utility companies over the long term will
make decisions that minimize the cost of
electricity generation. That is, (1) under
any demand situation utilities will first
operate their equipment with the lowest
operating costs, and (2) existing
generating capacity will be replaced
only if its operating costs exceed the
capital and operating costs of new
equipment. While political, financial, or
institutional constraints may bar cost-
minimizing behavior in individual cases,
the Administrator continues to believe
that the assumption of such behavior is
the most sound method of analyzing the
impacts of alternative standards.
Under this approach, the model
simultaneously adjusts both the •
utilization of existing plants and the
construction schedule of new plants
(subject to Subpart Da) based on the
relative economics of generating
electricity under alternative standards.
Hence, average capacity factors for the
population of new plants may vary
among standards due to variations in
the mix of base and intermediate loaded
plants which are brought on line in any
one year. But this does not mean, as
concluded in the Sierra Club petition at
page 8, that the model predicted that
utilities would permit new base-loaded
units to remain idle while they continue
to build still more new units.
The petition also alleged that this
modeling concept was introduced in the
phase 3 analysis, which was completed
after the close of the public comment
period, and hence the modeling
rationale was not subject to public
review. The petition went on to criticize
some of the assumptions in the mode)
charging that they were not even
mentioned in the record.
The Administrator finds no basis for
the Sierra Club's assertion that the
modeling methodology and input
assumptions were not exposed for
public review. First, the same model
was used for the phase 1, 2, and 3
analyses. The basic model logic was
explained in the preamble to the
September proposal and comments were
solicited-specifically on the use of a cost
optimization model for simulating utility
decisions (43 FR 42162, left column).
Secondly, the model's input
assumptions were subjected to broad
review. Assumptions were presented in
the September preamble and in even
greater detail in the consultant's reports
which are part of the record (OAQPS-
78-1, II-A-42, II-A-90, and II-A-91)
Following proposal, the Agency
convened an interagency working group
to review the macroeconomic model and
the Agency's input assumptions (44 FR
33604, left column). Members of the
group represented a spectrum of
expertise and interests (energy,
employment, environment, inflation,
commerce). The group me! numerous
times over a period of two months,
including meetings with UARG, NRDC,
and Sierra Club. As a result of the
group's recommendations, the phase 2
analysis was conducted. A full
description of the analysis including
changes to the modeling assumptions
was presented at the public hearing and
a detailed report was put into the record
(OAQPS-78-1, IV-A-5). For the phase 3
analysis accompanying promulgation,
the only change in modeling
assumptions from phase 2 was the
introduction of dry scrubbing
technology. Based on the detailed record
established, the Administrator
concludes that the Sierra Club had
ample opportunity to analyze and
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comment on the Agency's analytical
approach and did so by incorporating
the EOF and NRDC comments into their
January 1979 comments (OAQPS-78-1,
IV-D-626).
The Sierra Club also criticized the
conclusions of the Agency's regulatory
analysis because the assumed oil prices
were too low and the nuclear plant
growth rate was too high. To assist in
evaluating the petitions, two sensitivity
tests were performed on the Agency's
regulatory analysis. Using the phase 3
assumptions as a base, the analysis was
rerun first assuming higher oil prices
and then assuming both higher oil prices
and a lower nuclear growth rate
{OAQPS-7&-1, VI-B-16). The studies
addressed the promulgated standard,
the full control option (uniform 90
percent control), and a variable control
standard with a 50 percent minimum
control requirement as recommended by
UARG. The predictions for 1995 are
summarized in Tables 2 and 3,
respectively. For comparison, the phase
3 results are repeated in Table 1.
With respect to energy input
assumptions, the oil prices used by the
Agency for the phase 3 analysis were
based on the Department of Energy's
estimate of future crude oil prices. These
estimates are now probably low
because of the 1979 OPEC price increase
which occurred after promulgation of
the standard. For the sensitivity
analysis, the following oil prices in 1979
dollars were assumed:
Assumed Oil Prices
[Dollars per Barrel)
1985 ,
1990
1995
Sensitivity Pt"
analysis
25
30
38
iase 3
16
20
26
These prices were obtained from
conversations with DOE's policy
analysis staff. The prices may appear
low in comparison to the example of
$41.00 per barrel spot market oil given in
the Sierra Club petition, but the Sierra
Club figure is misleading because
utilities seldom purchase spot market
oil. The meaningful parameter is the
average refiners' acquisition cost, which
was $21/barrel at the time of this
analysis. The original nuclear capacity
assumptions were based on the
industry's announced plans for new
capacity. For sensitivity testing, these
estimates were modified by excluding
nuclear power plants in the early
planning stages while retaining those
now under construction or for which,
based on permit status, plans appear
firm. The following assumptions of total
nuclear capacity resulted:
Table 1.—Summary of 1995 Impacts With Phase 3 Assumptions'
Level of control with 520 ng/J maximum emission limit
Current
standards
Vanable con-
trol. 50 pet
minimum
Variable con-
trol. 70 pel
minimum
Full
control
National SOi Emissions (million tons) .. . .. ..
East '
M.dwest . .
West South Central . ...
West
Incremental Annualized Cost (billions 1978 $)
Incremental Cosl of SO, Reduction (1978 $/ton)
Oil Consumption (million bbl/day) . ...
Coal Production (million tons)
Total Coal Capacity (GW)....
23 B
112
63
26
1 7
1 4
1,767
554
206
97
80
1 8
1 1
29
914
1 6
1,745
537
1 With wet and dry scrubbing and the following energy assumptions
Year
1985
1990
1995
Oil prices Nuclear
($ 1975) Capacity
(GW)
$12.90 97
16 40 165
21 00 228
205
97
80
1 7
1 1
33
1.036
1 6
1,752
537
207
101
79
1 7
09
44
1,428
1 8
1,761
520
7 See 44 FR 33608 for designation of census regions
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Table 2.—Summary of 1995 Impacts With Higher Oil Pnces'
Level ol control with 520 ng/J maximum emission limit
Current Variable con- Vanable con- Full
standards trol, 50 pel Irol, 70 pet control
minimum minimum
East = ... ....
West South Central . ..
West
Total Coat Capacity (GW)
232
109
82
26
16
09
1,800
588
198
91
79
1 7
1 1
33
967
0.9
1,797
587
196
91
78
16
1.0
36
977
09
1.802
587
197
95
78
15
09
50
1,049
09
1.832
587
1 With wet and dry scrubbing and the following energy assumptions
Year
1985...
1990 .
1995...
Oil prices Nuclear
($ 1975) capacity
(GW)
$20.20 97
24 20 165
30 70 228
'See 44 FR 33608 lor designation ol census regions
Table 3.—Summary of 1995 Impacts With Higher Oil Pnces and Less Nuclear Growth'
Level ol control with 520 ng/J maximum emission limit
Current •
standards
Vanable con-
trol, 50 pet
minimum
Variable con-
trol. 70 pet
minimum
Full
control
National SO, Emissions (million tons)
East'
Midwest
West South Central
West
Incremental Annualized Cost (billions 1978 $)
Incremental Cost of SO, Reduction (1978 $/ton)
Oil Consumption (million bbl/day)
Coal Production (million tons)
Total Coal Capacity (GW)
250
120
86
86
1.7
09
1,940
644
209
98
8.2
18
12
3.6
883
09
1,943
644
206
97
61
1 7
1 1
41
914
09
1.946
644
205
101
80
16
09
59
1,259
09
1,984
643
1 With wet and dry scrubbing and the following energy assumptions
Year.
1985...
1990...
1995...
Oil prices Nuclear
($ 1975) Capacity
(GW)
$20 20 92
24 20 141
3070 173
•See 44 FR 33608 for designation ol census regions
Assumed Nuclear Capacity
1985
1990
1995
Sensitivity
analysis
92 GW
141 GW
173 GW
Phase 3
97 GW
165GW
228 GW
Environmentally, the impact of higher
oil prices was to reduce SO2 emissions
(Table 2). For example, under the
promulgated standard (hereafter
referred to as "the standard") national
SO2 emissions in 1995 were projected to
drop from 20.5 million tons predicted in
phase 3 (44 FR 33608) to 19.6 million
tons. This reduction occurred because
the higher oil prices led to the retirement
of about 50 gigawatts (GW) of existing
oil-fired capacity. While these
retirements increased the demand for
new coal-fired plants, new plants
(subject to Subpart Da) on average were
less polluting than the oil-fired capacity
they replaced. Therefore, the net effect
of oil replacement on a broad regional
basis was to reduce SO2 emissions.
The relative impacts of the alternative
standards under the sensitivity tests
remained about the same. Sulfur dioxide
emissions under the standard were still
predicted to be lower than with either
full control or the 50 percent variable
standard. The emissions benefit relative
to full control was reduced from 200,000
tons per year to 100,000 tons per year.
Regionally, the effect of the higher oil
prices on the relative impacts of the
standards was mixed. In comparison to
full control, the standard continued to
reduce emissions in the East by 400,000
tons per year, but resulted in an
additional 70,000 tons in the West and
100,000 tons in the West South Central
(relative to phase 3). However, as
pointed out above, emissions in all
regions were less than or equal to those
under the phase 3 oil price assumptions.
The cost of all the standards
increased under the higher oil price
assumption. This increase was due to
the cost of additional coal capacity and
corresponding emission control
equipment. Relative to the standard, the
cost of full control increased by $300
million per year over the $1.1 billion
difference predicted under lower oil
prices.
At the higher oil prices, 1995 oil
consumption by utilities was predicted
to be the same under all standards
tested. Depending on the standard,
consumption was 500,000 to 800,000
barrels per day lower than under the
phase 3 projections with lower prices.
The reason that the environmental
standards had no effect on oil
consumption was that at the assumed
rate of oil price increase, all base- and
intermediate-loaded oil capacity was
retired by 1995 and the only remaining
oil use was in combustion turbines used
to meet peak demand.
Under the assumption of both high oil
prices and slowed nuclear growth
(Table 3), national and regional SO2
emissions were predicted to be about
the same as under the phase 3
projections. This effect was due to the
counterbalancing emission impacts. As
noted above, higher oil prices resulted in
a net decrease in SO2 emissions. But at
the same time the reduced supply of
nuclear generation capacity precipitated
demand for an additional 55 GW of new
coal capacity beyond that required
under the projection with high oil prices.
On a national level the emissions from
these new coal-fired plants offset the
emission reductions achieved by the oil
replacements.
With this additional 55 GW of new
coal-fired capacity, the environmental
impact of alternative standards was
more significant. Baseline emission
projections (i.e., assuming no change to
the original standard) increased from
23.8 million tons per year under the
phase 3 energy assumptions to 25.0
million tons per year. Accordingly, the
promulgated standard reduced national
SO2 emissions in 1995 by almost 4.5
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million tons per year in contrast to
about 3.5 million tons per year under
both the phase 3 and the high oil price
sensitivity projections.
While emission levels were roughly
the same as under the phase 3 energy
assumptions, the relative impacts of the
alternative standards changed
somewhat. National emissions were
predicted to be 100,000 tons less under
full control than under the standard.
Relative to full control, the standard
was still predicted to reduce emissions
by about 400,000 tons in the East, but on
a national basis this was offset by
emission increases in the other regions.
With higher oil prices and less nuclear
capacity, the environmental benefit of
full control in the West and West South
Central was greater by about 100,000
tons, but this impact is masked in Table
3 due to rounding. The variable standard
with a 50 percent minimum control level
resulted in about 400,000 tons per year
more emissions than full control and
about 300,000 tons per year more than
the standard.
The total cost of all the alternatives
increased due to the increased coal
capacity. Relative to the standard, the
cost of the 50 percent variable control
standard remained about the same. The
full control standard, however, was
significantly more expensive. The
marginal cost of full control (relative to
the standard) increased from $1.1 billion
under the phase 3 energy assumptions to
$1.8 billion.
Energy impacts were about the same
as those predicted in the high oil price
sensitivity runs. Oil consumption was
still predicted at about 900 000 barrels
per day under all alternative standards.
Coal production under all alternatives
increased by about 100 million tons per
year.
Even considering the uncertainty of
futuie oil prices and nuclear capacity,
the Administrator found no basis for
convening a proceeding on the modeling
issue. The sensitivity runs did not show
significant changes in the relative
impacts of the alternatives. Under the
sensitivity test with both high oil prices
and slowed nuclear growth, full control
for the first time showed lower
emissions nationally than the standard.
But the cost of this additional 100,000
tons of control was estimated at $1.8
billion, which represents more than a 40
percent increase in the incremental cost
of the standad (Table 3). The principal
environmental benefit of full control
would be felt in the West and West
South Central. Through case-by-case
new source review ample authority
exists to require more stringent controls
as necessary to protect our pristine
areas and natioral parks (44 FR 33504,
left column). As a result, the
Administrator continues to believe that
the flexibility offered by the standard
will lead to the best balance of energy,
environmental, and economic impacts
than either a uniform 90 percent
standard or a 50 percent variable
standard and hence better satisfies the
purposes of the Act.
On the other side of the modeling
issue, UARG charged that the Agency's
regulatory analysis does not support a
70 percent minimum requirement. The
petition called the Agency's control cost
estimates unrealistic and presented a
macrceconomic analysis which
concluded that a 50 percent minimum
requirement would result in a more
favorable balance of cost, energy, and
environmental impacts.
Response to the UARG petition was
difficult because the UARG position was
presented in two separate reports
submitted at different times, and the two
reports reached different conclusions. In
the formal petition, UARG
recommended 50 percent minimum
control and promised a detailed report
by NERA supporting their position.
When the NERA report arrived six
weeks later, if recommended 30 percent
control. In light of this confusion, it was
decided to review each report
separately based on its own merits, but
devote primary attention to the 50
percent recommendation. After
reviewing UARG's macrceconomic
analysis, the Administrator finds no
convincing arguments for altering the
conclusion that the 70 percent minimum
removal requirement provides the best
balance of impacts. In the formal
petition, UARG's conclusion that a 50
percent standard is superior was based
on a NERA economic analysis which
assumed that only wet scrubbing
technology v, .is available to utilities. A
detailed analysis of the NERA results
was not possible because only summary
outputs were supplied in their
comments. But the results of this
analysis set,m to coincide with the
Agency's conclusions that there are
energy, environmental, and economic
benefits, associated with standards that
provide a lower cost control alternative
for lower sulfur coals. The problem with
the UARG initial analysis is that it
overlooked the economic benefits of dry
scrubbing.
In recognition of this shortcoming,
UARG presented their estimate of the
costs of dry scrubbing made by Battelle
Columbus Laboratories {UARG petition,
page 25) and then hypothesized without
supporting analysis that "with realistic
cost assumptions the advantages of a
lower percent remo\al are likely to
increase even further" (UARG petition,
page 27). Table 4 compares Battelle's
costs to those used in the EPA
regulatory analysis. The two estimates
are almost the same. More importantly,
the two estimates agree that the cost of
a 70 percent efficient dry system is not
significantly greater than the cost of a 50
percent efficient system, and this
conclusion had important implications
in the specification of the standard.
Based on these comparisons, the
Administrator finds that the UARG
petition supports the Agency's dry
scrubbing cost assumptions and the
finding that no significant cost benefit
will result from a standard with a 50
percent minimum control level.
Table 4.—Comparison of UARG and EPA dry SOt
Scrubbing Costs ' (Mills/kwhJ
Percent removal
50
70
Inlet sulfur (Ibs
SO./million
Btu)
080
200
060
200
UARG
'168
'213
197
254
EPA
206
244
266
266
' Wet scrubbing costs range up to 6 mills/kwh
1 UARG cos>ts based on 55 percent removal
In their second report, UARG
presented additional economic analyses
by NERA. In those analyes, the impacts
of 30, 50, and 70 percent minimum
control standards were tested assuming
that both wet and dry scrubbing
technology were available. The analyses
were performed with three different sets
of control cost assumptions—EPA's
costs. Battelle's costs, and an additional
set of costs specified by NERA. The
report concluded that the 70 percent
standard is superior using EPA's costs
but that under the other cost estimates
the 30 percent standard is better. The
cost effectiveness of alternative
standards (dollars per ton of pollutant
removed) was their principal basis of
evaluation. UARG then alleged that EPA
overestimated the differences in cost
between wet and dry scrubbing and that
this error led to the wrong conclusion
about the impacts of the 70 percent
minimum removal requirement. The EPA
cost assumptions were criticized
primarily because different methods
were used to estimate dry and wet
scrubbing costs. To justify their position,
UARG presented estimates of wet and
dry scrubbing costs developed by
Battelle. UARG believes that Battelle
understand scrubber costs, but that
Battelle's relationship between wet and
dry scrubbing costs is more accurate
than EPA's (UARG petition, page 7). As
noted above, Battelle agreed with the
Agency's dry scrubbing costs, but for
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wet scrubbing the Battelle costs were
substantially lower than the Agency's.
Typically, when comparing results of
studies, the Agency has detailed
documentation with which to compare
the methods of costing and analysis. In
this case, the Administrator had
documentation for neither the NERA
costs nor the Battelle costs. The NERA
costs were unreferenced and supported
by neither engineering analysis nor
vendor bids. They assumed that the
capital cost of a dry scrubber is 10
percent less than that for a comparable
wet scrubber and that the operating
costs and energy requirements are the
same for the two systems. The UARG
petition promised a detailed report from
Battelle, but the report was not
delivered. Without a basis for
evaluation, the Battelle and NERA costs
can only be considered as hypothetical
data sets for the purpose of sensitivity
testing of the economic analysis. They
cannot be considered as new
information on SO2 control costs.
The EPA cost estimates, on the other
hand, have withstood several critical
tests. The PEDCo cost model for wet
scrubbers which was used by EPA was
thoroughly reviewed by Department of
Energy (DOE) consultants, and DOE
concurred with the EPA estimates
through the interagency working group.
Later, the Agency's costs were again
reviewed in detail against wet scrubber
costs predicted by the Tennessee Valley
Authority's scrubber design model.
While the two models initially seemed
to produce divergent results, careful
analysis of the respective costing
methodology showed that for similar
design specifications the two models
produced costs that were very close, the
major difference stemming from
different assumptions about the
construction contingency fee (OAQPS-
78-1, IV-B-50). The Administrator
concluded from these cost comparisons
that the Agency's flue gas
desulfurization cost assumptions are
reasonable.
The EPA dry scrubbing costs were
based primarily on engineering studies
submitted by electric utility companies
and equipment vendors for the full-scale
utility systems now on order or under
construction. Using these studies, the
EPA cost estimates were made in full
cognizance of the basic assumptions
used in the PEDCo wet scrubbing model.
The result was that for economic
modeling purposes (OAQPS-78-1, IV-
A-25, page B-17) the dry scrubbing cost
estimates in the background document
(EPA 450/5-79-021, page 3-67) were
increased to reflect similar fuel
parameters, local conditions, and degree
of design conservatism as reflected in
the wet scrubbing costs. Since care was
taken in aligning these costs, the
Administrator does not accept UARG's
allegation that EPA's costs for wet and
dry scrubbing are invalid because they
were developed on an inconsistent
basis.
Even if EPA accepted UARG's
unsubstantiated cost assumptions, the
NERA sensitivity analyses provided no
new insights nor did they materially
contradict the Agency's basic *
conclusions about the standard. Using
the Battelle costs and NERA's
"alternative scrubber costs" as a range,
NERA predicted that relative to 50
percent minimum control, a 70 percent
standard would reduce national SO»
emissions by an additional 250 to 450
thousand tons per year compared to
about 100 thousand tons estimated by
EPA (Table 1). NERA predicted the
additional costs of a 70 percent
minimum standard relative to a 50
percent requirement would be between
$300 million and $400 million per year
compared to $300 million predicted by
EPA. It was only in moving to 30 percent
control that the NERA results showed a
distinct cost savings ($600 to $900
million) over the 70 percent level, but
the 30 percent standard produced an
additional 700 thousand tons per year of
SO2 under both of their control cost
scenarios. The Administrator rejects the
30 percent standard advocated by
UARG because the potential cost
savings do not justify the potential
emission increases. In conclusion, the
trade-offs between costs and emissions
shown by UARG are generally similar to
those predicted by EPA in promulgating
the standard and therefore do not
support a different standard from the 70
percent variable standard adopted.
Other Issues
Kansas City Power and Light
Company sought either an elimination of
the percent reduction requirement when
emissions are 520 ng/J (1.2 Ibs/million
Btu) heat input or less or as an
alternative a reduction in the 70 percent
minimum control requirement. In their
arguments, KCPL cited annualized
control costs for wet scrubbing of $11.4
million and an energy penalty of 70
thousand tons of coal per year to
operate a scrubber. Second, they noted
that 14 percent of the potential SO2
emissions from the coal they plan to
burn will be removed by the fly ash.
Taking these two factors in account,
KCPL computed a cost effectiveness
ratio for a hypothetical 650 MW unit to
be $3,600 per ton of sulfur removed and
concluded that such control was too
expensive. Finally, they concluded that
scrubbing low-sulfur coals is not
warranted since uncontrolled SO2
emissions from their new plants will be
less than the emissions allowed by the
standard for high-sulfur coals with 90
percent scrubbing.
After careful review, the
Administrator finds that the KCPL
petition provided no legal or technical
basis for reconsidering the final rule.
First, the question of whether a plant
burning low-sulfur coal should be
required to meet the same percentage
reduction requirement as those burning
high-sulfur coal has been a central issue
throughout this decision-making. Since
this issue was raised in the proposal (43
FR 42155, left column), KCPL had ample
opportunity to make their points during
the public comment period. In fact, it
was the recognition of this trade-off in
emissions between high-sulfur and low-
sulfur coal that led the Administrator to
first consider the concept of variable
control standards (43 FR 42155, right
column). While sulfur removal by fly ash
does not represent best demonstrated
technology for SO2 control, sulfur
removal by fuel pretreatment, fly ash,
and bottom ash may be credited toward
meeting the 70 percent requirement.
Second, the KCPL petition does not
allege the requisite procedural error that
the standard was based on information
on which they had no opportunity to
comment. Their objections center
primarily on the economic and energy
impacts of wet SO2 scrubbing on low-
sulfur coal. These issues were clearly
identified by the Agency in the
background document supporting
proposal (OAQPS-78-1, III-B-3,
Chapters 5 and 7). Furthermore, the
preamble to proposal specifically
requested comments on the Agency's
assumptions for the regulatory analysis
(43 FR 42162, left column).
Finally, and more importantly, the
major points made by KCPL are not of
central relevance to the outcome of the
rule because the information presented
does not refute the Agency's data base
on wet scrubbing. Consider the
following comparisons to the
assumptions of the EPA regulatory
analysis.
(a) The control costs quoted by KCPL
for a 650 MW unit were $31 million in
capital and $6.2 million in operating
expenses. The EPA assumptions applied
to a comparably sized unit result in $55
million in capital costs and $7 million in
operating expense.
(b) KCPL quoted an energy impact of 8
tons of coal per hour to operate the
scrubber. Considering their operating
requirement of 460 tons of coal per hour,
the energy penalty of SO2 control is 1.7
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percent. The Agency's economic model
assumed 2.2 percent.
(c) KCPL computed cost effectiveness
of the standard at $3600 per ton of sulfur
removed. This figure is based on a
misunderstanding of the application of
the fly ash removal credit toward the 70
percent removal requirement. According
to the standard, the scrubbing
requirement when assuming a 14 percent
SO2 removal in flyash is 55 percent
rather than 56 percent as cakiJaH'd by
KCPL. At C5 peir,ent scrubbing. Ihs cost
per ton of sulfur removed is $3100. This
converts to a cost of $1550 per ton of
sulfur dioxide removed which is similar
to the cos's estimated by EPA for low-
sulfur coal applications (OAQPS-78-1,
II1-R--3 and 1V-B-14).
Thus, the Administrator has already
concluclud that energy and economic
cos's greatei than those cited by KCPL
ar? justified to achieve the emission
reductions required by the standard.
Conclusions on Minimum Control Level
After carefully weighing the
a/puments by the three petitioners, the
Administrator can find no new
infoimation or insights which are of
central relevance to his conclusions
about the benefits of a variable control
standard with a 70 percent minimum
removal requirement. The Sierra Club
and UARG correctly point out that the
Agency's phase 3 analysis was
completed after the close of the public
comment period and that they were
therefore unable to comment on the final
step of the regulatory analysis. But in
assessing these comments it is important
to put the phase 3 analysis in proper
context with its role in the final
decision. The Administrator's
conclusions about the responses of the
utility industry to alternative standards
were no! based on phase 3 alone, but a
seiies of economic studies spanning
more than a year's effort. These
analyses were performed under a range
of assumptions of economic conditions,
regulatory options, and flue gas
desulfurization parameters. The phase 3
analysis was merely a fine tuning of the
regulatory analysis to reflect dry
scrubbing technology.
No new modeling concepts or
assumptions were introduced in phase 3.
The fundamental modeling concept as
introduced in the September proposal
(43 FR 42161, right column) has not
changed. The model input assumptions
were the same as those of the phase 2
analysis presented on December 8, 1978
(44 FR 54834, middle column), and at the
December 12 and 13,1978, public
hearing. Detailed consultants' reports on
the modeling analyses were available
for comment before the close of the
public comment period. This public
record provided adequate opportunity
for the public to comment both on the
principal concepts and detailed
implementation of the regulatory
analysis before the close of the public
comment period.
Even though new information was
added to the record after the close of the
comment period, none of the petitions
raised valid objections to this
information or cast any uncertainty that
is gnrmane to the final decision. The
Administrator has very carefully
weighed the petitioners comments on
dry scrubbing and the UARG sensitivity
analysis on pollution control costs. Not
only did the UARG analysis generally
confirm the conclusions of the EPA
regulatory analyses, but it established
that even if dry scrubbing costs vary
substantially, the relative impacts of a
50 versus 70 percent minimum removal
requirement change very little. The 70
percent standard was estimated to
produce lower emissions for only
slightly higher costs. Differences in cost
efiectiveness, which UARG seem to
weigh most heavily, varied by only $2 to
a maximum of $50 per ton of SOS
removed across alternative cost
estimates. In the final analysis none of
the petitions repudiated the Agency's
findings on the state of development,
range of applicability, or costs of dry
SOa scrubbing. In light of these findings,
the Administrator finds the information
in the petitions not of central relevance
to the final rule and therefore denies the
requests to convene a proceeding to
reconsider the 70 percent minimum
removal requirement.
///. SO, Maximum Control Level (90
percertt reduction of potential SO,
emissions)
Petitions for reconsideration
submitted by the Utility Air Regulatory
Group (UARG) and the Sierra Club
questioned the basis for the maximum
control level of 90 percent reduction in
potential SOj emissions, 30-day rolling
average. The other petitions did not
address this issue. However, in a July 18,
1979, letter, the Environmental Defense
Fund (EOF) requested EPA to review
utilization of adipic acid scrubbing
additives as a basis for a more stringent-
maximum control level. An additional
analysis by UARG was Forwarded to
EPA on January 28,1980. Although it
was reviewed by EPA, a detailed
response could not be prepared in the
three days afforded EPA for comment
prior to the court's doadline of January
31, I960, for EPA to respond to the
petitions. However, the only issue not
previously raised by I'ARG (boiler load
variation) has been addressed by this
response.
With their petition, UARG submitted a
statistical analysis of flue gas
desulfurization (FGD) system test data
which purportedly revealed certain
flaws in the Agency's conclusions. The
UARG petition maintained that a
scrubber with a geometric mean
(median) efficiency of 92 percent could
not achieve the standard because of
variations in its performance. UARG
also maintained that the highest removal
efficiency standard that can be justified
by the Agency's data is 85 percent, 30-
day rolling average. In the alternative,
they suggested that the 90 percent, 30-
day rolling average standard could be
retained if an adequate number of
exemptions were permitted during any
given 30-day averaging period. On the
other hand, the Sierra Club questioned
why the standard had been established
at 90 percent when the Agency had
documented that well-designed,
operated, and maintained scrubbers
could achieve a median efficiency of 92
percent. In doing so, they argued that a
90 percent, 30-day rolling average
standard was not sufficiently stringent.
After reviewing their petitions, the
Administrator finds that the Sierra Club
and UARG overlooked several
significant factors which were of critical
importance to the decision to
promulgate a 90 percent, 30-day rolling
average standard. The Sierra Club
position was based on a
misunderstanding of the statistical basis
for the standard. The UARG analysis
was flawed because it did not consider
the sulfur removed by coal washing,
coal pulverizers, bottom ash, and fly ash
(hereafter, collectively referred to as
sulfur reduction credits). Instead the
UARG petition based its conclusions on
the performance of the FGD system
alone. In short, UARG did not analyze
the promulgated standard (44 FR 33582,
center column). Furthermore, UARG
underestimated the minimum
performance capability of scrubbers by
assuming that future scrubbers would
not even achieve the level of process
control demonstrated by the best
existing systems tested by EPA.
EPA has prepared two reports which
re-analyze the same FGD test data
considered in UARG's analysis. One
report identified the important design
and operating differences in the FGD
systems tested (OAQPS-78-1, Vl-B-14)
by EPA and the second report provided
additional statistical analyses of these
data (OAQPS-78-1, VI-B-13). The
results of the EPA analyses showed that:
1. Flue gas desulfurization systems
can achieve a 30-day rolling average
efficiency between 88 percent and 89
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percent (base loaded boilers) or
between 86 and 87 percent (peak loaded
boilers) with no improvements in
currently demonstrated process control.
2. Even if a new FGD system attained
only 85 percent efficiency (30-day rolling
average), a 90 percent reduction in
potential SOj emissions can be met
when sulfur reduction credits are
considered.
To clarify the basis for the Agency's
conclusions, the following discussion
reviews the development of information
used to establish the final percent
reduction standard. Initially, EPA
studied the application of FCD systems
for the control of SOj emissions from
power plants. As part of that effort,
information which described the status
and performance of FGD systems in the
U.S. and Japan was inventoried and
evaluated. These evaluations included
the development of design information
on how to improve the median
efficiency of FGD systems based upon
an extensive testing program at the
Shawnee facility (OAQPS-78-1, II-A-
75). The Shawnee test data and other
data (OAQPS-78-1, II-A-71) on existing
FGD systems were generated by short-
term performance tests. These data did
not define the expected performance
range (the minimum and maximum SO?
percent removal) of state-of-the-art FGD
systems.
Because a continuous compliance
standard was under consideration,
information about the process variation
of FGD systems was needed to project
the performance range of scrubber
efficiency around the median percent
removal level. For the purpose of
measuring process variation, several
existing FGD systems were monitored
with continuous measurement
instrumentation. The selection of FGD
systems to be tested was limited
principally to the few FGD systems
available which were attaining 80 to 90
percent median reduction of high-sulfur
coal emissions. When examining the
results of these tests, it should be
recognized that they do not reflect the
performance of a new FGD system
specifically designed to attain a
continuous compliance standard.
When the percent reduction standard
was proposed, EPA projected the
performance of newly designed FGD
systems. The projection, referred to as
the "line of improved performance" in
the analysis, was principally based on
the information on how to improve
median system performance (OAQPS-
78-1, III-B-4). The line showed that
compliance with the proposed standard
(85 percent reduction in potential SO2
emissions, 24-hour average) could be
attained with an FGD system if the only
improvement made relative to an
existing FGD system was to increase the
median efficiency to 92 percent. The
"line of improved performance" did not
reflect the sulfur reduction credits that
could be applied towards compliance
with the proposed standard or the
improvements in process control (less
than 0.289 geometric standard deviation)
that could be designed into a new
facility. While these alternatives were
discussed in detail and included within
the basis for the proposed standard
(OAQPS-78-1, III-B-4), the purpose of
the "line of improved performance" was
to show that even without credits or
process control improvements, the
proposed standard could be met. Upon
proposal, the source owner was
provided a choice of complying with the
percent reduction standard by (1) an
FGD system alone (85 percent reduction,
24-hour standard), or by (2) use of sulfur
reduction credits together with an FGD
system attaining less than 85 percent
reduction.
After proposal, EPA continued to
analyze regulatory options for
establishing the final percent removal
requirement. On December 8,1978,
economic analyses of these additional
options were published in the Federal
Register (43 FR 57834) for public
comment. In this notice EPA stated that:
Reassessment of the assumptions made in
the August analysis also revealed that the
impact of the coal washing credit had not
been considered in the modeling analysis.
Other credits allowed by the September
proposal, such as sulfur removed by the
pulverizers or in bottom ash and flyash, were
determined not to be significant when viewed
at the national and regional levels. The coal
washing credit on the other hand, was found
to have a significant effect on predicated
emissions levels and, therefore, was taken
into consideration in the results presented
here.
This statement gave notice that the
effect of the coal washing credit on
emission levels for the proposed control
options had not been properly assessed
in previous modeling anayses. In the
economic analyses completed before
proposal, the environmental benefits of
the proposed standard were optimistic
because it was assumed that all high-
sulfur coal would be washed, but a
corresponding reduction in the level of
scrubbing needed for compliance was
not taken into account. This error
resulted in the analyses understimating
the amount of national and regional SO2
emissions that would have been allowed
by the proposed standard. This problem
was discussed at length at the public
hearing on December 12,1978 (OAQPS-
78-1, IV-F-1, p. 11, 22, 28, and 29).
UARG addressed this question of coal
washing in comments submitted in
response to recommendations presented
at the public hearing by the Natural
Resources Defense Council (OAQPS-78-
1. IV-F-1, p. 65,12-12-78) that the final
standards be based upon the removal of
sulfur from fuel together with the
removal of SO» from flue gases with a
FGD system. In their comments
(OAQPS-78-1, IV-D-725, Appendix A,
p. 23), UARG had three main objections:
(1) All coals are not washable to the
same degree.
(2) Coal cleaning may not be
economically feasible.
(3) The Clean Air Act and the
Resource Conservation and Recovery
Act may preclude the construction of
coal washing facilities at every mine.
EPA has reviewed these comments
again and does not find that they change
the Administrator's conclusion that
washed coal can be used in conjunction
with FGD systems to attain a 90 percent
reduction in potential SO» emissions.
First, EPA realizes that all coal is not
equally washable. In the regulatory
analaysis, the degree of coal washing
was a function of the rank and sulfur
content of the coal. Moreover, because
of the variable control scale inherent in
the standard, 75 percent of U.S coal
reserves would require less than 90
percent reduction in potential SO»
emissions. The remaining 25 percent are
high sulfur coals on which the highest
degree of sulfur removal by coal
washing are acheived. Second, the
washing assumptions used by the
Agency reflected the percentage of
sulfur removal currently being attained
by conventional coal washing plants in
the U.S. (OAQPS-78-1, IV-D-756).
These washing percentages were
therefore cost-feasible assumptions
because they are typical of current
washing practices. Finally, the Agency
does not believe that environmental
regulations will prohibit the cleaning of
coal. The Clean Air Act and the
Resource Conservation and Recovery
Act may impose certain environmental
controls, but would not prevent the
routine construction of coal washing
plants. Thus, the Agency concluded that
the basis for the promulgated standard
could be a combination of FGD control
and fuel credits.
Based on these findings, EPA stated
(44 FR 33582) that the 90 percent
reduction standard "can be achieved at
the individual plant level even under the
most demanding conditions through the
application of flue gas desulfurization
(FGD) systems together with sulfur
reductions achieved by currently
practiced coal preparation techniques.
Reductions achieved in the fly ash and
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bottom ash are also applicable". Thus,
FGD systems together with removal of
sulfur from the fuel was'the basis for the
final standard. The standard prohibits
the emission of more than "10 percent of
the potential combustion concentration
[90 percent reduction)." That is, the final
standard requires 90 percent reduction
of the potential emissions (the
theoretical emissions that would result
from combustion of fuel in an uncleaned
state), not 90 percent removal by a
scrubber.
Since UARG failed to take into
consideration sulfur reduction credits,
UARG analyzed a more stringent
standard than was promulgated.
Furthermore, EPA's review revealed that
while the statistical methodology in the
UARG analysis was basically correct, it
was flawed by UARG's assumption
about the process variation of a new
FGD system. As a result, the statistical
anaysis was improperly used by UARG
to project the number of violations
expected by a new FGD system.
To elaborate on the variability issue,
page 14 of the UARG petition states:
The range of efficiency variability values
resulting from this analysis represents the
range of efficiency variabilities that can be
expected to be encountered at future FGD
sites
This assumption artificially inflated
the amount of variability that would
reasonably be expected in a new FGD
system because it presumed that there
were no major design and operational
differences in the existing FGD systems
tested and that the performance of new
systems would not improve beyond that
of systems tested by EPA. To estimate
process variability of new FGD systems,
UARG simply averaged together all data
from all systems tested including
malfunctioning systems (Conesville).
EPA's review of these data showed that
there were major design and operating
differences in the existing FGD systems
tested and that the process control could
be improved in new FGD systems
(OAQPS-78-1, VI-B-14). Therefore, not
all of the FGD systems tested by EPA
were representative of best
demonstrated technology for SO2
control.
These major differences in the FGD
systems tested are apparent when the
test reports are examined (OAQPS-78-1,
VI-B-14).One of the tests was
conducted when the FGD systems were
not operating properly (Conesville). Two
tests were conducted on regenerative
FGD systems (Philadelphia and
Chicago) which are not representative of
a lime or limestone FGD system.
Another test was on an adipic acid/lime
FGD system (Shawnee-venturi). None of
these tests were representative of the
process variation of well-operated, lime
or limestone FGD systems on a high-
sulfur coal application (OAQPS-78-1,
VI-B-14).
Only three systems were tested when
(1) the unit was operating normally, and
(2) pH control instrumentation was in
place and operational (Pittsburgh,
Shawnee-TCA, and Louisville). Only at
Shawnee did EPA purposely have
skilled engineering and technician
personnel closely monitor the operation
during the test (OAQPS-78-1, VI-B-14).
Data from these systems best describe
the process control performance of
existing lime/limestone FGD systems.
During the Pittsburgh test, there were
some problems with pH meters. The
data was separated into Test I (pH
meter inoperative) and Test II (pH meter
operative). During Test I, operators
measured pH hourly with a portable
instrument (OAQPS-78-1, VI-B-14).
Analysis of these data show low
process variation during each test period
(OAQPS-78-1, VI-B-13). Although the
process variation during the second test
was 10 percent lower, the difference
was not found to be statistically
significant. Data taken during each test
(I and II) are representative of control
attainable with pH controls only. Boiler
load was relatively stable during the
test. Average process variation as
described by the geometric standard
deviation was 0.21 and 0.23,
respectively.
At Shawnee, only pH controls were in
use, but additional attention was given
to controlling the process by technical
personnel. Boiler load was purposely
varied. Geometric standard deviation
was 0.18, which was similar to that
recorded at Pittsburgh. UARG
acknowledged that careful attention to
control of the FGD operation by skilled
personnel was an important factor in
control of the Shawnee-TCA scrubber
process (OAQPS-78-1, II-D-440, page
3). It was at the Shawnee test that the
best control of FGD process variability
by an existing FGD system was
demonstrated (OAQPS-78-1, II-B-13).
The Louisville test appears to
represent a special case. The average
process variation was significantly
higher (0.30 and 0.34 for the two units
tested) than was recorded at the two
other tests (Pittsburgh and Shawnee).
An EPA contractor identified two
factors which potentially could
adversely affect process control at
Louisville (OAQPS-78-1, VI-B-14). First,
they noted that Louisville was originally
designed in the 1960's and has had
significant retrofit design changes which
could affect process control. Second, the
degree of operator attention given to
process control is unknown. In addition,
UARG showed that an additional factor
which may affect the FGD process
control is boiler load changes. Unlike a
new boiler, the Louisville unit is an
older boiler which has been placed into
peaking service and therefore
experiences significant load changes
during the course of a day. As was the
case with Pittsburgh and Shawnee,
Louisville only uses pH controls to
regulate the process. The process
variation was analyzed and the
maximum process variation of the
Louisville system, at a 95 percent
confidence level, was determined to be
0.36 geometric standard deviation
(OAQPS-78-1, VI-B-13). This estimate
of process variation represents a "worst
case" situation since it reflects the
degree of FGD variability at a peaking
unit rather than on the more easily
controlled immediate- or base-loaded
applications.
In addition to basing their projections
on nonrepresentative systems, UARG
has also ignored information in a
background information document
(OAQPS-78-1, II-B-4. section 4.2.6) on
feasible process control improvements
which were currently used in Japan
(OAQPS-78-1, H-I-359). An appraisal of
the degree of process instrumentation
and control in use at the existing FGD
systems tested and a review of the
feasible process control improvements
which can be designed into new FGD
systems was also reviewed (OAQPS-
78-1, VI-B-14). As described in this
review, none of systems tested had
automatic process instrumentation
control in operation. All adjustments to
scrubber operation were made by
intermittent, manual adjustments by an
operator. Automatic process controls,
which provide immediate and
continuous adjustments, can reduce the
process control response time and the
magnitude of FGD efficiency variation.
Even the best controlled FGD systems
tested (the Shawnee FGD system, which
was designed in the 1960's) employed
only feedback pH process control
systems (OAQPS-78-1, IV-J-20). None
of these existing FGD systems were
designed with the feedforward process
control features now used in Japan
(OAQPS-78-1, II-I-359) for the
automatic adjustment of scrubber make-
up in response to changing operating
conditions. These systems respond to
boiler load changes or the amount of
SOi in the flue gases to be cleaned
before they impact the scrubbing
system. The use of such systems would
improve the control of short-term FGD
efficiency variation. At the FGD systems
tested, the actual flue gas SO»
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concentration (affected by coal sulfur
content) and gas volume (affected by
boiler load) was not routinely monitored
by the FGD system operators for the
purpose of controlling the FGD
operation as is currently practiced in
Japan (OAQPS-78-1.11-I-359). Thus,
even the best controlled existing
systems tested were not representative
of the control of process variation that
would be expected in the performance
of new FGD systems to be operated in
the 1980's (OAQPS-78-1, VI-B-14). For
the purpose of describing the range in
performance of an FGD system using
only feedback pH control and which are
known to have received close attention
by operating personnel, the data
recorded at these two existing FGD
systems (Pittsburgh, test II and
Shawnee-TCA) have been used by EPA
to project the maximum process
variation that would result (0.23
geometric standard deviation) at a 95
percent confidence interval for a base
loaded boiler. The data from Louisville
was used to represent performance of a
peak loaded boiler (0.36 geometric
standard deviation at the 95 percent
confidence level). These values are
conservative because the data collected
at the existing FGD systems tested are
not representative of the lower process
variation that would be expected in
future FGD systems designed with
improved process control systems
(OAQPS-78-1, VI-B-14).
EPA's statistical analysis of scrubber
efficency is in close agreement with the
UARG analysis when-the same process
variation and amount of autocorrelation
was assumed. EPA's analysis showed
about the same autocorrelation effect
(the tendency for scrubber efficiency to
follow the previous day's performance)
as UARG's analysis. A "worst-case" 0.7
autocorrelation factor was used in both
analyses even though a more favorable
0.6 factor could have been used based
upon the measured autocorrelation of
the data at the Shawnee-TCA and
Pittsburgh tests. A comparison of the
minimum 30-day average performance
of a FGD system based upon EPA and
UARG process variation assumptions is
given in Table 5a.
The EPA analysis (OAQPS-78-1, VI-
B-13) summarized in Tables 5a and 5b
shows the median scrubbing efficieny
required to achieve various minimum 30-
day rolling average removal levels
(probability of 1 violation in 10 years).
The three sets of estimates shown are
based on (1) the same process control
demonstrated at Pittsburgh, test II and
loaded, well-operated existing plant
(a,=0.20 on average and cr,=0.23 at the
95 percent confidence level), (2) the
same process control demonstrated at
Louisville which represents a peak
loaded, existing plant (or,=0.32 on
average and o-,=0.36 at the 95 percent
confidence level), and (3) the poor
process control projected by UARG
(or,=0.29 on average and o-,=0.43 at the
95 percent confidence level). The
process variation is described on a 24-
hour, geometric standard deviation (o-()
basis to allow comparison with UARG's
analysis. However, the minimum FGD
efficiencies shown in Tables 5a and 5b
are 30-day rolling averages.
It is evident from the analysis
summarized in Table 5a that if a new
FGD system could be operated at least
as well as the two best controlled
existing FGD systems tested, a 92
percent efficient scrubber (median) can
achieve between 88 and 89 percent
control on a 30-day rolling average
Shawnee-TCA. which represents a base
basis.'More than 89 percent minimum
reduction could be obtained if the
process variations in new FGD systems
are kept under better control with new
control system instruments and careful
attention by operating personnel. Even
the peak-loaded Louisville system,
which has much higher process
variability (o-,=0.32 on average), could
achieve 86 to 87 percent reduction.
When reviewing the results of
analyses contained in Tables 5a and 5b,
it must be kept in mind that they
represent "worst case" projections of
compliance capability. Neither the
UARG nor EPA projections took into
account load shifting or the effect of a
spare FGD module as a means of
countering worst-case system
performance (as portrayed by the 95
percent confidence level).
1 With a risk assumption of one violation per year
(the assumption used by UARG] the minimum 30-
day rolling average was between 89 percent and 90
percent control at the 95 percent confidence level
(OAQPS-78-1. VI-B-13, page 1-4).
Table Sa.—Median FGD Efficiency to Attain Minimum 30-day Rolling Average Standard for Base Loaded
Units1**
Minimum 30-day rolling average Median efficiency for existing well-controlled
FGD efficiency FGD systems tested [EPA basts]
Median efficiency lor an existing FGD
systems tested [UARG basts]
Average
to-.=0.20J
Maximum Average
tcr.oO.23] {cr.-0.29]
Maximum [ Estimates are based on probability of only 1 violation in 10 yean. Process variation (cr, to expressed as one geometric
standard deviation, 24-hour basts). The maximum process variation is projected at the 95th percentite.
Table St.—Median FGD Efficiency to Attain
' Minimum 30-day Rolling A verage Standard for Peak
Loaded Units.™
Minimum 30-day
rolling average
FGD efficiency
Median efficiency for peak loaded,
existing FGD systems tested [EPA
basis]
90
89
88
87
86
85
Average
t Estimates are based on probability of only 1 violation in
10 years. Process variation (o-J • expressed as one geomet-
ric standard deviation, 24-hour basts. The maximum process
variation is projected at the 95th percentile.
EPA also contended that an FGD
system supplier could miss the mark in
designing a 92 percent median efficiency
FGD system and that a miscalculation of
only 1 or 2 percent in median efficiency
would prevent the FGD system from
complying with the final SO> percent
reduction standard (UARG petition,
Appendix B, p. 64). EPA specifically
addressed this miss-the-mark argument
when it established a variable control
standard (70 percent to 90 percent
reduction). In the preamble to the final
standard EPA stated, "Finally, under a
variable approach, a source could move
to a lower sulfur content coal to achieve
compliance if its control equipment
failed to meet design expectations" (44
FR 33583, left column). An FGD system
designed for high-sulfur coal would
increase in scrubbing efficiency if a
lower-sulfur coal were fired, and the
amount of removal required for
compliance would drop from 90 percent
to as low as 70 percent reduction in
potential SOa emissions.
Even if, as UARG contends, an FGD
system on a 30-day rolling average basis
(through poor design or operating
practices) could only attain 85 percent
reduction, the facility would comply
with the promulgated 90 percent
reduction standard when credits for
sulfur removed by coal washing,
pulverizers, and in bottom and fly ash
are considered. These credits which can
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be substantial, are summarized as
follows:
1. Coal washing. On high-sulfur
midwestern coals that would be subject
to the 90 percent reduction requirement,
an average of 27 percent sulfur removal
was achieved by conventional coal
washing plants in 1978 (OAQPS-78-1),
IV-D-761). Even in Ohio where the
lowest average coal washing reduction
was recorded, 20 percent reduction was
attained. These data represent current
industry practice and do not necessarily
represent full application of state-of-the-
art in coal cleaning technology.
2. Coal pulverizers. Additional sulfur
reductions are also attainable with coal
pulverizers used at power plants. Coal is
typically pulverized at power plants
prior to combustion. By selecting a
specific type of coal pulverizer (one that
will reject pyrites from the pulverized
coal), sulfur can be removed. One utility
company reported to EPA that sulfur
reductions of 12% to 38% (with 24%
average removal) had been obtained
(OAQPS-78-1, II-D-179) by the
pulvizers alone when a program had
been implemented to optimize the
rejection of pyrites by the pulverizer
equipment.
3. Ash retention. One utility company
has reported 0.4% to 5.1% sulfur removal
credit in bottom ash alone with eastern
and midwestern coals and 7.3% to 15.9%
removal with a western coal (OAQPS-
78-1, Il-B-72). To determine how much
sulfur is removed by the bottom ash and
fly ash combined, EPA conducted a
study in which numerous boilers were
tested. The amount of Sd emitted was
compared to the potential SO> emissions
in the coal. For eight western coals and
six midwestern coals, an average sulfur
retention of 20 percent and 10 percent,
respectively, was found (OAQPS-78-1,
IV-A-6). Thus, an average of at least 10
percent SO* reduction can be attributed
to sulfur retention in coal ash.
These credits together with an FGD
system continuously achieving as little
as 85 percent reduction are sufficient to
attain compliance with the final SOi
percent reduction standard as is shown
in Table 6:
Table 6.—Impact of Sulfur Reduction Credits
on Required FGD Control Efficiencies to
Attain 90 Percent Overall SO, Reduction
SOi removal method
Compliance
•Option
C
Coal washing removal, percent...- 27 20 8
Pulvenzei, lly ash, and bottom ash
reduction, percent ... 10 4 0
FGD system removal, percent 65 67 89
Overall SO, reduction in potential
emissions «. _.T. T.lllll[[ Qo BO 80
Table 6 illustrates that even if the
FGD system attained only 85 percent
reduction as UARG has claimed, the 90
percent removal standard would be
achieved (Option A) even if a coal
washing plant attained only 27 percent
reduction in sulfur (the average
reduction reported by the National Coal
Association for conventional coal
washing plants, OAQPS-78-1. IV-D-
761). In addition, Table 6 illustrates that
less fuel credit is needed when the FGD
system attains more than 85 percent
reduction (Options B and C). For
example, even if the minimum amount of
coal washing curently being achieved
(20 percent in Ohio) is attained, only 87
percent FGD reduction would bex
needed. Thus, less than average or only
average sulfur reduction credits (i.e.,
only 8-27% coal washing and 0-10%
pulverizer, bottom ash and fly ash
credits) would be needed to comply with
the 90 percent reduction standard even
if the FGD system alone only attained 85
to 89 percent control. Moreover, for 75
percent of the nation's coal reserves
which have potential emissions less
than 260 ng/J (6.0 Ibs/million Btu) heat
input (OAQPS-78-1, IV-E-12. page 18),
less than 90 percent reduction in
potential SOt emissions would be
needed to meet the standard
The statistical analysis submitted by
UARG does not address the basis (FGD
and sulfur reduction credits) of the
standard and therefore does not alter
the conclusions regarding the
achievability of the promulgated percent
reduction standard. The prescribed level
can be achieved at the individual plant
level even under the most demanding
conditions through the application of
scrubbers together with sulfur reduction
credits.
Finally, UARG's petition (p. 15) states
that the final standard was biased by an
error in the preamble (see table, 44 FR
33592) which incorrectly referred to
certain FGD removal efficiencies as
"averages" rather than as geometric
"means" (medians). These removal
efficiencies were properly referred to as
"means" in the EPA test reports. This
discrepancy had no bearing on EPA's
decision to promulgate a 90 percent SOS
standard. Even though UARG claims a
bias was introduced, their consultant's
report states (see Appendix B, Page 46):
Therefore, even though EPA mistakenly
used the term "average SOt removal" in the
promulgation, it it obvious that when the
phrase "mean FGD efficiency" is used, EPA is
correctly referred to the mean (or median) of
the long-normal distribution of (1-eff).
Thus, even though Entropy (UARG's
consultant which prepared their
statistical analysis in Appendix B)
"discovered a discrepancy" as UARG
alleges, they did not reach a conclusion
as UARG has done, that a simple
transcription error in preparation of the
preamble undermined the credibility of
EPA's analysis of the test data. In fact,
the analysis of test data performed by
EPA (OAQPS-78-1,0-B-4) used correct
statistical terminology.
The Sierra Club also submitted a
petition that questioned the promulgated
90 percent, 30-day rolling average
standard. The petition asks "why the
final percentage of removal for 'full
scrubbing' was set at only 90 percent for
a 30-day average" in view of the
preamble to the proposal which
mentions a 92 percent reduction (43 FR
42159). The petition states that "EPA
indicated that 85 percent scrubbing on a
24-hour average was equivalent to 92
percent on a 30-day average." This
statement is a misquotation. The
preamble actually stated that "an FGD
system that could achieve a 92 percent
long-term (30 days or more) mean SO»
removal would comply with the
proposed 85 percent (24-hour average)
requirement." The long-term mean
referred to is the median value
(geometric mean) of FGD system
performance, not an equivalent
standard. Reference in the preamble
was made to the background
information supplement (OAQPS-78-1,
III-B-4) which provided "a more
detailed discussion of these findings."
The 92 percent removal is described
therein as the median (geometric mean)
of the statistical distribution defined by
the "line of improved performance" in
Figure 4-1. A median is the middle
number in a given sequence of numbers.
Thus for a sequence of 24-hour or 30-day
rolling average efficiencies, the median
SOt removal (92 percent) is a level at
which one-half of the 30-day rolling
average FGD system efficiencies would
be higher and one-half would be lower.
Since one-half of the expected removal
efficiencies would be lower than the 92
percent median, a standard could not be
set at that level. The standard must
recognize the range of 30-day rolling
average FGD efficiencies that would be
expected. The petition is based upon a
misconception as to the meaning of the
92 percent value (a median) and is
therefore not new information of central
relevance to this issue.
The Environmental Defense Fund
requested that EPA consider the
relevance of the lime/limestone-adipic
acid tests at Shawnee to this
rulemaking. Adipic acid has been found
to increase FGD system performance by
limiting the drop in pH that normally
occurs at the gas/liquid interface during
SOi absorption. Test runs at Shawnee
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showed increased FGD performance (in
one test series the efficiency increased
from 71 percent to 93 percent) with no
apparent adverse impact upon FGD
system operation.
EPA agrees that use of adipic acid
additive in lime/limestone scrubbing
solutions appears very promising and is
currently planning a full-scale FGD
system demonstration. Several
important areas are to be evaluated in
the EPA test program. The handling and
disposal characteristics of waste sludges
from the scrubber must be evaluated to
see that adipic acid does not affect
control of leachates into groundwater. In
addition, the consumption rate of adipic
acid by the FGD system and its ultimate
disposition must be evaluated.
Furthermore, tests must be conducted to
show whether or not the concentration
of adipic acid in FGD system sludge
poses significant environmental
problems. In the absence of such data,
EPA does not believe it prudent to
include adipic acid as a basis for the
current revised standard.
IV. Particulate Matter Standards
Only one of the four petitions for
reconsideration raised issues concerning
the particulate matter standard. In their
petition, the Utility Air Regulatory
Group (UARG) argued principally that
baghouse technology was not
demonstrated on large coal-fired utility
boilers and that the 13 ng/J (0.03 lb/
million Btu) heat input standard could
not be achieved at reasonable costs
with electrostatic precipitators on low-
sulfur coal applications. They also noted
that emission test data on a 350 MW
baghouse application was placed in the
record after the close of the comment
period. In response to these data, UARG
presented operating information on
baghouse systems obtained from two
coal-fired installations. In addition they
restated arguments that had been raised
in their January 1979 comments
concerning EPA's data base and the
potential effects of NO, and SO,
emission control on particulate
emissions.
In reaching his decision that baghouse
technology is adequately demonstrated,
the Administrator took into account a
number of factors. In addition to the
emission test data and other technical
information contained in the record, he
placed significant weight on the fact that
at least 26 baghouse-equipped coal-fired
electric utility steam generators were
operating prior to promulgation of the
standard and that 28 additional units
were planned to start operation by the
end of 1982. He also noted that some of
the utility companies operating
baghouses on coal-fired steam
generators were ordering more
baghouses and that none of them had
announced plans to decommission or
retrofit a baghouse controlled plant
because of operating or cost problems.
The Administrator believed that this
was a strong indication that some
segments of the utility industry believe
that baghouses are practical,
economical, and adequately
demonstrated systems for control of
particulate emissions. These electric
utility baghouses are being applied to a
wide range of sizes of steam generators
and to coals of varying rank and sulfur
content. The Industrial Gas Cleaning
Institute speaking for the manufacturers
of baghouses submitted comments
(OAQPS-78-1, IV-D-247) confirming
that baghouses are adequately
demonstrated systems for control of
particulate emissions from coal-fired
steam-electric generators of all sizes and
types.
In the proposal, EPA acknowledged
that large baghouses of the size that
would typically be used to meet the
standard had only been recently
activated. Further, the Agency
announced that it planned to test a 350
MW unit (43 FR 42169, center column).
The validated test data from this unit,
located at the Harrington Station,
demonstrated that the standard could be
achieved at large facilities (OAQPS-78-
1, V-B-1, page 4-1). The Agency also
became aware that the operators of the
facility were encountering start-up
problems. After carefully evaluating the
situation, the Agency concluded that the
problems were temporary in nature (44
FR 33585, left column).
Furthermore, Appendix E of the
UARG petition supports the Agency
finding. According to Appendix E, the
start-up problems experienced at
Harrington Station (Unit #2} have not
affected unit availability nor have they
altered the utility's plans for equipping
another large coal-fired steam generator
at the site (Unit #3) with a baghouse.
Appendix E noted, "The company feels
that the baghouse achieved an
availability equal to that of the
electrostatic precipitator installed in
unit 1" (UARG petition, Appendix E,
page 2). The Appendix also examined
two retrofit baghouse installations on
boilers firing Texas lignite at the
Monticello Station (Unit #1 and Unit
#2). While the first unit that came on
line experienced problems, Appendix E
notes, "Since the start-up of Unit 2 bag
filter, the baghouse has been operational
at all times the boiler was on line (due
to the solution of the majority of the
problems associated with Unit 1
baghouse)" (UARG petition, Appendix
E, page 5). These findings served to
reinforce the Agency's conclusion that
problems encountered at these initial
installations are correctible.
Based on the Harrington and
Monticello experience, UARG
maintained that EPA did not properly
consider the cost of activating and
maintairiing a baghouse. Contrary to
UARG's position, the cost estimates
developed by EPA provide liberal
allowances for start-up and continued
maintenancei For example, the Agency's
cost estimates for a baghouse for a 350
MW power plant provided over $1.4
million for start-up and first year
maintenance of which $440,000 was
included for bag replacement (OAQPS-
78-1, II-A-64 and VI-B-12). For
subsequent years, $710,000 per year was
allowed for routine maintenance of
which $440,000 was included for bag
replacement. In comparison, the UARG
petition indicated that bag replacement
costs during the first year of operation of
the baghouse at the Harrington Station
(350 MW capacity) would be $250,000
and the bag replacement costs at the
two Monticello baghouse units (610 MW
capacity total) would total about
$642,000. From the information provided
by UARG, it appears that the Agency
has fully accounted for any potential
costs that may be incurred during start-
up or annual maintenance.
UARG further maintained that higher
pressure drops encountered at these
initial installations would increase the
cost of power to operate a baghouse
beyond those estimated by the Agency.
The Administrator agrees that if higher
pressure drops are encountered an
increase in cost will be incurred.
However, even assuming that the
pressure drops initially experienced at
the Harrington and Monticello Stations
occur generally, the annual cost will not
increase sufficiently to affect the
Administrator's decision that the
standard can be achieved at a
reasonable cost. For example, the
increase in pressure drop reported by
UARG (UARG petition, page 43) at the
Harrington station would result in a cost
penalty of about $191,000 per year,
which represents only a 4.5 percent
increase in the total annualized
baghouse costs projected by EPA
(OAQPS-78-1, II-A-64, page 3-18) and
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less than one percent increase in
relation to utility operating costs. It
should be reported, however, that as a
result of corrective measures taken at
Harrington station since start-up, the
operating pressure drop reported by
UARG has been reduced. If the pressure
drop stabilizes at this improved level 2
kilopascals (8 inches H2O) rather than
the 2.75 kilopascals (11 inches H2O)
suggested by UARG the $191.000 cost
penalty would be reduced by some
$90,000 per year (OAQPS-7&-1, VI-B-11
and UARG petition, page 43).
UARG also maintained that a period
longer than 180 days after start-up is
required to shake down new baghouse
installations, and that EPA should
amend 40 CFR 60.8, which requires
compliance to be demonstrated within
180 days of start-up. UARG based these
comments on the experience at the
Harrington and Monticello Stations. It is
important to understand that 40 CFR
60.8 only requires compliance with the
emission standards within 180 days of
start-up and does not require, or even
suggest, that the operation of the facility
be optimized within that time period.
Optimization of a system is a continual
process based on experience gained
with time. On the other hand, a system
may be fully capable of compliance with
the standard before it is fully optimized.
In the case of the Harrington station
the initial performance test was
conducted by the utility during October
1978 (which was within four months of
start-up). The initial test and a
subsequent one were found however, to
be invalid due to testing errors and
therefore it was February 1979 before
valid test results were obtained for the
Harrington Unit (OAQPS-78-1, IV-B-1,
page 42). This test clearly demonstrated
achievement of the 13 ng/J (0.03 lb/
million Btu) heat input emission level.
These results were obtained even
though the unit was still undergoing
operation and maintenance refinements.
With respect to the Monticello station.
UARG reported that no actual
performance test data are available
(UARG petition, Appendix E, page 6).
UARG also maintained that
baghouses are not suitable for peaking
units because of the high energy penalty
associated with keeping the baghouse
above the dew point. EPA recognizes
that baghouses may not be the best
control device for all applications. In
those instances where high energy
penalties may be incurred in heating the
baghouse above the dew point, the
utility would have the option of
employing an electrostatic precipitator.
However, some utilities will be using
bughouses for peaking units. For
example, the baghouse control system
on four subbituminous, pulverized coal-
fired boilers at the Kramer Station have
been equipped with baghouse preheat
systems and that station will be placed
in peaking service in the near future
(OAQPS-78-1, VI-B-10).
UARG also argued that it may be
necessary to install a by-pass system in
conjunction with a baghouse to protect
the baghouse from damage during
certain operation modes. The use of
such a system during periods of start-up,
shutdown, or malfunction is allowed by
the standard when in keeping with good
operating practice.
The UARG petition implied that the
test data base for electrostatic
precipitator systems (ESP) is inadequate
for determining that such systems can
meet the standard. Contrary to UARG's
position, the EPA data base for the
standard included test data obtained
under worst-case conditions, such as (1)
when high resistivity ash was being
collected, (2) during sootblowing, and (3)
when no additives to enhance ESP
performance were used (OAQPS-78-1,
1II-B-1, page 4-11 and 4-12). Even when
all of the foregoing worst-case
conditions were incurred
simultaneously, particulate matter
emission levels were still less than the
standard. It should also be understood
that none of the ESP systems tested
were larger than the model sizes used
for estimating the cost of control under
worst-case conditions.
The UARG petition also questioned
the Administrator's reasoning in failing
to evaluate the economic impact of
applying a 197 square meter per actual
cubic meter per second (1000 ft 2/1000
ACFM) cold-side ESP to achieve the
standard under adverse conditions such
as when firing low-sulfur coal. The
Administrator did not evaluate the
economic impact of applying a large.
cold-side ESP because a smaller, less
costly 128 square meter per actual cubic
meter per second (650 ft J/1000 ACFM)
hot-side ESP would typically be used.
The Administrator believed that it
would ha\e been non-productive to
investigate the economics of a cold-side
ESP when a hot-side ESP would achieve
the same level of emission control at a
lower cost.
The UARG petition also suggested
that hot-side ESP's are not always the
best choice for low-sulfur coal
applications. The Administrator agrees
with this position. In some case, low-
sulfur coals produce an ash which is
relatively easy to collect since flyash
resistivity is not a problem. Under such
conditions it would be less costly to
apply a cold-side ESP and therefore it
would be the preferred approach.
However, when developing cost impacts
of the standard, the Agency focused on
typical low-sulfur coal applications
which represents worst case conditions,
and therefore assessed only hot-side
precipitators.
The UARG petition suggests that in
some cases the addition of chemical
additives to the flue gas may be required
to achieve the standard with ESPs, and
the Agency should have fully assessed
the environmental impact of using such
additives. The Administrator, after
assessing all available data, concluded
that the use of additives to improve ESP
performance would not be necessary
(OAQPS-78-1, III-B-1, page 4-11).
Therefore, it was not incumbent upon
EPA to account for the environmental
impact of the use of additives other than
to note that such additives could
increase SO3 or acid mist emissions. In
instances where a utility elects to
employ additives as a cost saving
measure, their potential effect on the
environment can be assessed on a case-
by-case basis during the new source
review process.
UARG also maintained that there are
special problems with some low-sulfur
coals that would preclude the use of hot-
side ESPs and attached Appendix F in
support of their position. Review of
Appendix F reveals that while the
author discussed certain problems
related to the application of hot-side
ESPs on some western low-sulfur coal,
he also set forth effective techniques for
resolving these problems. The author
concluded, "The evidence of more than
11 years of experience indicates that hot
precipitators are here to stay and very
likely their use on all types of coal will
increase."
UARG also argued that the data base
in support of the final particulate
standard for oil-fired steam generating
units was inadequate. The standard is
based on a number of studies of
particulate matter control for oil-fired
boilers. These studies were summarized
and referenced in the BID for the
proposed standard (OAQPS-78-1, III-B-
1, page 4-39). These earlier studies
(Control of Particulate Matter from Oil
Burners and Boilers. April 1976, EPA-
450/3-76-005; and Particulate Emission
Control Systems for Oil-fired Boilers.
December 1974, EPA-450/3-74-063)
support the conclusion that ESP control
systems are applicable to oil-fired steam
generators and that such emission
control systems can achieve the
standard. The achievability of the
standard was also confirmed by the
Hawaiian Electric Company, a firm that
would be significantly affected by the
standard since virtually all their new
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generating capacity will be oil-fired due
to their location. In their comments the
company indicated, "Hawaiian Electric
Company supports the standards as
proposed in so far as they impact upon
the electric utilities in Hawaii"
(OAQPS-78-1, IV-D-159).
UARG also argued that the
Administrator had little or no data upon
which to base a conclusion that the
particulate standard is achievable for
lignite-fired units. In making this
assertion, UARG failed to recognize that
the Agency had extensively analyzed
lignite-fired units in 1976 and concluded
that they could employ the same types
of control systems as those used for
other coal types (EPA-450/2-76-030a,
page 11-29). Additionally, review of the
literature and other sources revealed no
new data that would alter this finding
(Some of the data considered includes
OAQPS-78-1,11-I-59, H-I-312, and II-I-
322) and the Agency continues to
believe that the emission standards are
achievable when firing all types of coal
including lignite coal. UARG has not
provided any information during the
comment period or in their petition
which would suggest any unique
problems associated with the control of
particulate matter from lignite-fired
units.
The UARG petition alleged that the
Administrator did not take into account
the effect of NO, control in conjunction
with promulgation of the particulate
standard. In developing the NO,
standard, the Administrator assessed
the possibility that NO, controls may
increase ash combustibles and thereby
affect the mass and characteristics of
particulate emissions. The
Administrator concluded, however, that
the NO, standard can be achieved
without any increase in ash
combustibles or any significant change
in ash characteristics and therefore
there would be no impact on the
particulate standard (OAQPS-78-1, III-
B-2, page 6-14).
UARG also raised the issue of sulfate
carryover from the scrubber slurry and
its potential effect on particulate
emissions. EPA initially addressed this
issue at proposal and concluded that
with proper mist eliminator design and
maintenance, liquid entrainment can be
controlled to an acceptable level (43 FR
42170, left column). Since that time, no
new information has been presented
that would lead the Administrator to
reconsider that finding.
In summary, UARG failed to present
any new information on particulate
matter control that is centrally relevant
to the outcome of the rule.
V. NOx Standards
The Utility Air Regulatory Group
(UARG) sought reconsideration of the
NO, standards. They maintained that
the record did not support EPA's
findings that the final standards could
be achieved by all boiler types, on a
variety of coals, and on a continuous
basis without an unreasonable risk of
adverse side effects. In support of this
position, they argued that while EPA's
short-term emissions data provided
insight into NO, levels attainable by
utility boilers under specified conditions
during short-term periods, they did not
sufficiently support EPA's standards
based on continuous compliance.
Further, they maintained that the
continuous monitoring data relied on by
the Agency does not support the general
conclusions that all boiler types can
meet the standards on a variety of coals
under all operating conditions. They
also argued that the Agency failed to
collect or adequately analyze data on
the adverse side effects of low-NO,
operations. Finally, they contended that
vendor guarantees have been shown not
to support the revised standards. The
arguments presented in the petition
were discussed in detail in an
accompanying report prepared by
UARG's consultant.
In general, the UARG petition merely
reiterated comments submitted in
January 1979. Their arguments
concerning short-term test data, the
potential adverse side effects of low-
NO, operation, and manufacturer's
guarantees did not reflect new
information nor were they substantially
different from those presented earlier.
For example, in their petition, UARG
asserted that new information received
at the close of comment period revealed
that certain data EPA relied upon to
conclude that low-NO, operations do
not increase the emissions of polycyclic
organic matter (POM) are of
questionable validity (UARG petition,
page 56). This comment repeats the
position stated in UARG's January 15,
1979, submittal (OAQPS 7&-1, IV-D-«11.
attachment—KVB report, January 1979,
page 86). More importantly, UARG
failed to recognize that EPA did not rely
on the tests in question and that the
Agency noted in the BID for the
proposed standards (OAQPS-78-1. III-
B-2, page 6-12) that the data were
insufficient to draw any conclusion on
the effects of modern, low-NO, Babcock
and Wilcox burners on POM emissions.
Instead, EPA based its conclusions in
regard to POM on its finding that
combustion efficiency would not
decrease during low-NO, operation and
therefore, there would not be an
increase in POM emissions (43 FR 42171,
left column and OAQPS-78-1, III-B-2,
page 9-6).
Similarly, UARG did not present any
new data in regard to boiler tube
corrosion. They merely restated the
arguments they had raised in their
January 1979 comments which
questioned EPA's reliance on corrosion
test samples (coupons). EPA believes
that proper consideration has been
given to the corrosion issues and
substantial data exist to support the
Administrator's finding that the final
requirements are achievable without
any significant adverse side effect (44
FR 33602, left column). In addition,
UARG also maintained that the Agency
should explain why it dismissed the 190
ng/J (0.45 Ib/million Btu) heat input NO,
emission limit (44 FR 33602, right
column) applicable to power plants in
New Mexico. In dismissing the
recommendation that the Agency adopt
a 190 ng/J emission limit, the
Administrator noted that the only
support for such an emission limitation
was in the form of vendor guarantees.
In relation to vendor guarantees,
UARG maintained in their January
comments and reiterate in their petition
that EPA should not rely on vendor
guarantees as support for the revised
standards. EPA cannot subscribe to
UARG's narrow position. While vendor
guarantees alone would not provide a
sufficient basis for a new source
performance standard, EPA believes
that consideration of vendor guarantees
when supported by other findings is
appropriate. In this instance, the vendor
guarantees served to confirm EPA
findings that the boiler manufacturers
possess the requisite technology to
achieve the final emission limitations.
This approach was described by Foster
Wheeler in their January 3,1979, letter
to UARG, (OAQPS 78-1, IV-D-611,
attachment—KVB report, January 1979,
page 119) that states, "When a
government regulation, which has a
major effect on steam generator design,
is changed it is unreasonable to judge
the capability of a manufacturer to meet
the new regulation by evaluating
equipment designed for the older less
stringent regulation."
This observation is also germane to
the arguments raised by UARG with
respect to EPA data on short-term
emission tests and continuous
monitoring. In essence, UARG
maintained that the EPA data base was
inadequate because boilers designed
and operated to meet the old 300 ng/J
(0.7 Ib/million Btu) heat input limitation
under Subpart D have not been shown
to be in continuous compliance with the
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new standard under Subpart Da. While
this statement is true, these units, which
were designed and operated to meet the
old standard, incurred only five
exceedances of the new standards on a
monthly basis. Moreover, a review of
the available 34 months of continuous
monitoring data from six utility boilers
revealed that they all operated well
below the applicable standard (OAQPS-
78-1. V-B-1).
In addition, UARG argued that the
available continuous monitoring data
demonstrated that the Agency should
not have relied on short-term test data.
Citing Colstrip Units 1 and 2, they noted
that less than one-third of the 30-day
average emissions fell below the units'
performance test levels of 125 ng/J (0.29
Ib/million Btu) heat input and 165 ng/J
{0.38 Ib/million Btu) heat input,
respectively. They further maintained
that this had not been considered by the
Agency. In fact, the Administrator
recognized at the time of promulgation
that emission values obtained on short-
term tests could not be achieved
continuously because of potential
adverse side effects and therefore
established emission limits well above
the values measured by such tests (44
FR 42171, left column). In addition. EPA
took into account the emission
variability reflected by the available
continuous monitoring data when it
established a 30-day rolling average as
the basis of determining compliance in
the standards (44 FR 33586, left column).
UARG also maintained in their
petition that EPA should not rely on the
Colstrip continuous monitoring data
because it was obtained with uncertified
monitors. The Administrator recognized
that the Colstrip data should not be
relied on in absolute terms since
monitors were probably biased high by
approximately 10 percent (OAQPS 78-1,
III-B-2, page 5-7). EPA's analysis of
data revealed, however, that it would be
appropriate to use the data to draw
conclusions about variability in
emissions since the shortcoming of the
Colstrip monitors did not bias such
findings. This data together with data
obtained using certified continuous
monitors at five other facilities (OAQPS
78-1, V-B-1, page 5-3) and the results
from 30-day test programs (manual tests
performed about twice per day) at three
additional plants (OAQPS 78-1, 0-8-62
and II-B-70) enabled the Administrator
to conclude that emission variability
under low-NO, operating conditions
was small and therefore the prescribed
emission levels are achievable on a
continuous basis.
UARG argued that since the only
continuous monitoring data available
was obtained from boilers manufactured
by Combustion Engineering and on a
limited number of coal types, the
Agency did not have a sufficient basis
for finding that the standards can be
achieved by other manufacturers or
when other types of coals are burned.
The Administrator concluded after
reviewing all available information that
the other three major boiler
manufacturers can achieve the same
level of emission reduction as
Combustion Engineering with a similar
degree of emission variability (43 FR
42171, left column and 44 FR 33588,
middle column). This finding was
confirmed by statements submitted to
UARG and EPA by the other vendors
that their designs could achieve the final
standards, although they expressed
some concern about tube wastage
potential (OAQPS-78-1, UI-D-611,
attachment-KVB report, pages 116-121
and IV-D-30). EPA has considered tube
wastage (corrosion) throughout the
rulemaking and has determined that it
will not be a problem at the NO,
emission levels required by the
standards (44 FR 33602, left column).
With respect to different coal types, the
Agency concluded from its analysis of
available data that NO. emissions are
relatively insensitive to differing coal
characteristics and therefore other coal
types will not pose a compliance
problem (43 FR 42171, left column and
OAQPS-78-1, IV-B-24). UARG did not
submit any data to refute this finding.
UARG also argued that the continuous
monitoring data should have been
accompanied by data on boiler
operating conditions. EPA noted that the
data were collected during extended
periods representative of normal
operations and therefore it reflected all
operational transients that occurred. In
particular, at Colstrip units 1 and 2 more
than one full year of continuous
monitoring data was analyzed for each
unit. In view of this, EPA believes that
the data base accurately reflects the
degree of emission variability likely t*
be encountered under normal operating
conditions. UARG recognized this in
principle in their January 15 comments
(Part 4, page 15) when they stated that
"continuous monitors would measure all
variations in NO, emissions due to
operational transients, coal variability,
pollution control equipment degradation,
etc/-
In their petition, UARG restated their
January 1979 comments that EPA's
short-term test data were not
representative and therefore should not
serve as a basis for the standard. As
noted earlier, EPA did not rely
exclusively on short-term test data in
setting the final regulations. In addition,
contrary to the UARG claim, EPA
believes that the boiler test
configurations used to achieve low-NO,
operations reflect sound engineering
judgement and that the techniques
employed are applicable to modern
boilers. This is not to say that the boiler
manufacturers may not choose other
approaches such as low-NO, burners to
achieve the standards. While
recognizing that EPA's test program was
concentrated on boilers from one
manufacturer, sufficient data was
obtained on the other major
manufacturers' boilers to confirm the
Agency's finding that they would exhibit
similar emission characteristics (44 FR
33586, left column). Therefore, in the
absence of new information, the
Administrator has no basis to
reconsider his finding that the
prescribed emission limitations are
achievable on modern boilers produced
by all four major manufacturers.
VI. Emission Measurement and
Compliance Determination
The Utility Air Regulatory Group
(UARG) raised several issues pertaining
to the accuracy and reliability of
continuous monitors used to determine
compliance with the SOi and NO,
standards. UARG particularly
commented on the data from the
Conesville Station. In addition, they also
maintained that the sampling method for
particulates was flawed. With respect to
compliance determinations, UARG
maintained that the method for
calculating the 30-day rolling averages
should be changed so that emissions
before boiler outages are not included
since they might bias the results. In
addition, UARG argued that the
standards were flawed since EPA had
not included a statement as to how the
Agency would consider monitoring
accuracy in relation to compliance
determination. With the exception of the
method of calculating the 30-day rolling
average and the comments on the
Conesville station, the petition merely
reiterated comments submitted prior to
the close of the public comment period.
As to the reliability and durability of
continuous monitors, information in the
docket (OAQPS-78-1. D-A-88, IV-A-20.
IV-A-21, and IV-A-22) demonstrates
that on-site continuous monitoring
systems (CMS) are capable and have
operated on a long-term basis producing
data which meet or exceed the minimum
data requirements of the standards.
In reference to the Conesville project.
UARG questioned why EPA dismissed
the continuous monitoring results since
it was the only long-term monitoring
effort by EPA to gain instrument
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operating experience. UARG maintained
that this study showed monitor
degradation over time and that it was
representative of state-of-the-art
monitoring system performance. This
conclusion is erroneous. EPA does not
consider the Conesville project adequate
for drawing conclusions about monitor
reliability because of problems which
occurred during the project.
To begin with, UARG is incorrect in
suggesting that the goal of the project
was to obtain instrument operating
experience. The primary purpose of the
project was to obtain 90 days of
continuous monitoring data on FGD
system performance. Because of
intermittent operation of the steam
generator and the FGD system, this
objective could not be achieved. As the
end of the 90-day period approached, a
decision was made to extend the test
duration from three to six months. The
intermittent system operation continued.
As a result, when the FGD outages were
deleted from the total project time of six
months, the actual test duration was
similar to those at the Louisville,
Pittsburgh, and Chicago tests and did
not, therefore, represent an extended
test program.
EPA does not consider the Conesville
results to be representative of state-of-
the-art monitoring system performance.
Because of the intermittent operation
throughout the test period (OAQPS-78-
1, IV-A-19, page 2), it became obvious
that the goals of the program could not
be met. As a result, monitoring system
maintenance lapsed somewhat. For
example, an ineffective sample
conditioning system caused differences
in monitor and reference method results
(OAQPS-7&-1, IV-A-20, page 3-2). If the
EPA contractor had performed more
rigorous quality assurance procedures,
such as a repetition of the relative
accuracy tests after monitor
maintenance more useful results of the
monitor's performance would have been
obtained. Thus, the Conesville study re-
emphasized the need for periodic
comparisons of monitor and reference
method data and the inherent value of
sound quality assurance procedures.
The UARG petition suggested that the
standards incorporate a statement as to
how EPA will consider monitoring
system accuracy during compliance
determination. More specifically, UARG
recommended that EPA define an error
band for continuous monitoring data
and explicitly state that the Agency will
take no enforcement action if the data
fall within the range of the error band.
The Agency believes that such a
provision is inappropriate. Throughout
this rulemaking, EPA recognized the
need for continuous monitoring systems
to provide accurate and reproducible
data. EPA also recognized that the
accuracy of a CMS is affected by basic
design principals of the CMS and by
operating and maintenance procedures.
For these reasons, the standards require
that the monitors meet (1) published
performance specifications (40 CFR Part
60 Appendix B] and (2) a rigorous
quality assurance program after they are
installed at a source. The performance
specifications contain a relative
accuracy criterion which establishes an
acceptable combined limit for accuracy
and reproducibility for the monitoring
system. Following the performance test
of the CMS, the standards specify
quality assurance requirements with
respect to daily calibrations of the
instruments. As was noted in the
rulemaking (44 FR 33611, right column),
EPA has initiated laboratory and field
studies to further refine the performance
requirements for continuous monitors to
include periodic demonstration of
accuracy and reproducibility. In view of
the existing performance requirements
and EPA's program to further develop
quality assurance procedures, the
Administrator believes that the issue of
continuous monitoring system accuracy
was appropriately addressed. In doing
so, he recognized that any questions of
accuracy which may persist will have to
be assessed on a case-by-case basis.
The UARG petition also raised as an
issue the calculation of the 30-day
rolling average emission rate. UARG
maintained that the use of emission data
collected before a boiler outage may not
be representative of the control system
performance after the boiler resumes
operation. UARG indicated that boiler
outage could last from a few days to
several weeks and suggested that if an
outage extends for more than 15 days, a
new compliance period should be
initiated. UARG also suggested that if a
boiler outage is less than 15 days
duration and the performance of the
emission control system is significantly
improved following boiler start-up, a
new compliance period should be
initiated. UARG argued that the data
following start-up would be more
descriptive of the current system
performance and hence would provide a
better basis for enforcement.
A basic premise of this rulemaking
was that the standard should encourage
not only installation of best control
systems but also effective operating and
maintenance procedures (44 FR 33595
center column, 33601 right column, and
33597 right column). The 30-day rolling
average facilitates this objective. In
selecting this approach, the Agency
recognized that a 30-day average better
reflects the engineering realities of SO2
and NO, control systems since it affords
operators time to identify and respond
to problems that affect control system
efficiency. Daily enforcement (rolling
average) was specified in order to
encourage effective operating and
maintenance procedures. Under this
approach, any improvement in emission
control system performance following
start-up will be reflected in the
compliance calculation along with
efficiency degradations occurring before
the outage. Therefore, the 30-day rolling
average provides an accurate picture of
overall control system performance.
On the other hand, the UARG
suggestion would provide a distorted
description of system performance since
it would discount certain episodes of
poor control system performance. Thai
is, the system operator could allow the
control system to degrade and then shut-
down the boiler before a violation of the
standard occurred. After start-up and
any required maintenance, a new
compliance period would commence,
thereby excusing any excursions prior to
a shut-down. In addition, since a new
averaging period would be initiated the
Agency would be unable to enforce the
standard for the first 29 boiler operating
days after the boiler had resumed
operation. In the face of this potential
for circumvention of the standards, the
Administrator rejects the UARG
approach.
UARG also reiterated their previous
comments that EPA did not properly
consider the accuracy and precision of
Reference Method 5 for measuring
particulate concentrations at or below
13 ng/J (0.03 Ib/million Btu) heat input.
EPA has recognized throughout this
rulemaking that obtaining accurate and
precise measurements of very low
concentrations of particulate matter is
difficult. In view of this, detailed and
exacting procedures for the clean-up
and analyses of the sample probe, filter
holder, and the filter were specified in
Method 5 to assure accuracy in
determining the mass collected.
Additionally, EPA has required that the
sampling time be increased from 60
minutes to 120 minutes. This will
increase the total sample volume frcjm a
minimum of 30 dscf to 60 dscf, thus
increasing the total mass collected to
about 100 mg at a loading of 13 ng/J
(0.03 Ib/million Btu) heat input. EPA has
concluded that measurement of mass at
this level can be reproduced within ±10
percent.
UARG also maintained that less than
ideal sampling can cause particulate
emission measurements to be inaccurate
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and this has not been evaluated. EPA
has addressed the question of
determining representative locations
and the number of sampling points in
some detail in the reference methods
and appropriate subparts. These
procedures were designed to assure
accurate measurements. EPA has also
evaluated the effects of less than ideal
sampling locations and concluded that
generally the results would be biased
below actual emissions. Assessment of
the extent of possible biases in
measurement data, however, must be
made on a case-by-case basis.
UARG raised again the issue of acid
mist generated by the FGD system being
collected in the Reference Method 5
sample, therefore rendering the emission
limit unachievable. EPA has recognized
this problem throughout the rulemaking.
In response to the Agency's own
findings and the public comments, the
standards permit determination of
particulate emissions upstream of the
scrubber. In addition, EPA announced
that it is studying the effect of acid mist
on particulate collection and is
developing procedures to correct the
collected mass for the acid mist portion.
VII. Applicability of Standards
Sierra Pacific Power Company and
Idaho Power Company (collectively,
"Sierra Pacific") petitioned the
Administrator to reconsider the
definition of "affected facility," asking
that the applicability date of the
standards be established as the date of
promulgation rather than the date of
proposal. 40 CFR 60.40a provides:
(a) The affected facility to which this
subpart applies is each electric utility steam
generating unit:
* * *
(2) For which construction or modification
is commenced after September 18.1978.
September 19,1978, is the date on
which the proposed standard was
published in the Federal Register. EPA
based this definition on sections
lll(a}(2) and lll(b)(6)of the Act.
Section lll(a)(2) provides:
The term "new source" means any
stationary source, the construction or
modification of which is commenced after the
publication of regulations (or. if earlier,
proposed regulations) prescribing a standard
of performance under this section which will
be applicable to such source.
Section lll(b)(6) includes a similar
provision specifically drafted to govern
the applicability date of revised
standards for fossil-fuel burning sources
(of which this standard is the chief
example.) It provides:
Any new or modified fossil fuel-fired
stationary source which commences
construction prior to the date of publication
of the proposed revised standards shall not
be required to comply with such revised
standards.
Sierra Pacific does not dispute that
the Agency's definition of affected
facility complies with the literal terms of
sections lll(a)(2) and lll(b)(6). Sierra
Pacific maintains, however, that the
definition is unlawful, because the
standard was promulgated more than 6
months after the proposal, in violation of
sections lll(b)(l)(B) and 307(d)(10).
Section lll(b)(l)(B) provides that a
standard is to be promulgated within 90
days of its proposal. Section 307(d)(10)
allows the Administrator to extend
promulgation deadlines, such as the 90-
day deadline in section lll(b)(l)(B), to
up to 6 months after proposal. Sierra
Pacific argues that section lll(a)(2) does
not apply unless the deadlines in
sections lll(b)(l)(B) and 307(d)(10) are
met. In this case the final standard was
promulgated on June 11,1979, somewhat
less than 9 months after proposal. (It
was announced by the Administrator at
a press conference on May 25,1979, and
signed by him on June 1,1979.)
In the Administrator's view, the
applicability date is properly the date of
proposal. First, the plain language of
section lll(a)(2) provides that the
applicability date is the date of
proposal. Second, the legislative history
of section 111 shows that Congress did
not intend that the applicability date
should be the date of proposal only
where a standard was promulgated
within 90 days of proposal. Section
lll(a)(2) took its present form in the
conference committee bill that became
the 1970 Clean Air Act Amendments,
whereas the 90-day requirement came
from the Senate bill, and there is no
indication that Congress intended to link
these two provisions.2
Moreover, this interpretation
represents longstanding Agency
practice. Even where responding to
public comments delays promulgation
more than 90 days, or more than 6
months, after proposal, the applicability
dates of new source performance
standards are established as the date of
proposal. See 40 CFR Part 60, Subparts
D et seq.
Sierra Pacific argues that its position
has been adopted by EPA in
"analogous" circumstances under the
Clean Water Act. This is inaccurate.
Section 306 of the Clean Water Act
specifically provides that the date of
proposal of a new source standard is the
applicability date only if the standard is
promulgated within 120 days of proposal
(section 306(a)(2), (b)(l)(B)).
Sierra Pacific suggests that utilities
are "unfairly prejudiced" by the
applicability date, but does not submit
any information to support this claim. In
any event, there does not seem to be
"In any event, in the Administrator's view the 90-
day requirement in section lll(b)(l)(B) no longer
governs the promulgation or revision of new source
slanddrds. It has been replaced by procedures set
forth in section lll(f) enacted by the 1977
amendments.
IV-385
any substantial unfair prejudice. At the
time of proposal, the Administrator had
not decided whether a full or partial
control alternative should be adopted in
the final SOa standard. As a result, the
Administrator proposed the full control
alternative stating (43 FR 42154, center
column):
* * * the Clean Air Act provides that new
source performance standards apply from the
date they are proposed and it would be easier
for power plants that start construction
during the proposal period to scale down to
partial control than to scale up to full control
should the final standard differ from the
proposal.
In fact, the final SO8 standard was less
stringent than the proposed rule.
In this case, utilities were on notice on
September 19,1978, of the proposed
form of the standard, and that the
standard would apply to facilities
constructed after that date. In March
1979, it became clear to the Agency that
it would not be possible to respond to
all the public comments and promulgate
the final standards by March 19, as
required by the consent decree in Sierra
Club v. Costle, a suit brought to compel
promulgation of the standard. {The
comment period had only closed on
January 15; EPA had received over 625
comment letters, totalling about 6,000
pages, and the record amounted to over
21,000 pages.) The Agency promptly
contacted the other parties to Sierra
Club v. Costle, and all the parties jointly
filed a stipulation that the standand
should be signed by June 1 and that the
Administrator should not seek "any
further extensions of time." This
stipulation was well-publicized (see, for
example, 9 Environment Reporter
Current Developments 2246, March 30,
1979). Thus utilities such as Sierra
Pacific had reasonable assurance that
the standard would be signed by June 1,
as it was.
Even assuming, as Sierra Pacific does,
that section 111 required the standard to
be promulgated by March 19, utilities
had to wait only an additional period of
84 days to know the precise form of the
promulgated standard. This delay is not
substantial in light of the long lead times
required to build a utility boiler, and in
light of the fact that the pollution control
techniques required to comply with the
promulgated standard are substantially
the same as those required by the
proposed standard.
Sierra Pacific's proposal that the
applicability date be shifted to the date
of promulgation is also inconsistent with
Congress' clear desire that the revised
standard take effect promptly. See
section lll(b)(6).
In conclusion, Sierra Pacific has
submitted no new information, has not
shown that it has been prejudiced in any
way, and has simply presented an
argument that is incorrect as a matter of
law. Its objection is therefore not of
central relevance and its petition is
denied.
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Federal Register / Vol. 45. No. 67 / Friday, April 4,1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40CFRPart60
[FRL1370-5]
Standards of Performance for New
Stationary Sources; Petroleum Liquid
Storage Vessels
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This regulation establishes
equipment standards which limit
emissions of volatile organic compounds
(VOC) from new, modified or
reconstructed petroleum liquid storage
vessels. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from petroleum liquid storage
vessels contribute significantly to air
pollution. The intended effect of this
regulation is to require new, modified or
reconstructed petroleum liquid storage
vessels to use the best demonstrated
system of continuous emission reduction
considering costs and nonair quality
health, environmental and energy
impacts.
EFFECTIVE DATE: April 4,1980.
ADDRESSES: Docket No. OAQPS-78-2.
containing all supporting information
used by EPA in developing the
standards, is available for public
inspection and copying between 8 a.m.
and 4 p.m., Monday through Friday, at
EPA's Central Docket Section, Room
2903B, Waterside Mall, 401 M Street,
SW., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Divison
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. telephone no. (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
The Standards
The standards promulgated under
Subpart Ka require each new, modified
or reconstructed petroleum liquid
storage vessel of greater than 151,416
liters (40,000 gallons) capacity
containing a petroleum liquid with a true
vapor pressure greater than 10.3 kPa (1.5
psia) to be equipped with one of the
following:
1. An external floating roof fitted with
a double seal system between the tank
wall and the floating roof;
2. A fixed roof with an internal-
floating cover equipped with a seal
between the tank wall and the edge of
the coven
3. A vapor recovery and disposal or
return system which reduces VOC
emissions by at least 95 percent, by
weight; or
4. Any system which is demonstrated
to the Administrator to be equivalent to
those described above.
Each affected vessel storing a
petroleum liquid with a true vapor
pressure greater than 76.6 kPa (11.1 psia)
must be equipped with a vapor recovery
and disposal or return system, or
equivalent. Storage vessels of less than
1,589,800 liters (420,000 gallons) capacity
used for petroleum or condensate stored
prior to custody transfer are exempt
from the standards.
Many of the petroleum liquid storage
vessels covered by the standards are
likely to be in locations other than
petroleum refineries. If the storage
vessel contains petroleum or
condensate, or finished or intermediate
products manufactured at a petroleum
refinery, and the size and true vapor
pressure applicability criteria are met,
the vessel would be covered by the
standards regardless of its location. For
example, cyclohexane may be produced
at a petroleum refinery and then stored
at a chemical plant before being used in
the plant. The storage vessel at the
chemical plant would be covered by the
standards if its size and the true vapor
pressure of the cyclohexane are greater
than the cut-offs in the standards.
The regulation contains allowable
seal gap criteria based on gap surface
area per unit of storage vessel diameter.
The standards require owners or
operators to measure and report seal
gaps annually for the secondary seal
and every five years for the primary seal
for each affected storage vessel. The
standards also require owners or
operators to monitor and maintain
records of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of the petroleum
liquid during its storage period for each
affected storage vessel.
Several definitions and the monitoring
and record keeping requirements of
Subpart K have been revised to make
them consistent with those in Subpart
Ka. These revisions to Subpart K clarify
the regulation and make it less
burdensome for owners and operators
but do not affect the emission reductions
required by Subpart K.
The promulgated standards are in
terms of equipment specifications and
maintenance requirements rather than
mass emission rates. It is extremely
difficult to quantify mass emission rates
for petroleum liquid storage vessels
because of the varying loss mechanisms
and the number of variables affecting
loss rate. Section lll(h)(l) of the Act
provides that equipment standards may
be established for a source category if it
is not feasible to prescribe or enforce a
standard which specifies an emission
limitation.
Environmental and Economic Impact
Compliance with these standards will
reduce VOC emissions to the
atmosphere from petroleum liquid
storage vessels with external floating
roofs by about 75 percent. This estimate
is based on a comparison of VOC
emissions between storage vessels
equipped with external floating roofs
and single seals and storage vessels
equipped with any of the systems
required in the standards. The standards
will reduce VOC emissions by about
4,545 megagrams per year (5000 tons per
year) by 1985.
This emission reduction will be
realized without adverse impacts on
other aspects of environmental quality,
such as solid waste disposal, water
pollution, or noise. There will be no
adverse energy impacts associated with
the standards. In fact, energy savings
will result because the standards will
help prevent the loss of valuable
petroleum products. The economic
impact, of the standards is considered
reasonable. The cost of complying with
the standards will be only the
incremental cost of installing a
secondary seal. This will increase the
cost of a new 81-meter diameter storage
vessel, by about 0.6 to 1.3 percent. The
incremental capital costs will be about
$12,000 to $19,000, and the average
incremental annualized costs will vary
between $1,100 and $3,300 per storage
vessel depending on the true vapor
pressure of the petroleum liquid, the
average wind velocity, and the cost of
the petroleum liquid.
Public Participation
The Standards were proposed in the
Federal Register on May 18,1978 (43 FR
21615), To provide interested persons
the opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards, a public hearing
was held on June 7,1978, in Washington,
D.C. In addition, during the public
comment period from May 18,1978, to
July 19,1978, a total of 35 comment
letters was received. These comments
have been carefully considered and,
where determined to be appropriate,
changes have been made in the final
regulation.
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Significant Comments and Changes
Made
Comments were received from
industry representatives, utility
companies, and State and Federal
agencies. Most of the comment letters
contained multiple comments. The
comments have been divided into the
following areas for discussion: testing
and monitoring, technology, impacts,
and general.
Testing and Monitoring
Most of the comments concerned the
proposed requirements for inspecting
the seals on external floating roof
storage vessels. The proposed standards
required that inspection of the seals be
performed while the roof was floating.
They also required, however, that the
secondary seal be kept in place at all
times if the storage vessel contained a
petroleum liquid with true vapor
pressure greater than 10.3 kPa (1.5 psia).
This meant that if the secondary seal
would have to be dislodged or removed
to inspect the primary seal, the vessel
would have to be empted of petroleum
liquid and the roof raised with some
other liquid. The preamble suggested
using water to do this. Commenters
pointed out that the use of a liquid other
than a petroleum liquid would put the
storage vessel out of service for an
indefinite period, that water was
unavailable in many areas, and that
water, if used, would become
contaminated with petroleum liquids
which would have to be separated prior
to discharge.
EPA has determined that these
comments are valid and that the VOC
emissions occurring during the relatively
short inspection period would be
insignificant when compared to the
impact of using water as the test fluid.
Therefore, the final regulation allows the
removal of the secondary seal for the
inspection of the primary seal while the
storage vessel is in operation. Higher
emissions will, however, result from the
removal of the secondary seal. To
reduce this period of increased
emissions, the final standards require
inspection of the primary seal to be
performed as rapidly as possible and the
secondary seal replaced as soon as
possible.
Many commenters stated that seal gap
measurement at one level would provide
sufficient indication of seal integrity and
that the proposed requirement for
measuring at eight levels would be too
burdensome, expensive, and would
provide little, if any, additional
information. Most of these commenters
recommended measuring seal gaps at
the "as found" level. It is not clear
whether the benefits of the eight-level
gap measurement would outweigh the
adverse impacts. In addition, since the
final standards allow removal of the
secondary seal during measurement and
inspection of the primary seal, it is
important to minimize the amount of
time the secondary seal is not in place.
Reducing the number of required
measurement levels thus will help to
minimize the VOC emissions during
primary seal gap measurements.
Therefore; the final regulation requires
that seal gaps be measured at one level
with the stipulation that the roof be
floating off the roof leg supports. The
owner or operator is required to notify
EPA prior to gap measurement and
provide all of the results of such
measurements to EPA each time they
are performed
The proposed seal gap measurement
frequency of five years was criticized by
many commenters. Some claimed this to
be too frequent while two commenters
suggested performing gap measurements
during scheduled storage vessel
maintenance periods. Requiring seal gap
measurements only during scheduled
maintenance would not provide uniform
impacts on owners and operators. Those
with more frequent maintenance periods
would be required to measure seal gaps
more often than those with less frequent
maintenance periods. Therefore the
same measurement frequency is
required of all owners and operators
regardless of their maintenance
schedules. The promulgated standards
require a different frequency, however,
for the primary seal than for the
secondary seal. Data derived from tests
conducted by Chicago Bridge and Iron
Company (CBI) on a 20-foot diameter
test storage vessel clearly indicate that
secondary seal gaps increase VOC
emissions to a greater degree than gaps
in the primary seal. Because of its
greater sensitivity, a more frequent
inspection of the secondary seal is
considered necessary. Consequently, the
final regulation requires the secondary
seal gaps to be measured at initial fill
and at least once annually and the
primary seal gaps at initial fill and at
least once every five years. The
requirement for more frequent gap
measurements for secondary seals is not
expected to increase the impact of the
final standards in comparison to the
proposed standards. In fact, the impact
will be less because gap measurements
are required at only one roof level
instead of the proposed eight levels, and
they may be conducted without taking
the storage vessel out of service. If a
storage vessel is out of service {i.e.,
empty) for more than one year, gap
measurements must be conducted upon
refilling. This is considered necessary to
ensure that the seal system integrity has
not severely deteriorated during the
period of inactivity. The final regulation
therefore, defines such refilling as
"initial fill" and the required frequency
of gap measurements would be based
upon the date of refilling.
One commenter suggested requiring
visual seal inspections instead of seal
gap measurements. This approach was
considered but rejected because of the
inability to develop a visual inspection
procedure which could be applied
uniformly. The subjectiveness of such a
procedure would preclude the use of the
data that would be obtained.
The gap criteria by size classes
specified in the proposed regulation
were unfair, claimed two commenters,
and are not consistent with the CBI
data. As pointed out by one commenter,
a three-sixteenths inch gap around the
entire storage vessel would produce less
gap surface area than the proposed
standards allowed yet would be out of
compliance with the proposed gap
criteria. To eliminate this possibility, the
final regulation specifies total gap
surface area criteria specific to the
storage vessel diameter for the primary
and the secondary seal. Since the seal
gap surface area allowed in the final
standards is approximately equal to that
allowed in the proposed standards,
about the same VOC emission reduction
and cost of performing gap
measurements will result. The final
standards, however, will provide a more
effective and uniform procedure for
ensuring that seals are properly
installed and maintained.
Two commenters questioned the
apparently inflexible requirement in the
proposal Aat only pre-sized probes
were to be used for gap measurements.
As pointed out by one commenter, use
of an L-shaped probe, in some cases,
could eliminate the need to remove the
secondary seal when measuring gaps in
the primary seal. The secondary seal, in
many cases, could merely be pulled
back and the L-shaped probe inserted
for accurate gap determinations. Such
an approach may be reasonable, and
there may be other suitable methods for
measuring gaps. Therefore, the
regulation specifies one method of gap
measurement but includes provisions for
allowing other methods provided they
can be demonstrated to be equivalent.
According to four commenters, the
monitoring requirements specified in the
proposed rule were too burdensome and
were probably of little value. They also
pointed out problems with Reid vapor
pressure conversions and true vapor
pressure determinations in some cases.
TT7_ "> O -7
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Federal Register / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
EPA agreed with this comment and has
re-evaluated the amount of monitoring
information needed to be able to ensure
that owners or operators of storage
vessels covered by the regulation are
complying with the standards. As a
result, the final regulation has been
revised to require that a record be kept
of the maximum true vapor pressure and
the periods of storage of each vessel's
contents. This maximum true vapor
pressure can be determined from
available data on the typical Reid vapor
pressure and the maximum expected
storage temperature. This precludes the
proposed requirement that an average
temperature record be kept. For any
crude oil with a true vapor pressure less
than 13.8 kPa (2.0 psia) or whose
physical properties preclude
determination by the recommended
methods, the true vapor pressure is to be
determined from available data and
recorded if the estimated true vapor
pressure is greater than 6.9 kPa (1.0
psia). The final regulation allows two
exemptions from the monitoring
requirements: (1) If the petroleum liquid
has a Reid vapor pressure less than 6.9
kPa (1.0 psia) and the true vapor
pressure will never exceed 6.9 kPa (1.0
psia) or (2) if the storage vessel is
equipped with a vapor return or disposal
system in accordance with the
requirements of the standard This
revision relieves much of the record
keeping and monitoring burden of the
proposed regulation but is not expected
to impact the amount of VOC emissions.
Two letters commented on the
requirement in the proposed standard
that there be four access points through
the secondary seal to the primary seal to
allow inspection while the storage
vessel is in operation. One commenter
said it was unnecessary while the other
commenter stated that the access points
should be chosen at random by the
inspector. Since the regulation has been
revised to allow removal of the
secondary seal for primary seal
inspections and gap measurements
while the vessel is in operation,
requiring the owner or operator to
provide four access points to the
primary seal is not necessary. Therefore,
this requirement has been deleted.
Technology
Seven commenters questioned the
validity of scaling up the CBI test vessel
data by linear extrapolation to Held size
storage vessels as was done to calculate
actual emission reductions. Many of
these commenters also believed that the
static test conditions were not
representative of dynamic field
conditions. These commenters
recommended awaiting results of the
American Petroleum Institute (API)
study of VOC emissions from petroleum
liquid storage vessels in actual field
conditions. Preliminary results of the
API study have been released, however,
and indicate that VOC emissions from
field storage vessels are directly
proportional to vessel diameter.
Therefore, the VOC emission estimates
based on CBI data are considered valid.
Four commenters stated that storage
vessels could not meet seal gap
specifications even if they met current
plumbness and roundness specifications
contained in API Standard 650 which is
used for construction standards for new
storage vessels. The out-of-plumbness
specification in API Standard 650 allows
V* percent of the height of the vessel and
the roundness specification is grouped
by vessel diameter as follows:
Storage Ve»Ml Diameter and Radius Tolerance
Inches
0 to 40 feet exclusive _,
40 to 1 SO feet exclusive..
150 to 250 leel exclusive..,
250 feet and over
±V4
±%
±1
Some of these commenters felt that
the construction tolerances would have
to be reduced considerably for primary
and secondary seals to maintain
compliance with the gap criteria at all
roof levels, thereby effecting a
significant economic impact of increased
construction costs which EPA failed to
consider. However, a compilation by
EPA of the California Air Resources
Board (GARB) petroleum liquid storage
vessel inspection reports showed that a
majority of existing welded vessels
inspected in California would have been
in compliance with the seal gap criteria
in both the proposed and final
regulations had these regulations been
in effect. Since the majority of those
tanks were found to be in compliance
with the seal gap standards, it is EPA's
judgement that all new petroleum liquid
storage vessel seals could meet the gap
standards. Therefore, EPA believes the
standards are attainable under present
construction standards.
In the proposed regulation, the
requirement that a vapor recovery and
return or disposal system be capable of
collecting and preventing the release of
all VOC vapors implied 100 percent
control efficiency, and four commenters
stated that this was impossible to
achieve. EPA did not intend to
necessarily require 100 percent control
but rather to require that the system be
properly designed, installed, and
operated. There are two parts to a vapor
recovery and return or disposal system.
The vapor recovery portion collects the
VOC vapors and gases from the storage
vessel and vents them to a control
device which then processes them by
either recovering them as product or
disposing of them. A properly designed
collection system would be capable of
collecting all the VOC vapors and gases
except when pressure relief vents on the
storage vessel roof would open and
release VOC emissions to the
atmosphere. The only time these vents
would open is during periods when the
emission control system is not operating
properly and VOC vapors are not being
vented to the control device, causing a
pressure buildup in the storage vessel.
Such an occurrence would be
considered a malfunction if it could not
be avoided through proper operation
and maintenance and, therefore, would
not cause the storage vessel to be out of
compliance with the standard.
Therefore, EPA considers the
requirement that the system "collect all
the vapors and gases discharged from
the storage vessel" to be achievable and
reasonable and has retained it hi the
final regulation. EPA agrees with the
commenters that the second part of the
system, the return or disposal portion, is
not likely to be able to achieve 100
percent control efficiency. It is generally
acknowledged, however, that greater
than 95 percent VOC emission reduction
can be achieved by at least two
commonly used types of vapor control
devices, thermal oxidation and carbon
adsorption. Therefore, the final
regulation requires that any vapor
recovery and return or disposal system
used to comply with the standard must
collect all the VOC vapors and gases
discharged from the storage vessel and
be capable of processing them so as to
reduce their emission to the atmosphere
by at least 95 percent by weight.
To enable EPA to determine
compliance with the requirements for
vapor recovery and return or disposal
systems, the regulation requires the
owner or operator to submit plans and
specifications for the system to EPA on
or before the date on which construction
of the storage vessel is commenced.
Owners and operators are encouraged
to provide this information as far in
advance as possible of commencing
construction.
One commenter suggested that the
section on "Equivalent Equipment" be
expanded to include the use of
innovative vapor control equipment
other than the three types specified in
the proposed standards. To encourage
innovation, an equivalency clause is
provided in the final regulation that
applies to all parts of the standards
provided no decrease in emission
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reduction will result and can be so
demonstrated. Determinations of
equivalency for VOC emission reduction
systems not specifically mentioned in
the regulation will generally be made by
comparing the VOC emissions from such
a source to the VOC emissions
calculated for an external floating roof
welded storage vessel with secondary
and primary seals according to
equations in API Bulletin 2517.
"Evaporation Loss from External
Floating Roof Tanks." February 1980.
There will probably be cases in which
determinations of equivalency cannot be
made through a strict comparison of
emission reduction, and these will be
based on sound engineering judgment
Therefore, the regulation requires that
any request for an equivalency
determination be accompanied by VOC
emission reduction data, if available,
and also by detailed equipment and
procedural specifications which would
enable a sound engineering judgment to
be made. In accordance with section
lll(h)(3) of the Clean Air Act. any
equivalency determination shall be
preceded by a notice in the Federal
Register and an opportunity for a public
hearing.
Non-metallic, resilient primary seals
were considered by four commenters to
be equivalent to metallic shoe seals. A
revaluation of available data, some of
which were received after issuance of
the proposed regulation, indicates that
various types of seals may provide
essentially the same degree of emission
reduction. The final regulation,
therefore, allows use of liquid-mounted,
foam-filled seals; liquid-mounted, liquid-
filled seals; or vapor-mounted, foam-
filled seals in addition to metallic shoe
seals as primary seals on external
floating roofs. Vapor-mounted seals,
however, are equivalent to the others
only when the gap area of vapor-
mounted seals is significantly less than
the gap area of the others. Therefore, the
final regulation requires more stringent
gap criteria for vapor-mounted primary
seals.
Several commenters recommended
exemption from the standards for
storage vessels involved in oil field and
production operations. Such vessels are
generally small, bolted, and equipped
with fixed roofs. This is to enable them
to be dismantled, transported and
reerected as needed. Therefore, to
comply with the standards, a new
production field vessel would have to be
equipped with either an internal floating
roof or a vapor recovery system.
Commenters provided information
which indicated that vapor recovery
would be very difficult and expensive
due to the remote location of many
vessels. One commenter also submitted
data to show that internal floating roofs
would generally not be cost-effective for
production vessels with capacities less
than 1,589,873 liters (420,000 gallons).
Therefore, the final regulation exempts
each storage vessel with a capacity of
less than 1,589,873 liters (420,000
gallons) used for petroleum or
condensate stored, processed, or treated
prior to custody transfer. This
exemption applies to storage between
the time that the petroleum liquid is
removed from the ground and the time
that custody of the petroleum liquid is
transferred from the well or producing
operations to the transportation
operations. If it is determined in the
future that VOC emissions from new
production field vessels smaller than
1,589,873 liters (420,000 gallons) are
significant, separate standards of
performance will be developed.
One commenter indicated that
internal non-contact floating roofs do
not reduce emissions to the same degree
as contact floating roofs and points out
that API Standard 650 recommends the
use of the contact type. EPA is
concerned about the difference in
emission control of these two types of
floating roofs although insufficient data
exist at present to justify a revision to
the standards for petroleum liquid
storage vessels. One type of non-contact
floating roof was tested at CBI and the
results were forwarded to EPA in late
1978. The results indicate that the roof
did not reduce emissions to the same
degree as a contact roof. However,
slight auxiliary equipment differences
such as different seals used with the
different roofs prohibit development of
valid conclusions. Therefore, more
information is necessary to determine if
the petroleum liquid storage vessels
standard should be revised.
Consequently, EPA is considering a
study specifically to determine
differences in VOC emission control of
these two types of internal floating
roofs.
Impacts
The proposed regulation specified that
the roof must be floating on the liquid at
all times except when the storage vessel
is completely emptied, during initial fill,
or performance tests. Three commenters
stated that the level of the liquid should
be allowed to go below the level where
the roof comes to rest on the roof leg
supports even if the vessel is not
completely emptied. This would avoid
the loss of working-capacity and, thus,
the need for more storage vessels. A
significant amount of VOC emissions,
however, would result upon refilling.
The intent of the regulation is to avoid
having a vapor space between the roof
and the petroleum liquid surface for
extended periods. The quantity of
petroleum liquid remaining in the
bottom of a storage vessel with the
floating roof on its leg supports asd the
time it remains in this condition
determines the amount of VOC
saturation of the vapor space and the
subsequent emissions upon refilling th»
storage vessel. It is therefore considered
beneficial to the environment for the
roof to be kept floating at all times
except when the tank is initially filled or
completely emptied and refilled for such
purposes as routine tank maintenance,
inspections, petroleum liquid deliveries,
or transfer operations. Therefore, the
final regulation requires that the roof be
floating on the liquid at all times except
during initial fill and when the vessel is
completely emptied and refilled. To
minimize the amount of time the
petroleum liquid remains in the storage
vessel while the roof is resting on the
roof leg supports, the final regulation
also requires that the process of
emptying and refilling be performed as
rapidly as possible.
As mentioned before, the proposed
regulation did not require the roof to be
floating on the petroleum liquid during
performance tests. This exemption was
needed since the proposal required that
gap measurements be conducted with a
liquid other than a petroleum liquid in
the storage vessel (the preamble
suggested using water). Therefore, the
storage vessel would have had to be
emptied and the roof re-floated on the
non-petroleum liquid. Since the final
regulation allows gap measurements to
be conducted while the vessel contains
petroleum liquid, this exemption has
been removed.
General
It was pointed out by two commenters
that because the proposed regulation
stated that a secondary seal gap would
exist only if the probe touched the
primary seal, gaps in the same location
in the primary seal and the secondary
seal would not be allowed. The
proposed regulation stated that "a gap is
deemed to exist under the following
conditions: * * * for a secondary seal,
the probe is to touch the primary seal
without forcing." This erroneously
implied that a secondary seal gap would
not exist should the probe be able to
pass between the secondary and
primary seals and the tank wall and
touch the liquid surface. These
commenters concluded that EPA
intended to regulate not only the size
and area of seal gaps but also their
locations in each seal. This was not the
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intent of the proposed regulation. The
final regulation eliminates this
ambiguity and redefines "gaps" as those
places where a uniform one-eighth inch
diameter probe passes freely between
the seal and the tank wall
Two commenters stated that a person
walking on an external floating roof
could alter gap configuration and would
pose a safety hazard because the roof
could possibly sink. Three commenters
felt that a fire hazard would be created
by the vapor that would become trapped
between the primary and secondary
seals. These comments were expressed
as opinions without any supporting data
or information. Since no such incidents
have been reported to EPA, and since
external floating roofs with double seals
are commonly used and apparently
operating safely even during
inspections, it is EPA's judgement that
the standards will not create either of
these hazards. A person walking on an
external floating roof should not cause
significant gap alterations since these
roofs are designed and built for this
purpose. Any small gap alteration
should not affect compliance status of
seal gaps since the allowable gap
criteria are based on total surface area
of all gaps.
The term "hydrocarbon" has been
changed to "volatile organic compounds
(VOC)" in the final regulation. This
change in terminology is consistent with
current EPA policy concerning
compounds which react
photochemically in the atmosphere to
form ozone. Reference has been made in
the past to "organic solvents,"
"thinners," and "hydrocarbons," in
addition to "VOC" to represent these
compounds. Some organics which are
ozone precursors are not hydrocarbons
in the strictest definition and are not
always used as solvents. Therefore, all
reference to emissions and emission
reduction in the standards refer to the
organic compounds which are ozone
precursors and have been designated
VOC.
Docket
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
the Administrator in the development of
this rulemaking. The docketing system is
intended to allow members of the public
and industries involved to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process.
Along with the statement of basis and
purpose of the promulgated rule and
EPA responses to significant comments,
the contents of the docket will serve as
the record in case of judicial review.
Miscellaneous
The effective date of this regulation is
April 4.1980. Section 111 of the Clean
Air Act provides that standards of
performance become effective upon
promulgation and apply to affected
facilities, construction or modification of
which was commenced after the date of
proposal (May 18,1978).
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods.
enforceability, and improvements in
emission control technology.
It should be noted that standards of
performance for new stationary sources
established under section 111 of the
Clean Air Act reflect
* * * Application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any non
air quality health and environmental impact
and energy requirements) the Administrator
determines has been adequately
demonstrated (section lll(a)(l)).
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requries (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources locating in
nonattainment areas, i.e., those areas
where statutorily-mandated health and
welfare standards are being violated. In
this respect, section 173 of the Act
requires that a new or modified source
constructed in an area which exceeds
the National Ambient Air Quality
Standard (NAAQS) must reduce
emissions to the level which reflects the
"lowest achievable emission rate"
(LAER), as defined in section 171(3), for
such category of source. The statute
defines LAER as that rate of emissions
based on the following, whichever is
more stringent:
(A) 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
(B) The most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate
exceed any applicable new source
performance standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act Best available
control technology must be determined
on a case-by-case basis, taking energy,
environmental and economic impacts,
and other costs into account. In no event
may lie application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all events. State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free .under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for
revisions of standards of performance
which the Administrator determines to
be substantial. An economic impact
assessment has been prepared and is
included in the docket All the
information in the economic impact
assessment was considered in
determining the cost of these standards.
Dated: March 28.1980.
Douglas M Cootie,
A dminis trator.
40 CFR Part 60 is amended by revising
§ 60.11(a); the heading of Subpart K;
§ 60.110(c)(l) and (c)(2); § 60.111(b) and
(c); the heading of 5 60.112; § 60.113; and
by adding a new Subpart Ka as follows:
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Federal Register / Vol. 45, No. 67 / Friday, April 4. 1980 / Rules and Regulations
1. Paragraph [a] of § 60.11 is revised to
read as follows:
§ 60.11 Compliance with standards and
maintenance requirements.
(a) Compliance with standards in this
part, other than opacity standards, shall
be determined only by performance
tests established by § 60.8, unless
otherwise specified in the applicable
standard.
*****
2. The heading for subpart K is revised
to read as follows:
Subpart K—Standards of Performance
for Storage Vessels for Petroleum
Liquids Constructed After June 11,
1973 and Prior to May 19,1978
3. Paragraphs (c)(l) and (c)(2) of
§ 60.110 of Subpart K are revised to read
as follows:
§ 60.110 Applicability and designation of
affected facility.
*****
(c) * * *
(1) Has a capacity greater than 151,
416 liters (40,000 gallons), but not
exceeding 246,052 liters (65,000 gallons),
and commences construction or
modification after March 8,1974, and
prior to May 19,1978.
(2) Has a capacity greater than 246,052
liters (65,000 gallons) and commences
construction or modification after June
11,1973, and prior to May 19,1978.
*****
4. Paragraphs (b) and (c) of § 60.111 of
Subpart K are revised to read as
follows:
§60.111 Definitions.
*****
(b) "Petroleum liquids" means
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean Nos. 2 through 6 fuel oils as
specified in ASTM-D-396-78, gas
turbine fuel oils Nos. 2-GT through 4-
GT as specified in ASTM-D-2880-78, or
diesel fuel oils Nos. 2-D and 4-D as
specified in ASTM-D-97578.
(c) "Petroleum refinery" means each
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking,
extracting, or reforming of unfinished
petroleum derivatives.
*****
5. The heading of § 60.112 of Subpart
K is revised to read as follows:
S 60.112 Standard for volatile organic
compounds (VOC).
6. Section 60.113 of Subpart K is
revised to read as follows:
§ 60.113 Monitoring of operations.
(a) Except as provided in paragraph
(d) of this section, the owner or operator
subject to this subpart shall maintain a
record of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of that liquid during
the respective storage period.
(b) Available data on the typical Reid
vapor pressure and the maximum
expected storage temperature of the
stored product may be used to
determine the maximum true vapor
pressure from nomographs contained in
API Bulletin 2517, unless the
Administrator specifically requests that
the liquid be sampled, the actual storage
temperature determined, and the Reid
vapor pressure determined from the
sample(s).
(c) The true vapor pressure of each
type of crude oil with a Reid vapor
pressure less than 13.8 kPa (2.0 psia) or
whose physical properties preclude
determination by the recommended
method is to be determined from
available data and recorded if the
estimated true vapor pressure is greater
than 6.9 kPa (1.0 psia).
(d) The following are exempt from the
requirements of this section:
(1) Each owner or operator of each
affected facility which stores petroleum
liquids with a Reid vapor pressure of
less than 6.9 kPa (1.0 psia) provided the
maximum true vapor pressure does not
exceed 6.9 kPa (1.0 psia).
(2) Each owner or operator of each
affected facility equipped with a vapor
recovery and return or disposal system
in accordance with the requirements of
S 60.112.
7. A new Subpart Ka is added to read
as follows:
Subpart Ka—Standards of Performance for
Storage vessels for Petroleum Liquids
Constructed After May 18,1978
Sec.
GO.llOa Applicability and designation of
affected facility.
60.1113 Definitions.
60.112a Standard for volatile organic
compounds (VOC).
60.113a Testing and procedures.
60.114a Equivalent equipment and
procedures.
60.115a Monitoring of operations.
Authority: Sec. Ill, 301 (a) of the Clean Air
Act as amended (42 U.S.C. 7411, 7601 (a)}, and
additional authority as noted below.
Subpart Ka—Standards of
Performance for Storage Vessels for
Petroleum Liquids Constructed After
May 18,1978
§ 60.110a Applicability and designation of
affected facility.
(a) Except as provided in paragraph
(b) of this section, the affected facility to
which this subpart applies is each
storage vessel for petroleum liquids
which has a storage capacity greater
than 151,416 liters (40,000 gallons) and
for which construction is commenced
after May 18,197&
(b) Each petroleum liquid storage
vessel with a capacity of less than
1,589,873 liters (420,000 gallons) used for
petroleum or condensate stored,
processed, or treated prior to custody
transfer is not an affected facility and,
therefore, is exempt from the
requirements of this subpart
§60.11 la Definitions.
In addition to the terms and their
definitions listed in the Act and Subpart
A of this part the following definitions
apply in this subpart:
(a) "Storage vessel" means each tank,
reservoir, or container used for the
storage of petroleum liquids, but does
not include:
(1) Pressure vessels which are
designed to operate in excess of 204.9
kPa (15 psig) without emissions to the
atmosphere except under emergency
conditions.
(2) Subsurface caverns or porous rock
reservoirs, or
(3) Underground tanks if the total
volume of petroleum liquids added to
and taken from a tank annually does not
exceed twice the volume of the tank.
(b) "Petroleum liquids" means
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean Nos. 2 through 6 fuel oils as '
specified in ASTM-D-396-78, gas
turbine fuel oils Nos. 2-GT through 4-
GT as specified in ASTM-D-2880-78, or
diesel fuel oils Nos. 2-D and 4-D as
specified in ASTM-D-975-78.
(c) "Petroleum refinery" means each
facility engaged hi producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking,
extracting, or reforming of unfinished
petroleum derivatives.
(d) "Petroleum" means the crude oil
removed from the earth and the oils
derived from tar sands, shale, and coal.
(e) "Condensate" means hydrocarbon
liquid separated from natural gas which
condenses due to changes in the
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Federal Register / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
temperature or pressure, or both, and
remains liquid at standard conditions.
(f) "True vapor pressure" means the
equilibrium partial pressure exerted by
a petroleum liquid such as determined in
accordance with methods described in
American Petroleum Institute Bulletin
2517, Evaporation Loss from Floating
Roof Tanks, 1962.
(g) "Reid vapor pressure" is the
absolute vapor pressure of volatile
crude oil and volatile non-viscous
petroleum liquids, except liquified
petroleum gases, as determined by
ASTM-D-323-58 (reapproved 1968).
(h) "Liquid-mounted seal" means a
foam or liquid-filled primary seal
mounted in contact with the liquid
between the tank wall and the floating
roof continuously around the
circumference of the tank.
(i) "Metallic shoe seal" includes but is
not limited to a metal sheet held
vertically against the tank wall by
springs or weighted levers and is
connected by braces to the floating roof.
A flexible coated fabric [envelope)
spans the annular space between the
metal sheet and the floating roof.
(j) "Vapor-mounted seal" means a
foam-filled primary seal mounted
continuously around the circumference
of the tank so there is an annular vapor
space underneath the seal. The annular
vapor space is bounded by the bottom of
the primary seal, the tank wall, the
liquid surface, and the floating roof.
(k) "Custody transfer" means the
transfer of produced petroleum and/or
condensate, after processing and/or
treating in the producing operations,
from storage tanks or automatic transfer
facilities to pipelines or any other forms
of transportation.
§ 60.112a Standard for volatile organic
compounds (VOC).
(a) The owner or operator of each
storage vessel to which this subpart
applies which contains a petroleum
liquid which, as stored, has a true vapor
pressure equal to or greater than 10.3
kPa (1.5 psia) but not greater than 76.6
kPa (11.1 psia) shall equip the storage
vessel with one of the following:
(1) An external floating roof,
consisting of a pontoon-type or double-
deck-type cover that rests on the surface
of the liquid contents and is equipped
with a closure device between the tank
wall and the roof edge. Except as
provided in paragraph (a)(l)(ii)(D) of
this section, the closure device is to
consist of two seals, one above the
other. The lower seal is referred to as
the primary seal and the upper seal is
referred to as the secondary seal. The
roof is to be floating on the liquid at all
times (i.e., off the roof leg supports)
except during initial fill and when the
tank is completely emptied and
subsequently refilled. The process of
emptying and refilling when the roof is
resting on the leg supports shall be
continuous and shall be accomplished
as rapidly as possible.
(i) The primary seal is to be either a
metallic shoe seal, a liquid-mounted
seal, or a vapor-mounted seal. Each seal
is to meet the following requirements:
(A) The accumulated area of gaps
between the tank wall and the metallic
shoe seal or the liquid-mounted seal
shall not exceed 212 cm* per meter of
tank diameter (10.0 in *per ft of tank
diameter) and the width of any portion
of any gap shall not exceed 3.81 cm (1%
in).
(B) The accumulated area of gaps
between the tank wall and the vapor-
mounted seal shall not exceed 21.2 cm*
per meter of tank diameter (1.0 in* per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm (% in).
(C) One end of the metallic shoe is to
extend into the stored liquid and the
other end is to extend a minimum
vertical distance of 61 cm (24 in) above
the stored liquid surface.
(D) There are to be no holes, tears, or
other openings in the shoe, seal fabric,
or seal envelope.
(ii) The secondary seal is to meet the
following requirements:
(A) The secondary seal is to be
installed above the primary seal so that
it completely covers the space between
the roof edge and the tank wall except
as provided in paragraph (a)(l)(ii)(B) of
this section.
(B) The accumulated area of gaps
between the tank wall and the
secondary seal shall not exceed 21.2 cm*
per meter of tank diameter (1.0 in* per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm (V4 hi).
(C) There are to be no holes, tears or
other openings in the seal or seal fabric.
(D) The owner or operator is
exempted from the requirements for
secondary seals and the secondary seal
gap criteria when performing gap
measurements or inspections of the
primary seal.
(iii) Each opening in the roof except
for automatic bleeder vents and rim
space vents is to provide a projection
below the liquid surface. Each opening
in the roof except for automatic bleeder
vents, rim space vents and leg sleeves is
to be equipped with a cover, seal or lid
which is to be maintained in a closed
position at all times (i.e., no visible gap)
except when the device is in actual use
or as described in pargraph (a)(l)(iv) of
this section. Automatic bleeder vents
are to be closed at all times when the
roof is floating, except when the roof is
being floated off or is being landed on
the roof leg supports. Rim vents are to
be set to open when the roof is being
floated off the roof legs supports or at
the manufacturer's recommended
setting.
(iv) Each emergency roof drain is to
be provided with a slotted membrane
fabric cover that covers at least 90
percent of the area of the opening.
(2) A fixed roof with an internal
floating type cover equipped with a
continuous closure device between the
tank wall and the cover edge.'The cover
is to be floating at all times, [i.e., off the
leg supports) except during initial fill
and when the tank is completely
emptied and subsequently refilled. The
process of emptying and refilling when
the cover is resting on the leg supports
shall be continuous and shall be
accomplished as rapidly as possible.
Each opening in the cover except for
automatic bleeder vents and the rim
space vents is to provide a projection
below the liquid surface. Each opening
in the cover except for automatic
bleeder vents, rim space vents, stub
drains and leg sleeves is to be equipped
with a cover, seal, or lid which is to be
maintained in a closed position at all
times (i.e., no visible gap) except when
the device is in actual use. Automatic
bleeder vents are to be closed at all
times when the cover is floating except
when the covtsr is being floated off or is
being landed on the leg supports. Rim
vents are to be set to open only when
the cover is being floated off the leg
supports or at the manufacturer's
recommended setting.
(3) A vapor recovery system which
collects all VOC vapors and gases
discharged from the storage vessel, and
a vapor return or disposal system which
is designed to process such VOC vapors
and gases so as to reduce their emission
to the atmosphere by at least 95 percent
by weight.
(4) A system equivalent to those
described in paragraphs (a)(l), (a)(2), or
(a)(3) of this section as provided in
{ 60.114a.
(b) The owner or operator of each
storage vessel to which this subpart
applies which contains a petroleum
liquid which, as stored, has a true vapor
pressure greater than 76.6 kPa (11.1
psia), shall equip the storage vessel with
a vapor recovery system which collects
all VOC vapors and gases discharged
from the storage vessel, and a vapor
return or disposal system which is
designed to process such VOC vapors
and gases so as to reduce their emission
to the atmosphere by at least 95 percent
by weight.
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Federal Register / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
§ 60.113a Testing and procedures.
(a) Except as provided in § 60.8(b)
compliance with the standard
prescribed in § 60.112a shall be
determined as follows or in accordance
with an equivalent procedure as
provided in § 60.114a.
(1) The owner or operator of each
storage vessel to which this subpart
applies which has an external floating
roof shall meet the following
requirements:
(i) Determine the gap areas and
maximum gap widths between the
primary seal and the tank wall, and the
secondary seal and the tank wall
according to the following frequency
and furnish the Administrator with a
written report of the results within 60
days of performance of gap
measurements:
(A) For primary seals, gap
measurements shall be performed within
60 days of the initial fill with petroleum
liquid and at least once every five years
thereafter. All primary seal inspections
or gap measurements which require the
removal or dislodging of the secondary
seal shall be accomplished as rapidly as
possible and the secondary seal shall be
replaced as soon as possible.
(B) For secondary seals, gap
measurements shall be performed within
60 days of the initial fill with petroleum
liquid and at least once every year
thereafter.
(C) If any storage vessel is out of
service for a period of one year or more,
subsequent refilling with petroleum
liquid shall be considered initial fill for
the purposes of paragraphs (a)(l)(i)(A)
and (a)(l)(i)((B) of this section.
(ii) Determine gap widths in the
primary and secondary seals
individually by the following
procedures:
(A) Measure seal gaps, if any, at one
or more floating roof levels when the
roof is floating off the roof leg supports.
(B) Measure seal gaps around the
entire circumference of the tank in each
place where a Vs" diameter uniform
probe passes freely (without forcing or
binding against seal) between the seal
and the tank wall and measure the
circumferential distance of each such
location.
(C) The total surface area of each gap
described in paragraph (a)(l)(ii)(B) of
this section shall be determined by using
probes of various widths to accurately
measure the actual distance from the
tank wall to the seal and multiplying
each such width by its respective
circumferential distance.
(iii) Add the gap surface area of each
gap location for the primary seal and the
secondary seal individually. Divide the
sum for each sea) by the nominal
diameter of the tank and compare each
ratio to the appropriate ratio in the
standard in § 60.112a(a)(l)(i) and
(iv) Provide the Administrator 30 days
prior notice of the gap measurement to
afford the Administrator the opportunity
to have an observer present.
(2) The owner or operator of each
storage vessel to which this subpart
applies which has a vapor recovery and
return or disposal system shall provide
the following information to the
Administrator on or before the date on
which construction of the storage vessel
commences:
(i) Emission data, if available, for a
similar vapor recovery and return or
disposal system used on the same type
of storage vessel, which can be used to
determine the efficiency of the system.
A complete description of the emission
measurement method used must be
included.
(ii) The manufacturer's design
specifications and estimated emission
reduction capability of the system.
(iii) The operation and maintenance
plan for the system.
(iv) Any other information which will
be useful to the Administrator in
evaluating the effectiveness of the
system in reducing VOC emissions.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
f 60. 11 4a Equivalent equipment and
procedures.
(a) Upon written application from an
owner or operator and after notice and
opportunity for public hearing, the
Administrator may approve the use of
equipment or procedures, or both, which
have been demonstrated to his
satisfaction to be equivalent in terms of
reduced VOC emissions to the
atmosphere to the degree prescribed for
compliance with a specific paragraph(s)
of this subpart.
(b) The owner or operator shall
provide the following information in the
application for determination of
equivalency:
(1) Emission data, if available, which
can be used to determine the
effectiveness of the equipment or
procedures in reducing VOC emissions
from the storage vessel. A complete
description of the emission
measurement method used must be
included.
(2) The manufacturer's design
specifications and estimated emission
reduction capability of the equipment.
(3) The operation and maintenance
plan for the equipment.
(4) Any other information which will
be useful to the Administrator in
evaluating the effectiveness of the
equipment or procedures in reducing
VOC emissions.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
§60.115a Monitoring of operations.
(a) Except as provided in paragraph
(d) of this section, the owner or operator
subject to this subpart shall maintain a
record of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of that liquid during
the respective storage period.
(b) Available data on the typical Reid
vapor pressure and the maximum
expected storage temperature of the
stored product may be used to
determine the maximum true vapor
pressure from nomographs contained in
API Bulletin 2517, unless the
Administrator specifically requests that
the liquid be sampled, the actual storage
temperature determined, and the Reid
vapor pressure determined from the
sample(s).
(c) The true vapor pressure of each
type of crude oil with a Reid vapor
pressure less than 13.8 kPa (2.0 psia) or
whose physical properties preclude
determination by the recommended
method is to be determined from
available data and recorded if the
estimated true vapor pressure is greater
than 6.9 kPa (1.0 psia).
(d) The following are exempt from the
requirements of this section:
(1) Each owner or operator of each
storage vessel storing a petroleum liquid
with a Reid vapor pressure of less than
6.9 kPa (1.0 psia) provided the maximum
true vapor pressure does not exceed 6-9
kPa (1.0 psia).
(2) Each owner or operator of each
storage vessel equipped with a vapor
recovery and return or disposal system
in accordance with the requirements of
§§ 60.112a(a)(3) and 60.112a(b).
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
[FR Doc. 80-10222 Filed 4-3-80: 8:45 «m]
BILLING CODE 6S60-01-M
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Federal Register / Vol. 45, No. 105 / Thursday, May 29, 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FBL-1493-1]
Standards of Performance of New
Stationary Sources: Adjustment of
Opacity Standard for Fossil Fuel Fired
Steam Generator
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: On April 1,1980, there was
published in the Federal Register (45 FR
21302) a notice of proposed rulemaking
setting forth a proposed EPA adjustment
of the capacity standard for Interstate
Power Company's Lansing Unit No. 4, in
Lansing, Iowa. The proposal was based
on Interstate's demonstration of the
conditions that entitle it to such an
adjustment under 40 CFR 60.11(e).
Interested persons were given thirty
days in which to submit comments on
the proposed rulemaking.
No written comments have been
received and the proposed adjustment is
approved without change and is set
forth below.
Effective Date: May 29,1980.,
FOR FURTHER INFORMATION CONTACT:
Henry Rompage, Enforcement Division,
EPA, Region VII, Area Code 816-374-
3171.
Signed at Washington, D.C., on May 22,
1980.
Douglas M. Costle,
Administrator.
In consideration of the foregoing, Part
60 of 40 CFR Chapter I is amended as
follows:
Subpart D—Standards of Performance
for Fossil Fuel-Fired Generators
§ 60.42 [Amended]
1. Section 60.42 is amended by adding
paragraph (b)(2):
*****
(b) * * *
(2) Interstate Power Company shall
not cause to be discharged into the
atmosphere from its Lansing Station
Unit No. 1 in Lansing, Iowa, any gases
which exhibit greater than 32% opacity,
except that a maximum of 39% opacity
shall be permitted for not more than six
minutes in any hour.
(Sec. 111.301(a), Clear Air Act as amended
(42 U.S.C. 7411, 7601)).
2. Section 60.45(g)(l) is amended by
adding Paragraph (ii) as follows:
f 60.45 Emission and fuel monitoring.
(g) * * *
(1) * * *
(i) * * *
(ii) For sources subject to the opacity
standard of § 60.42(b)(2), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 32 percent opacity,
except that one six-minute average per
hour of up to 39 percent opacity need
not be reported.
[FR Doc. 8O-1B409 Filed 5-28-80, 8 45 am)
BILLING CODE 656O-01-M
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Federal Register / Vol. 45, No. 121 / Friday, June 20,1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1458-4]
Standards of Performance for New
Stationary Sources; Revised
Reference Methods 13A and 13B
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule revises Appendix A,
Reference Methods 13A and 13B, the
detailed requirements used to measure
total fluoride emissions to determine
whether affected facilities at phosphate
fertilizer and primary aluminum plants
are in compliance with the standard of
performance. Since the methods were
originally promulgated on January 26,
1976, several revisions that would
clarify, correct, and improve the
methods have been evaluated. Adoption
of these revisions will make Methods
ISA and 13B more accurate and reliable.
EFFECTIVE DATE: June 20,1980.
FOR FURTHER INFORMATION CONTACT:
Mr. Roger T. Shigehara, Emission
Measurement Branch (MD-19), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-2237.
SUPPLEMENTARY INFORMATION: The
specific changes to Methods 13A and
13B are:
1. Aluminum and silicon dioxide are
no longer listed as interferences since
sample distillation eliminates this
problem. Grease on sample-exposed
surfaces, which may adsorb F, has been
added as a potential interference.
2. The heat source for the sample
distillation has been changed from a hot
plate to a bunsen burner.
3. The requirements for the sample
train filter when it is placed between the
probe and first impinger have been
changed to allow any filter that can
meet certain specifications. The filter (1)
must withstand prolonged exposure to
temperatures up to 135°C (275°F), (2)
have at least 95 percent collection
efficiency for 0.3 ftm dioctyl phthalate
smoke particles, and (3) have a low F
blank value.
4. A requirement to oven dry the
sodium fluoride before preparing the
standardizing solution has been added.
5. Additional details have been added
to clarify sample recovery procedures.
6. A requirement to collect and
analyze a sample blank has been added.
7. To prevent F carryover after
distillation of high concentration F
samples, a procedure to remove the
residual F has been added.
8. The definition of Vt has been
changed to make it clearer.
9. Method 13B requires additional
standardizing solutions for specific ion
electrodes which do not display a linear
response to low concentration F
samples.
PUBLIC COMMENTS: Upon proposal of the
amendments to the New Source
Performance Standard for Primary
Aluminum plants, a comment was
received on Methods 13A and 13B. The
comment noted that in some cases the
sampling train may be required to
collect sample continuously over a
period of 24 hours. Such a large sample
would exceed the capacity of the train's
silica gel to absorb the residual moisture
in the sample.
EPA agrees with this comment and
has modified Methods ISA and 13B to
eliminate this potential problem. These
changes are consistent with the changes
in Method 5 allowing the following
options: (1) alternative systems of
cooling the gas stream and measuring
the condensed moisture, (2) addition of
extra silica gel to the impinger train, or
(3) replacement of spent silica gel during
a sample run.
The Administrator finds that these
amendments are minor and technical,
and that they will have no effect on the
stringency of the affected NSPS's. Notice
and public procedure on these
amendments are therefore unnecessary.
(Sections 111, 114, and 301(a) of the Clean Air
Act as amended (42 U.S.C. 7411, 7414. and
7C01(a))
Dated: )une 16,1960.
Douglas M. Costle,
Administrator.
40 CFR Part 60 is amended by revising
Methods ISA and 13B of Appendix A to
read as follows:
Appendix A—Reference Test Methods
*****
Method 13A. Determination of Total Fluoride
Emissions From Stationary Sources; SPADNS
Zirconium Lake Method
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of fluoride (F) emissions
from sources as specified in the regulations. It
does not measure fluorocarbons, such as
freons.
1.2 Principle. Gaseous and paniculate F
are withdrawn isokmetically from the source
and collected in water and on a filter. The
total F is then determined by the SPADNS
Zirconium Lake colorimetric method.
2. Range and Sensitivity
The range of this method is 0 to 1.4 fig F/
ml. Sensitivity has not been determined.
3. Interferences
Large quantities of chloride will interfere
with the analysis, but this interference can be
prevented by adding silver sulfate into the
distillation flask (see Section 7.3.4). If
chloride ion is present, it may be easier to use
the Specific Ion Electrode Method (Method
13B). Grease on sample-exposed surfaces
may cause low F results due to adsorption.
4. Precision, Accuracy, and Stability
4.1 Precision. The following estimates
are based on a collaborative test done at a
primary aluminum smelter. In the test, six
laboratories each sampled the stack
simultaneously using two sampling trains for
a total of 12 samples per sampling run.
Fluoride concentrations encountered during
the test ranged from 0.1 to 1.4 mg F/ms. The
within-laboratory and between-laboratory
standard deviations, which include sampling
and analysis errors, were 0.044 mg F/m3 with
60 degrees of freedom and 0.064 mg F/m*
with five degrees of freedom, respectively.
4.2 Accuracy. The collaborative test did
not find any bias in the analytical method.
4.3 Stability. After the sample and
colorimetric reagent are mixed, the color
formed is stable for approximately 2 hours. A
3°C temperature difference between the
sample and standard solutions produces an
error of approximately 0.005 mg F/liter. To
avoid this error, the absorbances of the
sample and standard solutions must be
measured at the same temperature.
5. Apparatus
5.1 Sampling Train. A schematic of the
sampling train is shown in Figure 13A-1; it is
similar to the Method 5 train except the filter
position is interchangeable. The sampling
train consists of the following components:
5.1.1 Probe Nozzle, Pilot Tube,
Differential Pressure Gauge, Filter Heating
System, Metering System, Barometer, and
Gas Density Determination Equipment.
Same as Method 5, Sections 2.1.1, 2.1.3, 2.1.4,
2.1.6. 2.1.8, 2.1.9, and 2.1.10. When moisture
condensation is a problem, the filter heating
system is used.
5.1.2 Probe Liner. Borosilicate glass or
316 stainless steel. When the filter is located
immediately after the probe, the tester may
use a probe heating system to prevent filter
plugging resulting from moisture
condensation, but the tester shall not allow
the temperature in the probe to exceed
120±14°C (248±25°F).
5.1.3 Filter Holder. With positive seal
against leakage from the outside or around
the filter. If the filter is located between the
probe and first impinger, use borosilicate
glass or stainless steel with a 20-mesh
stainless steel screen filter support and a
silicone rubber gasket: do not use a glass frit
or a sintered metal filter support. If the filter
is located between the third and fourth
impingers, the tester may use borosilicate
glass with a glass frit filter support and a
silicone rubber gasket. The tester may also
use other materials of construction with
approval from the Administrator.
5.1.4 Impingers. Four impingers
connected as shown in Figure 13A-1 with
ground-glass (or equivalent), vacuum-tight
fittings. For the first, third, and fourth
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TEMPERATURE
SENSOR
/
STACK WALL
— ' PROBE
•-^ PITOTTUBE
i !
I OPTIONAL FILTER
HOLDER LOCATION
FILTER HOLDER
PROBE
REVERSE TYPE
PITOT TUBE
THERMOMETER
rS
C/1 ^ CHECK VALVE
VACUUM LINE
VACUUM GAUGE
AIR • TIGHT PUMP
DRY TEST METER
Figure 13A 1. Fluoride sampling train.
CONNECTING TUIE .
12 mm ID
§24/40
THERMOMETER
124/40
CONDENSER
SM-nil
ERLENMEYER
FLASK
Figure 13A-2. Fluoride distillation •pparatu*.
impingers. use the Greenburg-Smith design,
modified by replacing the tip with a 1.3-cm-
inside-diameter (Vfe in.) glass tube extending
to 1.3 cm (Vt in.) from the bottom of the flask.
For the second impinger, use a Greenburg-
Smith impinger with the standard tip. The
tester may use modifications (e.g., flexible
connections between the impingers or
materials other than glass), subject to the
approval of the Administrator. Place a
thermometer, capable of measuring
temperature to within 1°C (2°F), at the outlet
of the fourth impinger for monitoring
purposes.
5.2 Sample Recovery. The following
items are needed:
5.2.1 Probe-Liner and Probe-Nozzle
Brushes, Wash Bottles, Graduated Cylinder
and/or Balance, Plastic Storage Containers,
Rubber Policeman, Funnel. Same as Method
5, Sections 2.2.1 to 2.2.2 and 2.2.5 to 2.2.8,
respectively.
5.2.2 Sample Storage Container. Wide-
mouth, high-density-polyethylene bottles for
impinger water samples, 1-liter.
5.3 Analysis. The following equipment is
needed:
5.3.1 Distillation Apparatus. Glass
distillation apparatus assembled as shown in
Figure 13A-2.
5.3.2 Bunsen Burner.
5.3.3 Electric Muffle Furnace. Capable of
heating to 600°C.
5.3.4 Crucibles. Nickel, 75- to 100-ml.
5.3.5 Beakers. 500-ml and 1500-ml.
5.3.6 Volumetric Flasks. 50-ml.
5.3.7 Erlenmeyer Flasks.or Plastic Bottles.
500-ml.
5.3.8 Constant Temperature Bath.
Capable of maintaining a constant
temperature of ±1.0°C at room temperature
conditions.
5.3.9 Balance. 300-g capacity to measure
to ±0.5 g.
5.3.10 Spectrophotometer. Instrument
that measures absorbance at 570 nm and
provides at least a 1-cm light path.
5.3.11 Spectrophotometer Cells. 1-cm
pathlength.
ft Reagents
6.1 Sampling. Use ACS reagent-grade
chemicals or equivalent, unless otherwise
specified. The reagents used in sampling are
as follows:
6.1.1 Filters.
6.1.1.1 If the filter is located between the
third and fourth impingers, use a Whatman '
No 1 filter, or equivalent, sized to fit the filter
holder.
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6.1.1.2 If the filter is located between the
probe and first impinger, use any suitable
medium (e.g., paper organic membrane) that
conforms to the following specifications: (1)
The filter can withstand prolonged exposure
to temperatures up to 135°C (275°F). (2) The
filter has at least 95 percent collection
efficiency (<5 percent penetration) for 0.3 ftm
dioctyl phthalate smoke particles. Conduct
the filter efficiency test before the test series,
using ASTM Standard Method D 2986-71, or
use test data from the supplier's quality
control program. (3) The filter has a low F
blank value (<0.015 mg F/cm2of filter area).
Before the test series, determine the average
F blank value of at least three filters (from
the lot to be used for sampling) using the
applicable procedures described in Sections
7.3 and 7.4 of this method. In general, glass
fiber filters have high and/or variable F
blank values, and will not be acceptable for
use.
0.1.2 Water. Deionized distilled, to
conform to ASTM Specification D1193-74,
Type 3. If high concentrations of organic
matter are not expected to be present, the
analyst may delete the potassium
permanganate test for oxidizable organic
matter.
6.1.3 Silica Gel, Crushed Ice, and
Stopcock Grease. Same as Method 5,
Section 3.1.2, 3.1.4, and 3.1.5, respectively.
6.2 Sample Recovery. Water, from same
container as described in Section 6.1.2, is
needed for sample recovery.
6.3 Sample Preparation and Analysis.
The reagents needed for sample preparation
and analysis are as follows:
6.3.1 Calcium Oxide (CaO). Certified
grade containing 0.005 percent F or less.
6.3 2 Phenolphthalein Indicator.
Dissolve 0.1 g of phenolphthalein in a mixture
of 50 ml of 90 percent ethanol and 50 ml of
deionized distilled water.
8.3.3 Silver Sulfate (Ag^O,).
6.3.4 Sodium Hydroxide (NaOH).
Pellets.
6.3.5 Sulfuric Acid (H.SO.), Concentrated.
6.3 6 Sulfuric Acid, 25 percent (V/V).
Mix 1 part of concentrated HiSO. with 3
parts of deionized distilled water.
6.3.7 Filters. Whatman No. 541, or
equivalent.
6.3.8 Hydrochloric Acid (HC1),
Concentrated.
6.3.9 Water. From same container as
described in Section 6.1.2.
6 3.10 Fluoride Standard Solution, 0.01 mg
F/ml. Dry in an oven at 110'C for at least 2
hours. Dissolve 0.2210 g of NaF in 1 liter of
deionized distilled water. Dilute 100 ml of thii
solution to 1 liter with deionized distilled
water.
6.3.11 SPADNS Solution [4, 5 dihydroxy-3-
(p-sulfophenylazo)-2,7-naphthalene-disuifonic
acid trisodium salt). Dissolve 0.960 ± 0.010
g of SPADNS reagent in 500 ml deionized
distilled water. If stored in a well-sealed
bottle protected from the sunlight, this
solution is stable for at least 1 month.
6.3.12 Spectrophotometer Zero Reference
Solution. Prepare daily. Add 10 ml of
SPADNS solution (6.3.11) to 100 ml deionized
distilled water, and acidify with a solution
prepared by diluting 7 ml of concentrated HC1
to 10 ml with deionized distilled water.
6.3.13 SPADNS Mixed Reagent. Dissolve
0.135 ± 0.005 g of zirconyl chloride
octahydrate (ZrOCU 8H,O) in 25 ml of
deionized distilled water. Add 350 ml of
concentrated HC1, and dilute to 500 ml with
deionized distilled water. Mix equal volumes
of this solution and SPADNS solution to form
a single reagent. This reagent is stable for at
least 2 months.
7. Procedure
7.1 Sampling. Because of the complexity
of this method, testers should be trained and
experienced with the text procedures to
assure reliable results.
7.1.1 Pretest Preparation. Follow the
general procedure given in Method 5, Section
4.1.1, except the filter need not be weighed.
7.1.2 Preliminary Determinations.
Follow the general procedure given in
Method 5, Section 4.1.2., except the nozzle
size selected must maintain isokinetic
sampling rates below 28 liters/min (1.0 cfm).
7.1.3 Preparation of Collection Train.
Follow the general procedure given in
Method 5, Section 4.1.3, except for the
following variations:
Place 100 ml of deionized distilled water in
each of the first two impingerg, and leave the
third impinger empty. Transfer approximately
200 to 300 g of preweighed silica gel from its
container to the fourth impinger.
Assemble the train as shown in Figure
13A-1 with the filter between the third and
fourth impingers. Alternatively, if a 20-mesh
stainless steel screen is used for the filter
support, the tester may place the filter
between the probe and first impinger. The
tester may also use a filter heating system to
prevent moisture condensation, but shall not
allow the temperature around the filter holder
to exceed 120 ± 14°C (248 ± 25°F). Record
the filter location on the data sheet.
7.1.4 Leak-Check Procedures. Follow the
leak-check procedures given in Method 5,
Sections 4.1.4.1 (Pretest Leak-Check), 4.1.4.2
(Leak-Checks During the Sample Run), and
4.1.4.3 (Post-Test Leak-Check).
7.1.5 Fluoride Train Operation.. Follow
the general procedure given in Method 5,
Section 4.1.5, keeping the filter and probe
temperatures (if applicable) at 120 ± 14°C
(248 ± 25°F) and isokinetic sampling rates
below 28 liters/min (1.0 cfm). For each run.
record the data required on a data sheet such
as the one shown in-Method 5, Figure 5-2.
7.2 Sample Recovery. Begin proper
cleanup procedure as soon as the probe is
removed from the stack at the end of the
sampling period.
Allow the probe to cool. When it can be
safely handled, wipe off all external
particulate matter near the tip of the probe
nozzle and place a cap over it to keep from
losing part of the sample. Do not cap off the
probe tip tightly while the sampling train is
cooling down, because a vacuum would form
in the filter holder, thus drawing impinger
water backward.
Before moving the sample train to the
cleanup site, remove the probe from the
sample train, wipe off the sihcone grease, and
cap the open outlet of the probe. Be careful
not to lose any condensate, if present.
Remove the filter assembly, wipe off the
sihcone grease from the filter holder inlet,
and cap this inlet. Remove the umbilical cord
from the last impinger, and cap the impinger.
After wiping off the silicone grease, cap off
the filter holder outlet and any open impinger
inlets and outlets. The tester may use ground-
glass stoppers, plastic caps, or serum caps to
close these openings.
Transfer the probe and filter-impinger
assembly to an area that is clean and
protected from the wind so that the chances
of contaminating or losing the sample is
minimized.
Inspect the train before and during
disassembly, and note any abnormal
conditions. Treat the samples as follows:
7.2.1 Container No. 1 (Probe, Filter, and
Impinger Catches). Using a graduated
cylinder, measure to the nearest ml, and
record the volume of the water in the first
three impingers; include any condensate in
the probe in this determination. Transfer the
impinger water from the graduated cylinder
into this polyethylene container. Add the
filter to this container. (The filter may be
handled separately using procedures subject
to the Administrator's approval.) Taking care
that dust on the outside of the probe or other
exterior surfaces does not get into the
sample, clean all sample-exposed surfaces
(including the probe nozzle, probe fitting,
probe liner, first three impingers, impinger
connectors, and filter holder) with deionized
distilled water. Use less than 500 ml for the
entire wash. Add the washings to the sampler
container. Perform the deionized distilled
water rinses as follows:
Carefully remove the probe nozzle and
rinse the inside surface with deionized
distilled water from a wash bottle. Brush with
a Nylon bristle brush, and rinse until the
rinse shows no visible particles, after which
make a final rinse of the inside surface. Brush
and rinse the inside parts of the Swagelok
fitting with deionized distilled water in a
similar way.
Rinse the probe liner with deionized
distilled water. While squirting the water into
the upper end of the probe, tilt and rotate the
probe so that all inside surfaces will be
wetted with water. Let the water drain from
the lower end into the sample container. The
tester may use a funnel (glass or
polyethylene) to aid in transferring the liquid
washes to the container. Follow the rinse
with a probe brush. Hold the probe in an
inclined position, and squirt deionized
distilled water into the upper end as the
probe brush is being pushed with a twisting
action through the probe. Hold the sample
container underneath the lower end of the
probe, and catch any water and particulate
matter that is brushed from the probe. Run
the brush through the probe three times or
more. With stainless steel or other metal
probes, run the brush through in the above
prescribed manner at least six times since
metal probes have small crevices in which
particulate matter can be entrapped. Rinse
the brush with deionized distilled water, and
quantitatively collect these washings in the
sample container. After the brushing, make a
final rinse of the probe as described above.
It is recommended that two people clean
the probe to minimize sample losses.
Between sampling runs, keep brushes clean
and protected from contamination.
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Rinse the inside surface of each of the first
three impingers (and connecting glassware)
three separate times. Use a small portion of
deionized distilled water for each rinse, and
brush each sample-exposed surface with a
Nylon bristle brush, to ensure recovery of
fine particulate matter. Make a final rinse of
each surface and of the brush.
After ensuring that all joints have been
wiped clean of the silicone grease, brush and
rinse with deionized distilled water the inside
of the filter holder (front-half only, if filter is
positioned between the third and fourth
impingers). Brush and rinse each surface
three times or more if needed. Make a final
rinse of the brush and filter holder.
After all water washings and particulate
matter have been collected in the sample
container, tighten the lid so that water will
not leak out when it is shipped to the
laboratory. Mark the height of the fluid level
to determine whether leakage occurs during
transport. Label the container clearly to
identify its contents.
7.2.2 Container No. 2 (Sample Blank).
Prepare a blank by placing an unused filter in
a polyethylene container and adding a
volume of water equal to the total volume in
Container No. 1. Process the blank in the
same manner as for Container No. 1.
7.2.3 Container No. 3 (Silica Gel). Note
the color of the indicating silica gel to
determine whether it has been completely
spent and make a notation of its condition.
Transfer the silica gel from the fourth
impinger to its original container and seal.
The tester may use a funnel to pour the silica
gel and a rubber policeman to remove the
silica gel from the impinger. It is not
necessary to remove the small amount of dust
particles that may adhere to the impinger
wall and are difficult to remove. Since the
gain in weight is to be used for moisture
calculations, do not use any water or other
liquids to transfer the silica gel. If a balance
is available in the field, the tester may follow
the analytical procedure for Container No. 3
in Section 7.4.2.
7.3 Sample Preparation and Distillation.
(Note the liquid levels in Containers No. 1
and No. 2 and confirm on the analysis sheet
whether or not leakage occurred during
transport. If noticeable leakage had occurred,
either void the sample or use methods,
subject to the approval of the Administrator,
to correct the final results.) Treat the contents
of each sample container as described below:
7.3.1 Container No. 1 (Probe, Filter, and
Impinger Catches). Filter this container's
contents, including the sampling filter,
through Whatman No. 541 filter paper, or
equivalent, into a 1500-ml beaker.
7.3.1.1 If the filtrate volume exceeds 900
ml, make the filtrate basic (red to
phenolphthalein) with NaOH, and evaporate
to less than 900 ml.
7.3.1.2 Place the filtered material
(including sampling filter) in a nickel crucible,
add a few ml of deionized distilled water,
and macerate the filters with a glass rod.
Add 100 mg CaO to the crucible, and mix
the contents thoroughly to form a slurry. Add
two drops of phenolphthalein indicator. Place
the crucible in a hood under infrared lamps
or on a hot plate at low heat. Evaporate the
water completely. During the evaporation of
the water, keep the slurry basic (red to
phenolphthalein) to avoid loss of F. If the
indicator turns colorless (acidic) during the
evaporation, add CaO until the color turns
red again.
After evaporation of the water, place the
crucible on a hot plate under a hood and
slowly increase the temperature until the
Whatman No. 541 and sampling filters char. It
may take several hours to completely char
the filters.
Place the crucible in a cold muffle furnace.
Gradually (to prevent smoking) increase the
temperature to 600°C, and maintain until the
contents are reduced to an ash. Remove the
crucible from the furnace and allow to cool.
Add approximately 4 g of crushed NaOH to
the crucible and mix. Return the crucible to
the muffle furnace, and fuse the sample for 10
minutes at 600°C.
Remove the sample from the furnace, and
cool to ambient temperature. Using several
rinsings of warm deionized distilled water,
transfer the contents of the crucible to the
beaker containing the filtrate. To assure
complete sample removal, rinse finally with
two 20-ml portions of 25 percent H2SO4, and
carefully add to the beaker. Mix well, and
transfer to a 1-liter volumetric flask. Dilute to
volume with deionized distilled water, and
mix thoroughly. Allow any undissolved solids
to settle.
7.3.2 Container No. 2 (Sample Blank).
Treat in the same manner as described in
Section 7.3.1 above.
7.3.3 Adjustment of Acid/Water Ratio in
Distillation Flask. (Use a protective shield
when carrying out this procedure.) Place 400
ml of deionized distilled water in the
distillation flask, and add 200 ml of
concentrated HjSO«. (Caution: Observe
standard precautions when mixing HaSO«
with water. Slowly add the acid to the flask
with constant swirling.) Add some soft glass
beads and several small pieces of broken
glass tubing, and assemble the apparatus as
shown in Figure 13A-2. Heat the flask until it
reaches a temperature of 175°C to adjust the
acid/water ratio for subsequent distillations.
Discard the distillate.
7.3.4 Distillation. Cool the contents of
the distillation flask to below 80°C. Pipet an
aliquot of sample containing less than 10.0 mg
F directly into the distillation flask, and add
deionized distilled water to make a total
volume of 220 ml added to the distillation
flask. (To estimate the appropriate aliquot
size, select an aliquot of the solution and
treat as described in Section 7.4.1. This will
be an approximation of the F content because
of possible interfering ions.) Note: If the
sample contains chloride, add 5 mg of AgsSOj
to the flask for every mg of chloride.
Place a 250-ml volumetric flask at the
condenser exit. Heat the flask as rapidly as
possible with a Bunsen burner, and collect all
the distillate up to 175°C. During heatup, play
the burner flame up and down the side of the
flask to prevent bumping. Conduct the
distillation as rapidly as possible (15 minutes
or less). Slow distillations have been found to
produce low F recoveries. Caution: Be careful
not to exceed 175°C to avoid causing HjSO4
to distill over.
If F distillation in the mg range is to be
followed by a distillation in the fractional mg
range, add 220 ml of deionized distilled water
and distill it over as in the acid adjustment
step to remove residual F from the distillation
system.
The tester may use the acid in the
distillation flask until there is carry-over of
interferences or poor F recovery. Check for
these every tenth distillation using a
deionized distilled water blank and a
standard solution. Change the acid whenever
the F recovery is less than 90 percent or the
blank value exceeds 0.1 >ig/ml.
7.4 Analysis.
7.4.1 Containers No. 1 and No. 2. After
distilling suitable aliquots from Containers
No. 1 and No. 2 according to Section 7.3.4,
dilute the distillate in the volumetric flasks to
exactly 250 ml with deionized distilled water,
and mix thoroughly. Pipet a suitable aliquot
of each sample distillate (containing 10 to 40
fig F/ml) into a beaker, and dilute to 50 ml
with deionized distilled water. Use the same
aliquot size for the blank. Add 10 ml of
SPADNS mixed reagent (6.3.13), and mix
thoroughly.
After mixing, place the sample in_a
constant-temperature bath containing the
Standard solutions (see Section 8.2) for 30
minutes before reading the absorbance on the
spectrophotometer.
Set the spectrophotometer to zero
absorbance at 570 nm with the reference
solution (6.3.12), and check the
spectrophotometer calibration with the
standard solution. Determine the absorbance
of the samples, and determine the
concentration from the calibration curve. If
the concentration does not fall within the
range of the calibration curve, repeat the
procedure using a different size aliquot.
7.4.2 Container No. 3 (Silica Gel). Weigh
the spent silica gel (or silica gel plus
impinger) to the nearest 0.5 g using a balance.
The tester may conduct this step in the field.
8. Calibration
Maintain a laboratory log of all
calibrations.
8.1 Sampling Train. Calibrate the
sampling train components according to the
indicated sections in Method 5: Probe Nozzle
(Section 5.1); Pilot Tube (Section 5.2);
Metering System (Section 5.3); Probe heater
(Section 5.4); Temperature Gauges (Section
5.5); Leak Check of Metering System (Section
5.6); and Barometer (Section 5.7).
8.2 Spectrophotometer. Prepare the
blank standard by adding 10 ml of SPADNS
mixed reagent to 50 ml of deionized distilled
water. Accurately prepare a series of
standards from the 0.01 mg F/ml standard
fluoride solution (6.3.10) by diluting 0, 2, 4, 6,
8, 10,12, and 14 ml to 100 ml with deionized
distilled water. Pipet 50 ml from each solution
and transfer each to a separate 100-ml
beaker. Then add 10 ml of SPADNS mixed
reagent to each. These standards will contain
0,10, 20, 30, 40 50,60, and 70 fig F (0 to 1.4 jig/
ml), respectively.
After mixing, place the reference standards
and reference solution in a constant
temperature bath for 30 minutes before
reading the absorbance with the
spectrophotometer. Adjust all samples to this
same temperature before analyzing.
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With the spectrophotometer at 570 nm, use
the reference solution (6.3.12) to set the
absorbance to zero.
Determine the absorbance of the
standards. Prepare a calibration curve by
plotting Hg F/50 ml versus absorbance on
linear graph paper. Prepare the standard
curve initially and thereafter whenever the
SPADNS mixed reagent is newly made. Also,
run a calibration standard with each set of
samples and if it differs from the calibration
curve by ±2 percent, prepare a new standard
curve.
9. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation. Other forms of the equations may
be used, provided that they yield equivalent
results.
9.1 Nomenclature.
A,, =4 Aliquot of distillate taken for color
development, ml.
A, = Aliquot of total sample added to still,
ml.
B,s = Water vapor in the gas stream,
proportion by volume.
C. = Concentration of F in stack gas, mg/ms,
dry basis, corrected to standard
conditions of 760 mm Hg (29.92 in. Hg)
and 293=K (528'R).
l(f
F)
Ft = Total F in sample, mg,
Hg F = Concentration from the calibration
curve, ng.
Tm = Absolute average dry gas meter
temperature (see Figure 5-2 of Method 5),
•K(°R).
T, = Absolute average stack gas temperature
(see Figure 5-2 of Method 5), °K (°R).
Vd = Volume of distillate collected, ml.
VmUui) = Volume of gas sample as measured
by dry gas meter, corrected to standard
conditions, dscm (dscf).
V, = Total volume of F sample, after final
dilution, ml.
V«(,w> = Volume of water vapor in the gas
sample, corrected to standard conditions,
scm (scf).
9.2 Average Dry Gas Meter Temperature
and Average Orifice Pressure Drop. See data
sheet (Figure 5-2 of Method 5).
9.3 Dry Gas Volume. Calculate Vm(,^ and
adjust for leakage, if necessary, using the
equation in section 6.3 of Method 5.
9.4 Volume of Water Vapor and Moisture
Content. Calculate the volume of water vapor
V»(st and moisture content Bsl from the data
obtained in this method (Figure 13A-1); use
Equations 5-2 and 5-3 of Method 5.
9.5 Concentration.
9.5.1 Total Fluoride in Sample. Calculate
the amount of F in the sample using the
following equation:
Eq. 13A-1
9.5.2 Fluoride Concentration in Stack Gas. Determine the F concentration in the stack
gas using the following equation:
K
Xstd)
Where:
K = 35.31 ft'/m'if V^uw) is expressed in
English units.
= 1.00 m'/m3 if Vm^u> is expressed in
metric units.
9.6 Isokinetic Variation and Acceptable
Results. Use Method 5, Sections 6.11 and
6.12.
10. Bibliography
1. Bellark. Ervin, Simplified Fluoride
Distillation Method. Journal of the American
Water Works Association. 50/5306. 1958.
2 Mitchell, W. J., J. C. Suggs, and F. J.
Bergman. Collaborative Study of EPA method
13A and Method 13B. Publication No. EPA-
600/4-77-050. Environmental Protection
Agency. Research Triangle Park, North
Carolina. December 1977.
3. Mitchell, W. J. and M. R. Midgett.
Adequacy of Sampling Trains and Analytical
Procedures Used for Fluoride. Atm. Environ.
70-865-672.1978.
Eq. 13A-2
Method 13B. Determination of Total Fluoride
Emissions From Stationary Sources; Specific
Ion Electrode Method
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of fluoride (F) emissions
from stationary sources as specified in the
regulations It does not measure
fluorocarbons, such as freons.
1.2 Principle. Gaseous and par'iculate F
are withdrawn isokmetically from the source
and collected in water and on a filter. The
total F is then determined by the specific ion
electrode method.
2. Range and Sensitivity
The range of this method is 0.02 to 2.000 fig
F/ml. however, measurements of less than 0.1
fig F/ml require extra care. Sensitivity has
not been determined.
3. Interferences
Grease on sample-exposed surfaces may
cause low F results because of adsorption.
4. Precision and Accuracy
4.1 Precision. The following estimates
are based on a collaborative test done at a
primary aluminum smelter. In the test, six
laboratories each sampled the stack
simultaneously using two sampling trains for
a total of 12 samples per sampling run.
Fluoride concentrations encountered during
the test ranged from 0.1 to 1.4 mg F/m5. The
within-laboratory and between-laboratory
standard deviations, which include sampling
and analysis errors, are 0.037 mg F/ms with
60 degrees of freedom and 0.056 mg F/m3
with five degrees of freedom, respectively.
4.2 Accuracy. The collaborative test did
not find any bias in the analytical method.
5. Apparatus
5.1 Sampling Train and Sample Recovery.
Same as Method 13A, Sections 5.1 and 5.2,
respectively.
5.2 Analysis. The following items are
needed:
5.2.1 Distillation Apparatus, Bunsen
Burner, Electric Muffle Furnace, Crucibles,
Beakers, Volumetric Flasks, Erlenmeyer
Flasks or Plastic Bottles, Constant
Temperature Bath, and Balance. Same as
Method ISA, Sections 5.3.1 to 5.3.9,
respectively, except include also 100-ml
polyethylene beakers.
5.2.2 Fluoride Ion Activity Sensing
Electrode.
5.2.3 Reference Electrode. Single
junction, sleeve type.
5.2.4 Electrometer. A pH meter with
millivolt-scale capable of ±0.1-mv resolution.
or a specific ion meter made specifically for
specific ion use.
5.2.5 Magnetic Stirrer and TFE *
Fluorocarbon-Coated Stirring Bars.
6. Reagents
6.1 Sampling and Sample Recovery.
Same as Method ISA, Sections 6.1 and 6.2,
respectively.
6.2 Analysis. Use ACS reagent grade
chemicals (or equivalent), unless otherwise
specified. The reagents needed for analysis
are as follows:
6.2.1 Calcium Oxide (CaO). Certified
grade containing 0.005 percent F or less.
6.2.2 Phenolphthalem Indicator.
Dissolve 0.1 g of phenolphthalein in a mixture
of 50 ml of 90 percent ethanol and 50 ml
deionized distilled water.
6.2.3 Sodium Hydroxide (NaOH).
Pellets.
6.2.4 Sulfuric Acid (HZSO4), Concentrated.
6.2.5 Filters. Whatman No. 541, or
equivalent.
6.2.6 Water. From same container as
6.1.2 of Method 13A.
6.2.7 Sodium Hydroxide, 5 M. Dissolve
20 g of NaOH in 100 ml of deionized distilled
water.
6.2.8 Sulfuric Acid, 25 percent (V/V).
Mix 1 part of concentrated H2SO« with 3
parts of deionized distilled water.
* Mention of any trade name or specific product
does not constitute endorsement by the
Environmental Protection Agency.
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6.2.9 Total Ionic Strength Adjustment
Buffer (TISAB). Place approximately 500 ml
of deionized distilled water in a 1-liter
beaker. Add 57 ml of glacial acetic acid, 56 g
of sodium chloride, and 4 g of cyclohexylene
dinitrilo tetraacetic acid. Stir to dissolve.
Place the beaker in a water bath to cool it
Slowly add 5 M NaOH to the solution,
measuring the pH continuously with a
calibrated pH/reference electrode pair, until
the pH is 5.3. Cool to room temperature. Pour
into a 1-liter volumetric flask, and dilute to
volume with deionized distilled water.
Commercially prepared TISAB may be
substituted for the above.
6.2.10 Fluoride Standard Solution. 0.1 M.
Oven dry some sodium fluoride (Nap) for a
minimum of 2 hours at 110°C, and store in a
desiccator. Then add 4.2 g of NaF to a 1-liter
volumetric flask, and add enough deionized
distilled water to dissolve. Dilute to volume
with deionized distilled water.
7. Procedure
7.1 Sampling, Sample Recovery, and
Sample Preparation and Distillation. Same
as Method 13A, Sections 7.1, 72, and 7.3,
respectively, except the notes concerning
chloride and sulfate interferences are not
applicable.
7.2 Analysis.
7.2.1 Containers No. 1 and No. 2. Distill
suitable aliquots from Containers No. 1 and
No. 2. Dilute the distillate in the volumetric
flasks to exactly 250 ml with deionized
distilled water and mix thoroughly. Pipet a
25-ml aliquot from each of the distillate and
separate beakers. Add an equal volume of
TISAB, and mix. The sample should be at the
same temperature as the calibration
standards when measurements are made. If
ambient laboratory temperature fluctuates
more than ±2°C from the temperature at
which the calibration standards were
measured, condition samples and standards
in a constant-temperature bath before
measurement. Stir the sample with a
magnetic stirrer during measurement to
minimize electrode response time. If the
•tirrer generates enough heat to change
solution temperature, place a piece of
temperature insulating material such as cork,
between the stirrer and the beaker. Hold
dilute samples (below 10' * M fluoride ion
content) in polyethylene beakers during
measurement.
Insert the fluoride and reference electrodes
into the solution. When a steady millivolt
reading is obtained, record it. This may take
several minutes. Determine concentration
from the-calibration curve. Between electrode
measurements, rinse the electrode with
distilled water.
7.2.2 Container No. 3 (Silica Gel). Same
as Method 13A, Section 7.4.2.
8. Calibration
Maintain a laboratory log of all
calibrations.
8.1 Sampling Train. Same as Method
13A.
8.2 Fluoride Electrode. Prepare fluoride
standardizing solutions by serial dilution of
the 0.1 M fluoride standard solution. Pipel 10
ml of 0.1 M fluoride standard solution into a
100-ml volumetric flask, and make up to the
mark with deionized distilled water for a 10"*
M standard solution. Use 10 ml of 10"* M
solution to make a 10"' M solution in the
same manner. Repeat the dilution procedure
and make lO'^and 10"* solutions.
Pipet 50 ml of each standard into a
separate beaker. Add 50 ml of TISAB to each
beaker. Place the electrode in the most dilute
standard solution. When a steady millivolt
reading is obtained, plot the value on the
linear axis of semilog graph paper versus
concentration on the log axis. Plot the
nominal value for concentration of the
standard on the log axis, e.g., when 50 ml of
10~2M standard is diluted with 50 ml of
TISAB, the concentration is still designated
"10" 2M."
Between measurements soak the fluoride
sensing electrode in deionized distilled water
for 30 seconds, and then remove and blot dry.
Analyze the standards going from dilute to
(M)
Where:
K=l9mg/ml.
10. References
1. Same as Method 13A, Citations 1 and 2
of Section 10.
2. MacLeod, Kathryn E. and Howard L.
concentrated standards. A straight-line
calibration curve will be obtained, with
nominal concentrations of 10"*, 10"', 10"*,
and 10"' fluoride molarity on the log axis
plotted versus electrode potential (in mv) on
the linear scale. Some electrodes may be
slightly nonlinear between 10"* and 10" 4M. If
this occurs, use additional standards between
these two concentrations.
Calibrate the fluoride electrode daily, and
check it hourly. Prepare fresh fluoride
standardizing solutions daily (10~*M or less).
Store fluoride standardizing solutions in
polyethylene or polypropylene containers.
(Note: Certain specific ion meters have been
designed specifically for fluoride electrode
use and give a direct readout of fluoride ion
concentration. These meters may be used in
lieu of calibration curves for fluoride
measurements over narrow concentration
ranges. Calibrate the meter according to the
manufacturer's instructions.)
9. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation.
9.1 Nomenclature. Same as Method 13A,
Section 9.1. In addition:
M = F concentration from calibration curve,
molarity.
9.2 Average Dry Gas Meter Temperature
and Average Orifice Pressure Drop, Dry Gas
Volume, Volume of Water Vapor and
Moisture Content, Fluroide Concentration in
Stack Gas, and Isokinetic Variation and
Acceptable Results. Same as Method 13A,
Section 9.2 to 9.4, 9.5.2. and 9.6, respectively.
9.3 Fluoride in Sample. Calculate the
amount of F in the sample using the
following:
Equation 13B-1
Crist. Comparison of the SPADNS—
Zirconium Lake and Specific Ion Electrode
Methods of Fluoride determination in Stack
Emission Samples. Analytical Chemistry.
45:1272-1273.1973.
|FR Doc 8O-186S8 Filed 0-19-80: 8.45 am)
BILLING CODE 6560-01-M
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114 Federal Register / Vol. 45, No. 127 / Monday, June 30. 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
IFRL 1442-1]
Standards of Performance for New
Stationary Sources Primary Aluminum
Industry; Amendments
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: The amendments permit
fluoride emissions to exceed, under
certain circumstances, emission limits
contained in the previously promulgated
standards of performance for new
primary aluminum plants. Such
excursions cannot be more than 0.3 kg/
Mg of aluminum produced (0.6 Ib/ton)
above the promulgated standards of 0.95
kg/Mg (1.9 Ib/ton) and 1.0 kg/Mg (2.0 lb/
ton) for prebake and Soderbcrg plants,
respectively. For an excursion to be
allowed, a proper emission control
system must have been installed and
properly operated and maintained at the
time of the excursion. The intended
effect of these amendments is to take
into account an inherent variability of
fluoride emissions from the aluminum
reduction process.
The amendments require monthly
testing of emissions and revise
Reference Method 14 for measuring
fluoride emission rates. The
amendments also respond to argument*
raised during litigation of the standards
of performance.
DATES: The effective date of the
amendments is June 30.1980. The
applicability date of the amendments is
October 23,1974. All primary aluminum -
plants which commence construction on
.and after the applicability date are
subject to the standards of performance,
as amended here.
ADDRESSES: Background Information
Document. The background information
documents for the proposed and final
amendments may be obtained from the
U.S. EPA Library (MD-35), Research
Triangle Park, North Carolina 27711,
telephone (919) 541-2777. Please refer to
Primary Aluminum Background
Information: Proposed Amendments
(EPA 450/2-76-025a) and Promulgated
Amendments (EPA 450/3-79-026).
Docket: Docket No. OAQPS-78-10,
containing supporting information used
to develop the amendments, is available
for public inspection and copying
between 8:00 a.m. and 4.00 p.m., Monday
through Friday, at EPA's Central Docket
Section, Room 2902, Waterside Mall, 401
M Street, S.W.. Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
John Crenshaw, Emission Standards and
Engineering Division (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone (919) 541-5477.
SUPPLEMENTARY INFORMATION:
Final Amendments
The amendments allow fluoride
emissions from aluminum plant
potrooms to exceed the original limits of
0.95 kg/Mg (1.9 Ib/ton) for prebake
plants and 1.0 kg/Mg (2.0 Ib/ton) for
Soderberg plants if the owner or
operator of the plant can establish that a
proper emission control system was
installed and properly operated and
maintained at the time the excursion
above the original limits occurred.
Emissions may not, however, exceed
1.25 kg/Mg (2.5 Ib/ton) for prebake
plants and 1.3 kg/Mg (2.6 Ib/ton) for
Soderberg plants at any time.
The amendments also require
performance testing to be conducted at
least once each month throughout the
life of the plant. The owner or operator
of a new plant may apply to the
Administrator for an exemption from the
monthly testing requirement for the
primary control system and the anode
bake plant. An exemption from the
testing of secondary emissions from roof
monitors, however, is not permitted.
Finally, the amendments: (1) require
the potroom anemometers and
associated equipment used in
conjunction with Reference Method 14
to be checked for calibration once each
year, unless the anemometers are found
to be out of calibration, in which case an
alternative schedule would be
implemented; [2] clarify other Reference
Method 14 procedures; (3) clarify the
definition of potroom group; (4) replace
English and metric units of measure with
the International System of Units (SI);
and (5) clarify the procedure for
determining the rate of aluminum
production for fluoride emission
calculations. The amendments do not
change the fluoride emission limit of 0.05
kg/Mg (0.1 Ib/ton) of aluminum
equivalent for anode baking facilities at
prebake plants.
Summary of Environmental, Economic,
and Energy Impacts
The amendments allow excursions
above the original standard, but only
under certain conditions. Each excursion
must be reported to the Administrator
and the adequacy of control equipment
and operating and maintenance
procedures must be established by the
plant owner or operator. Based on
emission test results at the Anaconda
Aluminum Company's Sebree, Kentucky
plant, such excursions may be expected
approximately eight percent of the time.
Assuming that each of these excursions
is at the upper limit allowed (1.25 kg/Mg
for a prebake plant), fluoride emissions
from a typical new primary aluminum
plant could be around three to four
percent higher (3.8 Mg/yr, or 4.2 tons/yr,
more) than had been originally
calculated. It is important to stress that
excursions are expected to occur at any
new plant trying to meet the original
standards; the amendments simply
acknowledge that some excursions are
unavoidable.
Although the emission control
efficiency required by the original
standards is still required, it would be
theoretically possible to operate a new
plant so that emissions were always at
the upper limit permitted by these
amendments. Using this "worst case"
assumption, fluoride emissions from a
typical new primary aluminum plant
could increase above levels associated
with the original emission limits by
about 30 percent, or 33 Mg/yr (36 tons/
yr). Assuming that two new plants
become subject to the amended
standards during the next five years,
nationwide emissions of fluorides during
that period could increase by 66 Mg/yr
(72 tons/yr) above the levels which
would result if the original limits were in
effect. No other environmental impacts
are associated with the amendments.
The amendments will result in
performance test costs of about
$415.000/yr during the first year and
$330,000/yr during succeeding years of
operation of a new plant. The increase
in annualized costs, however, would be
less than 0.5 percent for the first and
succeeding years. There are no other
significant costs associated with the
amendments.
No increase in energy consumption
will result from the amendments. The
environmental, economic, and energy
impacts are discussed in greater detail
in Primary Aluminum Background
Information: Promulgated Amendments
(EPA 450/3-79-026).
Background
Standards of performance for new
primary aluminum plants were proposed
on October 23,1974 (39 FR 37730), and
promulgated on January 26,1976 (41 FR
3826). These standards limited fluoride
emissions to 1.0 kg/Mg (2 Ib/ton) for
Soderberg plants, 0.95 kg/Mg (1.9 Ib/ton)
for prebake plants, and 0.05 kg/Mg (0.1
Ib/ton) for anode bake plants. There are
two emission sources from Soderberg
and prebake plants. The first source is
the primary control system, which
includes hoods to capture emissions
from the pots and the control device
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used to treat these emissions; the
exhaust from this system still contains
some fluorides. The second source is the
roof monitor, through which flow the
emissions (called secondary, or roof
monitor, emissions) not captured by the
primary control system. A few plants
use secondary control systems to
capture and collect roof monitor
emissions.
Shortly after promulgation, petitions
for review of the standards were filed
by four aluminum companies. The
principal argument raised by the
petitioners was that the emission limits
contained in the standards were too
stringent and could not be achieved
consistently by new, well-controlled
facilities. Facilities which commenced
construction prior to October 23, 1974.
are not affected by the standard.
Following discussions with the
petitioning aluminum companies, EPA
conducted an emission test program at
the Anaconda Aluminum Company'
plant in Sebree, Kentucky. At the time of
testing, the Sebree plant was the newest
primary aluminum plant in the United
States, and its emission control system
was considered by the Administrator
representative of the best technological
system of continuous emission
reduction. The purpose of the test
program was to gather additional data
for reevaluating the standards. The test
results were available in August of 1977
and indicated that emissions for a new,
well-controlled plant could exceed the
original emission limits approximately
eight percent of the time. The
amendments proposed on September 19,
1978 (43 PR 42186] and promulgated here
address this potential problem by
amending the standards to permit
excursions of fluoride emissions up to
0.3 kg/Mg {0.6 Ib/ton) above the
emission limits contained in the original
standards provided that proper control
equipment was installed and properly
operated and maintained during the time
the excursion occurred.
In addition to amending the original
standards, EPA has revised Reference
Method 14 to reflect knowledge gained
during the Sebree test program. The
revisions clarify and improve the
reliability of the testing procedures, but
do not change the basic test method
and. therefore, do not invalidate earlier
Method 14 test results.
Rationale
The Administrator's decision to
amend the existing standard is based
primarily on the results of the Sebree
test program. The test results may be
summarized as follows: (1) the measured
emissions were variable, ranging from
0.43 to 1.37 kg/Mg (0.85 to 2.74 Ib/ton)
for single test runs; and (2) emission
variability appeared to be inherent in
the production process and beyond the
control of plant personnel. Since the
Sebree plant represents a best
technological system of continuous
emission reduction for new aluminum
plants, the Administrator expects that
the other new plants covered by the
standard will also exhibit emission
variability.
An EPA analysis of the nine Sebree
test runs indicates that there is about
eight percent probability that a
performance test would violate the
current standard. (A performance test is
defined in 40 CFR 60.8(f) as the
arithmetic mean of three separate test
runs, except in situations where a run
must be discounted or canceled and the
Administrator approves using the
arithmetic mean of two runs.) The
petitioners have estimated chances of a
violation ranging from about 2.5 to 10
percent. Although the Sebree data base
is not large enough to permit a thorough
statistical analysis, the Administrator
believes it is adequate to demonstrate a
need for amending the current standard.
The approach selected is to amend
Subpart S to allow a performance test
result to be above the current standard
provided the owner or operator submits
to EPA a report clearly demonstrating
that the emission control system was
properly operated and maintained
during the excursion above the
standard. The report would be used as
evidence that the high emission level
resulted from random and
uncontrollable emission variability, and
that the emission variability was
entirely beyond the control of the owner
or operator of the affected facility.
Under no circumstances, however,
would performance test results be
allowed above 1.25 kg/Mg (2.5 Ib/ton)
for prebake plants or 1.3 kg/Mg (2.6 lb/
ton) for Soderberg plants. The
Administrator believes that emissions
from a plant equipped with the proper
control system which is properly
operated and maintained would be
below these limits at all times.
For performance test results which fall
between the original standard and the
1.25 or 1.3 kg/Mg upper limit to be
considered excursions rather than
violations, the owner or operator of the
affected facility must, within 15 days of
receipt of such performance test results,
submit a report to the Enforcement
Division of the appropriate EPA
Regional Office. As a minimum, the
report should establish that all
necessary control devices were on-line
and operating properly during the
performance test, describe the operation
and maintenance procedures followed,
and set forth any explanation for the
excursion.
The amendments also require,
following the initial performance test
required under 40 CFR 60.8(a),
additional performance testing at least
once each month during the life of the
affected facility. During visits to existing
plants, EPA personnel have observed
that the emission control systems are
not always operated and maintained as
well as possible. The Administrator
believes that good operation and
maintenance of control systems are
essential and expects the monthly
testing requirement to help achieve this
goal. The Administrator has the
authority under section 114 of the Clean
Air Act to require additional testing if
necessary.
It is important to emphasize that the
purpose of the amendments is to allow
for inherent emission variability, not to
permit substandard control equipment
installation, operation or maintenance.
Unfortunately, proper control equipment
and proper operation and maintenance
are difficult to describe and may vary
considerably on a case-by-case basis.
There are, however, a few guidelines
that can be used as indicators.
The first guideline is that the control
equipment should be designed to meet
the original standard. This means a 95-
97 percent overall control efficiency
(capture efficiency times collection
efficiency) for a potroom group.
Equipment capable of this level of
control is described in the background
document (EPA 450/2-74-020a).
Assuming proper control equipment is
installed, the adequacy of operating and
maintenance procedures can be
evaluated on the basis of the frequency
of excursions above the original
standard. Based on the Sebree test
results, more than one excursion per
year (assuming performance tests are
conducted monthly) may indicate a
problem. Note, however, that legally
every performance test result could be
an excursion as long as proper
equipment, operation and maintenance
are shown.
As a guide to proper operation and
maintenance, the following are
considered basic to good control of
emissions:
(1) Hood covers should fit properly
and be in good repair;
(2) If the exhaust system is equipped
with an adjustable air damper system.
the hood exhaust rate for individual pots
should be increased whenever hood
covers are removed from a pot (the
exhaust system should not, however, be
overloaded by placing too many pots on
high exhaust);
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(3) Hood covers should be replaced as
soon as possible after each potroom
operation;
(4) Dust entrainment should be
minimized during materials handling
operations and sweeping of the working
aisles;
(5) Only tapping crucibles with
functional aspirator air return systems
(for returning gases under the collection
hooding) should be used; and
(6) The primary control system should
be regularly inspected and properly
maintained.
The amendments affect not only
prebake designs such as the Scbree
plant, but also Soderberg plants.
Available data for existing plants
indicate that Soderberg and prebake
plants have similar emission variability.
Thus, the Administrator feels justified in
extrapolating the conclusions about the
Sebree prebake plant to cover Soderberg
designs, It is unlikely that any new
Soderberg plant will be built due to the
high cost of emission control for these
designs. However, existing Soderberg
plants may be modified to such an
extent that they would be subject to
these regulations.
Under the amendments, anode bake
plants would be subject to the monthly
testing requirement, but emissions
would not be allowed under any
circumstances to be above the level of
the current bake plant standard. Since
there is no evidence that bake plant
emissions are as variable as potroom
emissions, there is no need to allow for
excursions above the bake plant
standard.
The amendments allow the owner or
operator of a new plant to apply to the
Administrator for an exemption from the
monthly testing requirement for the
primary control system and the anode
bake plant. The Administrator believes
that the testing of these system* as often
as once aach month may be
unreasonable given that (1) the
contribution of primary and bake plant
emissions (after exhausting from the
primary control system) to the total
emission rate is minor, averaging about
2.5 and 5 percent, respectively; (2)
primary and bake plant emissions are
much less variable than secondary
emissions; and (3) the cost of primary
and bake plant emissions sampling is
high. An application to the
Administrator for an exemption from
monthly testing would be required Jo
include [1] evidence that the primary
and bake plant emissions have low
variability; (2) an alternative testing
schedule; and (3) the method to be used
to determine primary control system
emissions for the purpose of calculating
total fluoride emissions from the
potroom group.
The Administrator estimates the costs
associated with monthly performance
testing to average about $4,200 for
primary tests, $5,100 for secondary tests,
and $4,200 for bake plant tests. These
estimates assume that (1) testing would
be performed by plant personnel; (2)
each monthly performance test would
consist of the average of three 24 hour
runs; (3) sampling would be performed
by two crews working 13-hour shifts; (4)
primary control system sampling would
be performed at a single point in the
stack; and (5) Sebree in-house testing
costs would be representative of
average costs for other new plants.
Although these assumptions may not
hold for all situations, the Administrator
believes they provide a representative
estimate of what testing costs would be
for new plants.
Also amended is the procedure for
determining the rate of aluminum
production. Previously, the rate was
based on the weight of metal tapped
during the test period. However, since
the weight of metal tapped does not
always equal the weight of metal
produced, undertapping or overlapping
during a test period would result in
erroneous production rates. The
Administrator believes it is more
reasonable to judge the weight of metal
produced according to the weight of
metal tapped during a 30-day period (720
hours) prior to and including the test
date. The 30-day period allows
overlapping and undertapping to
average out, and gives a more accurate
estimate of the true production rate.
Public Comment*
Upon proposal of the amendments, the
public was invited to submit written
comments on all aspects of the
amendment* and Reference Method 14
revision*. Thes« comments were
reviewed and considered in developing
the final amendments. All of the
comment* received are summarized and
discussed in Primary Aluminum
Background Information: Promulgated
Amendments (EPA 450/3-79-026).
The most significant change resulting
from these comments concerns the
requirement in Reference Method 14 to
periodically check the calibration of the
anemometers located in the roof
monitors of aluminum plant potrooms.
The use of anemometers is required by
the test method to determine the
velocity and flow rate of air exiting the
potroom roofs. Commenters felt that the
proposed requirement to check
anemometer calibration every month
was unnecessary and would lead to
substantially increased costs.
Review of anemometer calibration
data indicates that anemometer
calibration checks as often as every
month are unnecessary. Consequently,
Reference Method 14 has been revised
to require an anemometer calibration
check 12 months after the initial
anemometer installation. The results of
this check will be used to determine the
schedule of subsequent anemometer
checks.
Several commenters noted thai the
proposed requirement to conduct
performance testing at least once each
month throughout the life of a new
primary aJuminum plant would impose a
large economic burden on the plant In
general, the commenters believed that
testing at less frequent intervals should
be sufficient to determine compliance
with the standard. Three alternatives to
monthly performance testing were
suggested:
(1) One commenter believed that an
initial performance test would be
sufficient to demonstrate compliance.
Periodic visual inspections could then
be used to determine whether the
control systems were being properly
maintained. If the visual inspections
indicated that maintenance was poor,
monthly testing could then be required.
This procedure would not impose the
burden of monthly testing on the entire
industry.
(Z) Another commenter, noting that
the proposed monthly testing
requirement was excessively stringent,
recommended that criteria be
established for determining when
monthly testing is required. For
example, testing could be performed on
a semi-annual basis until a violation
occurred, when testing would revert to a
monthly schedule.
(3) A third commenter suggested that
the provision* permitting the
Administrator, upon application, to
establish »n alternative test schedule for
primary and bake plant emissions be
extended to Include secondary
emi*sions. For example, quarterly
testing of secondary emissions could be
required until a violation occurred.
Monthly testing could then be invoked
for some period of time, possibly six
months, until emissions were once again
consistently below the level of the
standard. Quarterly testing would then
resume.
During the development of the
amendments, the administrator learned
•that the operation and maintenance of
aluminum plant emission control
systems had seriously deteriorated
during the past several years. The
Administrator believes that regular
emission testing will help remedy this
situation by providing an incentive for
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good operation and maintenance
throughout the life of the plant. Although
no continuous monitoring method is
available, the level of roof monitor
emissions provides a good indication of
the adequacy of operation and
maintenance procedures for the most
sensitive portion of the primary control
system: capture of the pot emissions.
The frequency of testing selected—once
per month—is a judgmental compromise
between high testing costs (as would
occur with weekly tests) and the
possibility of inadequate maintenance
between tests (which seems more likely
to occur as the time between tests
increases).
In evaluating comments on the
proposed monthly testing requirement.
the administrator focused his attention
on costs. Since the cost of the monthly
testing requirement is less than 0.5
percent of the annualized costs of a
typical primary aluminum plant, the
Administrator considered the
requirement reasonable.
The original standards required
potroom emissions to be below 0.95 kg/
Mg (1.9 )b/ton) for prebake plants and
1.0 kg/Mg (2.0 Ib/ton) for Soderberg
plants. One commenter, noting that the
0.05 kg/Mg (0.1 Ib/ton) difference
between the standards is reasonable in
view of the differences between the two
types of plants, felt this same reasoning
should be followed in developing the
proposed never-to-be-exceeded limit of
1.25 kg/Mg (2.5 Ib/ton) which applied to
both prebake and Soderberg plants. The
commenter recommended that a never-
to-be-exceeded limit of 1.3 kg/Mg (2.6
Ib/ton) be established for Soderberg
plants while retaining the proposed 1.25
kg/Mg (2.5 Ib/ton) limit for prebake
plants.
This comment is incorporated in the
final amendments, which allow
emissions from Soderberg plants where
exemplary operation and maintenance
of the emission control systems has
been demonstrated to be as high as 1.3
kg/Mg (2.6 Ib/ton).
One commenter expressed concern
over the correct number or Reference
Method 14 sampling manifolds to be
located in potroom groups where two or
more potroom segments are ducted to a
common control system. The regulation
defines potroom group as an
uncontrolled potroom. a potroom which
is controlled individually, or a group of
potrooms or potroom segments ducted to
a common control system. In situations
where a potroom group consists of a
group of potroom segments ducted to a
common control system, the manifold
would be installed in only one potroom
segment. The manifold may not be
di\ ided among potroom segments
however, additional sampling manifolds
may be installed in the other segments,
if desired.
When only one manifold is located in
a potroom group, care must be taken to
ensure that operations are normal in the
potroom segments where manifolds are
not located, but which are ducted to the
same control system. During normal
operation, most pots should be
operating, no major upsets should occur.
and the operating and maintenance
procedures followed in each potroom
segment, including the segment tested,
should be the same. Otherwise, the
emission levels measured in the tested
potroom segment may not be
representative of emission levels in the
other potroom segments.
One commenter felt that the
amendments would unjustly require the
use of tapping crucibles with aspirator
air return systems, since the preamble
for the proposed amendment stated that
certain operating and maintenance
procedures, including the use of
aspirator air return systems, represent
good emission control and should be
implemented. Although this statement
reflects the Administrator's judgment
about which procedures would enable
the standards to be achieved, the
regulation does not actually require that
these procedures be implemented.
Instead these procedures provide useful
guidance for improving emission control
when the standards are being exceeded
If emissions are below 0.95 kg/Mg (1.9
Ib/ton) for prebake potrooms and 1.0
kg/Mg (2.0 Ib/ton) for Soderberg
potrooms, any combination of
procedures may be used. If emission
levels are between 0.95 and 1.25 kg/Mg
(1.9 and 2.5 Ib/ton) for prebake
potrooms or 1.0 and 1.3 kg/Mg (2.0 and
2.6 Ib/ton) for Soderberg pptrooms, the
regulation requires the owner or
operator of a plant to demonstrate that
exemplary operating and maintenance
procedures were used. Otherwise the
excursion is considered a violation of
the standard. The Administrator has not
defined exemplary operating and
maintenance procedures in the
regulation because different plants.
depending on plant design, may
incorporate different procedures, but the
basic procedures listed in the preamble
rationale proxide guidance as to which
operating and maintenance procedures
should be effected to reduce or prevent
excursions.
Several commenters expressed
concern that the standards of
performance and test methods would be
applied to existing primary aluminum
plants. It is emphasized, however, that
the standards and test methods apply
onlv to new. modified, or reconstructed
plants. Existing plants often differ in
design from new plants and cannot be
controlled to the same level, except at
much higher costs. As an aid to the
States in controlling emissions from
existing primary aluminum plants, the
Administrator has recently published
draft emission guidelines for existing
plants (44 FR 21754), These draft
guidelines may be obtained from the
U.S. EPA Library. Request Primary
Aluminum Draft Guidelines for Control
of Fluoride Emissions from Existing
Primary Aluminum Plants (EPA 450/2-
78-049a).
Another commenter was concerned
about the required length of each test
run Section 5.3.4 of Reference Method
14 states that each test run shall last at
least eight hours, and if a question exists
as to the representativeness of an eight-
hour period, a longer period should be
selected. It is essential that the sampling
period be representative of all potroom
operations and events, including
tapping, carbon setting, and tracking.
For most recently-constructed plants. 24
hours are required for all potroom
operations and events to occur in the
area beneath the sampling manifold.
Thus, a 24-hour sampling period would
be necessary for these plants.
Another commenter expressed
concern about the procedure for
conducting performance tests. The
General Provisions for standards of
performance for new stationary sources
|40 CFR 60 8(f)] state that each
performance test shall consist of the
arithmetic mean of three separate test
runs Although the results of the three
test runs are to be calculated separately.
the runs may be conducted
consecutive!}. as was done during the
Sebree test program.
One commenter suggested that the
rate of aluminum production, as used to
calculate final emission rates, be based
on the weight of metal tapped during the
month in which testing was performed
rather than on the test date. This, the
commenter believed, would be a more
convenient and practical method for
calculating the aluminum production
rate because production records are
commonly kept on a monthly basis The
Administrator believes, however, that if
the rate of aluminum production were
determined on a calendar-month basis.
as the commenter suggests, then in
situations where testing is conducted al
the beginning of a month, the final test
results would not be known until the
end of the month. This delay could
allow emissions to be above the
standard for nearly an entire month
before a violation could be determinpd
and corrective actions taken It is
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preferable thdt the test results be known
as soon as possible after the testing is
completed, as provided for in the
proposed and final amendments.
As a result of comments, several other
minor changes were made to the
proposal. These include provisions
allowing an owner or operator the
option of: (1) installing anemometers
halfway across the width of the potroom
roof monitor: (2) balancing the sampling
manifold for flow rate prior to its
installation in the roof monitor; or (3)
making anemometer installations non-
permanent.
Docket
The docket is an organized and
complete file of all the information
submitted to or otherwise considered in
the development of this rulemaking. The
principal purposes of the docket are: (1)
to allow interested parties to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process:
and (2) to serve as the record in case of
judicial review. The docket is available
for public inspection and copying, as
noted under ADDRESSES.
Miscellaneous
The proposed amendments contained
a revision to Section 60,8(d) of the
General Provisions which would have
allowed the owner or operator to give
less than 30 days prior notice of testing
if required to do so in specific
regulations. Since this revision has
already been promulgated with another
regulation (44 FR 33580), it is not
contained in the final amendments
promulgated here.
The final amendments do not alter the
applicability date of the original
standards. The standards continue to
apply to all new primary aluminum
plants for which construction or
modification began on or after October
23. 1974, the original proposal date.
As prescribed by section 111 of the
Clean Air Act, promulgation of the
original standards of performance (41
FR 3826) was preceded by the
Administrator's determination that
primary aluminum plants contribute
significantly to air pollution which
causes or contnbutes to the
endangerment of public health or
welfare. In accordance with section 117
of the Act, publication of the originally
proposed standards (39 FR 37730) was
preceded by consultation with
appropriate advisory committees,
independent experts, and Federal
departments and agencies.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Act reflect:
' " " application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, and any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated (section lll(a)(l)].
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas,
i.e.. those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the National
Ambient Air Quality Standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3) for such category of
source. The statute defines LAER as that
rate of emissions based on the
following, whichever is more stringent:
(A) 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
|B) The most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources (referred to
in section 169(1)) employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act. Best available
control technology must be determined
on a case-by-case basis, taking energy,
environmental and economic impacts
and other costs into account. In no event
may the application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all events. State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reduction than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent limits than those established
under section 111 and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment and
environmental impact statement for
substantial revisions to standards of
performance. Although these
amendments are not substantial
revisions, certain economic information
was developed and is presented in
Primary Aluminum Background
Information: Promulgated Amendments
(EPA 450/3-79-026). The revisions to the
standards of performance were not
significant enough to warrant
preparation of an environmental impact
statement.
Dated: ]une 24.1980.
Douglas M. Costle,
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
40 CFR Part 60 is revised as follows:
1. Subpart S is revised to read as
follows:
Subpart S—Standards of Performance
for Primary Aluminum Reduction
Plants
Authority: Sections 111 and 301 (a) of the
Clean Air Act as amended (42 U.S.C. 7411,
7601(a)), and additional authority as noted
below.
Section 60.190 paragraph (a) is revised
as follows:
§ 60.190 Applicability and designation of
affected facility.
(a) The affected facilities in'primary
aluminum reduction plants to which this
subpart applies are potroom groups and
anode bake plants.
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Section 60.191 is revised to read as
follows:
§60.191 Definitions.
As used in this subpart. all terms not
defined herein shall have the meaning
gi\en them in the Act and in subpart A
of this part.
"Aluminum equivalent" means an
amount of aluminum which can be
produced from a Mg of anodes produced
by an anode bake plant as determined
by § 60.195(g).
"Anode bake plant" means a facility
which produces carbon anodes for use
in a primary aluminum reduction plant
"Potroom" means a building unit
which houses a group of electrolytic
cells in which aluminum is produced
"Potroom group" means an
uncontrolled potroom. a potroom which
is controlled individually, or a group of
potrooms or potroom segments ducted to
a common control system.
"Primary aluminum reduction plant"
means any facility manufacturing
aluminum by electrolytic reduction
"Primary control system" means an
air pollution control system designed to
remove gaseous and particulate
flourides from exhaust gases which are
captured at the cell,
"Roof monitor" means that portion of
the roof of a potroom where gases not
captured at the cell exit from the
potroom.
"Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods
specified in § 60.195 or by equivalent or
alternative methods (see | 60.8(b))
Section 60.193 is revised to read as
follows:
§ 60.192 Standards for fluorides.
(a) On and after the date on which the
initial performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases
containing total fluorides, as measured
according to § 60.8 above, in excess of
(1) 1.0 kg/Mg (2.0 Ib/ton) of aluminum
produced for potroom groups at
Soderberg plants: except that emissions
between 1.0 kg/Mg and 1.3 kg/Mg (2.6
Ib/ton) will be considered in compliance
if the owner or operator demonstrates
that exemplary operation and
maintenance procedures were used with
respect to the emission control system
and that proper control equipment was
operating at the affected faciht\ during
the performance tests;
(2) 0.95 kg/Mg (1.9 Ib/ton) of
aluminum produced for potroom groups
at prebake plants; except that emissions
between 0 95 kg/Mg and 1 25 kg/Mg (2.5
Ib/ton) will be considered in compliance
if the owner or operator demonstrates
that exemplary operation and
maintenance procedures were used with
respect to the emission control system
and that proper control equipment was
operating at the affected facility during
the performance test; and
(3) 0.05 kg/Mg (0.1 Ib/ton) of
aluminum equivalent for anode bake
plants.
(b) Within 30 days of any performance
test which reveals emissions which fall
between the 1.0 kg/Mg and 1.3 kg/Mg
levels in paragraph (a](l) of this section
or between the 0.95 kg/Mg and 1.25 kg/
Mg levels in paragraph (a)(2) of this
section, the owner or operator shall
submit a report indicating whether all
necessary control devices were on-line
and operating properly during the
performance test, describing the
operating and maintenance procedures
followed, and setting forth any
explanation for the excess emissions, to
the Director of the Enforcement Division
of the appropriate EPA Regional Office.
Section 60.193 is revised to read as
follows:
§ 60.193 Standard lor visible emissions.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any potroom group any gases
which exhibit 10 percent opacity or
greater, or
(2) From any anode bake plant any
gases which exhibit 20 percent opacity
or greater.
Section 60.194 paragraphs (a) and (b)
are revised as follows:
§60.194 Monitoring of operations.
(a) The owner or operator of any
affected facility subject to the provisions
of this subpart shall install, calibrate.
maintain, and operate monitoring
devices which can be used to determine
daily the weight of aluminum and anode
produced. The weighing devices shall
have an accuracy of ± 5 percent over
their operating range.
(b) The owner or operator of any
affected facility shall maintain a record
of daily production rates of aluminum
and anodes, raw material feed rates.
and cell orpotlme voltages.
(Section 114 of the Clean Air Act as amended
(42 U.SC. 7414))
Section 60.195 is reused as follows
§ 60.195 Te>t methods and procedures.
(d) Following the initial performance
test as required under § 60.8(a). an
owner or operator shall conduct a
performance test at least once each
month during the life of the affected
facility except when malfunctions
prevent representative sampling, as
provided under § 60.8(c). The owner or
operator shall gi\e the Administrator at
least 15 days ad\ ance notice of each
test. The Administrator may require
additional testing under section 114 of
the Clean Air Act.
(b) An owner or operator may petition
the Administrator to establish an
alternatee testing requirement thdt
requires testing less frequently than
once each month for a priman, control
system or an anode bake plant. If the
owner or operator show that emissions
from the primary control system or the
anode bake plant have low variability
during day-to-day operations, the
Administrator may establish such an
alternative testing requirement. The
alternative testing requirement shall
include a testing schedule and, in the
case of a primary control system, the
method to be used to determine pnmarj
control system emissions for the purpose
of performance tests The Administrator
shall publish the alternative testing
requirement in the Federal Register.
(c) Except as pro\ided in § 60.8(b).
reference methods specified in
Appendix A of this part shall be used to
determine compliance with the
standards prescribed in § 60.192 as
follows:
(1J For sampling emissions from
stacks:
(i) Method 1 for sample and veJocih
traverses.
(n) Method 2 for velocity and
volumetric flow rate.
(lii) Method 3 for gas analysis, and
(iv) Method 13A or 13B for the
concentration of total fluorides and the
associated moisture content.
(2) For sampling emissions from roof
monitors not employing stacks or
pollutant collection systems:
(i) Method 1 for sample and velociH
traverses.
(ii) Method 2 and Method 14 for
velocity and volumetric flow rate,
(iii] Method 3 for gas analysis, and
(iv) Method 14 for the concentration of
total fluorides and associated moisture
content.
(3) For sampling emissions from roof
monitors not employing stacks but
equipped with pollutant collection
systems, the procedures under § 60 8(b)
shall be followed.
(d'J For Method 13A or 13B, the
sampling time for each run shall be at
least 8 hours for any potroom sample
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and at least 4 hours for any anode bake
plant sample, and (he minimum sample
volume shall be 6.8 dscm (240 dscf) for
any potroom sample and 3.4 dscm {120
dscf) for any anode bake plant sample
except that shorter sampling times or
smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(e) The air pollution control system for
each affected facility shall be
constructed so that volumetric flow
rates and total fluoride emissions can be
accurately determined using applicable
methods specified under paragraph (c)
of this section.
(f) The rate of aluminum production is
determined by dividing 720 hours into
the weight of aluminum tapped from the
affected facility during a period of 30
days prior to and including the final run
of a performance test.
(g) For anode bake plants, the
aluminum equivalent for anodes
produced shall be determined as
follows:
(1) Determine the average weight (Mg)
of anode produced in anode bake plant
during a representative oven cycle using
a monitoring device which meets the
requirements of § 60.194(a).
(2) Determine the average rate of
anode production by dividing the total
weight of anodes produced during the
representative oven cycle by the length
of the cycle in hours.
(3) Calculate the aluminum equivalent
for anodes produced by multiplying the
average rate of anode production by
two. (Note: An owner or operator may
establish a different multiplication
factor by submitting production records
of the Mg of aluminum produced and the
concurrent Mg of anode consumed by
potrooms.)
(h) For each run, potroom group
emissions expressed in kg/Mg of
aluminum produced shall be determined
using the following equation:
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two alternatives. The first is to make a
iclocity traverse of the width of the roof
monitor where an anemometer is to be placed
and install the anemometer at a point of
average velocity along this traverse. The
traverse may be made with any suitable low
velocity measuring device, and shall be made
during normal process operating conditions.
The second alternative, at the option of the
tester, is to install the anemometer halfway
across the width of the roof monitor. In this
latter case, the velocity traverse need not be
conducted.
2.1.3 Recorders. Recorders, equipped with
suitable auxiliary equipment (e.g.
transducers) for converting the output signal
from each anemometer to a continuous
recording of air flow velocity, or to an
integrated measure of volumetric flowrate. A
suitable recorder is one that allows the
output signal from the propeller anemometer
to be read to within 1 percent when the
velocity is between 100 and 120 m/min (350
and 400 fpm). For the purpose of recording
velocity, "continuous" shall mean one
readout per 15-minute or shorter time
interval. A constant amount of time shall
elapse between readings. Volumetric flow
rate may be determined by an electrical
count of anemometer revolutions. The
recorders or counters shall permit
identification of the velocities or flowrate
measured by each individual anemometer.
2.1.4 Pilot tube. Standard-type pilot tube.
as described in Section 2.7 of Method 2, and
having a coefficient of 0.99±0.01.
2.1.5 Pilot tube (optional). Isolated, Type
S pilot, as described in Section 2.1 of Method
2. The pilot tube shall have a known
coefficient, determined as outlined in Section
4.1 of Melhod 2.
2.1.6 Differentia] pressure gauge. Inclined
manometer or equivalent, as described in
Section 2.1.2 of Method 2.
2.2 Roof monitpr air sampling system.
2.2.1 Sampling ductwork. A minimum of
one manifold system shall be installed for
each potroom group (as defined in Subpart S.
Section 60.191). The manifold system and
connecting duct shall be permanently
installed to draw an air sample from the roof
monitor to ground level. A typical installation
of a duct for drawing a sample from a roof
monitor to ground level is shown in Figure
14-1. A plan of a manifold system that is
located in a roof monitor is shown in Figure
14.2. These drawings represent a typical
installation for a generalized roof monitor
The dimensions on these figures may be
altered slightly to make the manifold system
fit into a particular roof monitor, but the
general configuration shall be followed.
There shall be eight nozzles, each having a
diameter of 0.40 to 0.50 m. Unless otherwise
specified by the AdminiMrator. Ihe length of
the manifold system from the first nozzle to
the eighth shall be 35 m or eight percent of
the length of the potroom (or potroom
segment) roof monitor, whichever is greater.
The duct leading from the roof monitor
manifold shall lie round with a diameter of
0.30 to 0.40 m. As shown in Figure 14-2, each
of the sample legs of the manifold shall have
a device, such as a blast gate or valve, to
enable adjustment of the flow mto each
sample nozzle.
BILLING CODE 6560-Ot-M
IV-408
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
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IV-409
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
0.025 DIA
CALIBRATION
HOLE
DIMENSIONS IN METERS
NOT TO SCALE
Figure 14 2 Sampling manifold and nozzles
BILLING COM 66SO-01-C
IV-410
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
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IV-411
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
The manifold sh
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
SIDE
(A)
FRONT
SIDE
(B)
FROM
Figure 144. Check of anemometer starting torque. A "y" gram weight placed "x" centimeters
from center of propeller shaft produces a torque of "xy" g-cm. The minimum torque which pro-
duces a 90° (approximately) rotation of the propeller is the "starting torque."
IV-413
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
o
UJ*
a
o
K
O
tr
<
FPM
(m/tnin)
20
(6)
40
(12)
60
(18)
80
(24)
100
(30)
120
(36)
140
(42)
THESHOLD VELOCITY FOR HORIZONTAL MOUNTING
Figure 145. Typical curve of starting torque vs horizontal threshold velocity for propeller
anemometers. Based on data obtained by R.M. Young Company, May, 1977.
IV-414
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
4 1.2 Thermocouple. Check the calibration
of the thermocouple-potentiometer system,
using the procedures outlined in Section 4.3
of Method 2. at temperatures of 0,100, and
150' C If the CHliliration is off by more than
5'C at any of the temperatures, repair or
replace the system; otherwise, the system can
be used.
4.1.3 Recorders and/or counters. Check
the calibration of each recorder and/or
counter (see Section 2.1.3) at a minimum of
three points, approximately spanning the
expected range of velocities. Use the
calibration procedures recommended by the
manufacturer, or other suitable procedures
(subject to the approval of the
Administrator). If a recorder or counter is
found to be out of calibration, by an average
amount greater than 5 percent for the three
calibration points, replace or repair the
sys'em: otherwise, the system can be used.
4.1 4 Manifold Intake Nozzles. In order to
balance the flow rates in the eight individual
nuzzles, proceed as follows: Adjust the
exhaust fan to draw a volumetric flow rate
(refer to Equation 14-1) such that the
entrance velocity into each manifold nozzle
approximates the average effluent velocity in
the roof monitor. Measure the velocity of the
air entering each nozzle by inserting a
standard pilot tube into a 2.5 cm or less
diameter hole (see Figure 14-2) located in the
manifold between each blast gate (or valve)
and nozzle. Note that a standard pilot tube is
used, rather than a type S, to eliminate
possible velocity measurement errors due to
cross-section blockage in the small (0.13 m
diameter) manifold leg ducts. The pitot tube
tip shall be positioned at the center of each
manifold leg duct. Take care to insure that
there is no leakage around the pilot tube.
which could affect the indicated velocity in
the manifold leg If the velocity of air being
didwn into each nozzle is not the same, open
or close earh blast gate (or valve) until the
velocity in each nozzle is the same Fasten
each blast gate (or vaNe) so that it will
remain in this position and close the pitot
port holes. This calibration shall be
performed when the manifold system is
installed Alternativelv. the manifoRi may be
prdissembled and the flow rates balanced on
the ground, before being installed.
4.2 Periodical performance checks.
Twelve months afler their iniUal installation,
ch«.k the calibration of the propeller
anemometers, thermocouple-potentiometer
system, and the recorders and/or counters as
in Section 4 1. If the above systems pass the
performance checks, (i.e., if no repair or
replacement of any component is necessary),
continue with the performance checks on a
12-month interval basis However, if any of
the above systems fail the performance
checks, repair or replace the system(s) that
failed and conduct the periodical
performance checks on a 3-mohth interval
basis, until sufficient information (consult
with the Administrator) is obtained to
establish a modified performance check
schedule and calculation procedure.
Note.—If any of the above systems fatl the
initial performance checks, the data for the
past year need no! be recalculated.
5. Procedure.
5.1 Roof Monitor Velocity Determination.
5.1.1 Velocity estimate(s) for setting
isokinetic flow. To assist in setting isokinetic
flow in the manifold sample nozzles, the
anticipated average velocity in the section of
the roof monitor containing the sampling
manifold shall be estimated prior to each test
run. The tester may use any convenient
means to make this estimate (e.g.. the
velocity indicated by the anemometer in the
section of the roof monitor containing the
sampling manifold may be continuously
monitored during the 24-hour period prior to
the test run).
If there is question as to whether a single
estimate of average velocity is adequate for
an entire test run (e.g., if velocities are
anticipated to be significantly different
during different potroom operations), the
tester may opt to divide the test run into two
or more "sub-runs," and to use a different
estimated average velocity for each sub-run
(see Section 5.3.2 2.)
5.1 2 Velocity determination during a test
run. During the actual test run, record the
velocity or volumetric flowrate readings of
each propeller anemometer in the roof
monitor. Readings shall be taken for each
anemometer every 15 minutes or at shorter
equal time intervals (or continuously).
5.2 Temperature recording. Record the
temperature of the roof monitor every 2 hours
during the test run.
5.3 Sampling.
5.3.1 Preliminary air flow in duct. During
24 hours preceding the Jest, turn on the
exhaust fan and draw roof monitor air
through the manifold duct to condition the
ductwork. Adjust the fan to draw a
volumetric flow through the duct such that
the velocity of gas entering the manifold
nozzles approximates the average velocity of
the air exiting the roof monitor in the vicinity
of the sampling manifold.
5.3.2 Manifold isokinetic sample rate
adjustment(s).
5.3.2.1 Initial adjustment. Prior to the test
run (or first sub-run, if applicable: see Section
5.11 and 5.3.2 2), adjust the fan to provide the
necessary volumetric flowrate in the
sampling duct, so that air enters the manifold
sample nozzles at a velocity equal to the
appropriate estimated average velocity
determined under Section 5.1.1. Equation 14-1
gives the correct stream velocity needed in
the duct at the sampling location, in order for
Sample gas to be drawn isokinetically into
the manifold nozzles. Next, verify that the
correct stream velocity has been achieved, by
performing a pitot tube traverse of the sample
duct (using either a standard or type S pitot
tube); use the procedure outlined in Method 2.
8 (D .)' 1 min
(vj
(Equation 14-1)
(D,,)' 60 sec
Where:
.va = Desired velocity in duct at sampling
location. m/»ec.
Dn = Diameter of a roof monitor manifold
nozzle, m.
D,i = Diameter of duct at sampling location,
m.
vm = Average velocity of the air stream in
the roof monitor, m/min, as determined
under Section 5.1.1.
5.3.2.2 Adjustments during run. If the test
run is divided into two or more "sub-runs"
(see Section 5.1.1), additional isokinetic rote
adjustment(s) may become necessary during
the run. Any such adjustment shall be made
just before the start of a sub-run, using the
procedure outlined in Section 5.3.2.1 above.
Note.—Isokinetic rate adjustments are not
permissible during a sub-run.
5.3.3 Sample train operation. Sample the
duct using the standard fluoride train and
methods described in Methods 13A and 13B.
Determine the number and location of the
sampling points in accordance with Method
1. A single train shall be used for the entire
sampling run Alternatively, if two or more
sub-runs are performed, a separate train may
be used for each sub-run; note, however, that
if this option is chosen, the area of the
sampling nozzle shall be the same (± 2
percent) for each train. If the test run is
divided into sub-runs, a complete traverse of
the duct shall be performed during each sub-
run.
5.3 4 Time per run. Each test run shall last
8 hours or more; if more than one run is to be
performed, all runs shall be of approximately
the same (± 10 percent) length. If question
exists as to the representativeness of an 8-
hour test, a longer period should be selected.
Conduct each run during a period when all
normal operations are performed underneath
the sampling manifold. For most recently-
constructed plants, 24 hours are required for
all potroom operations and events to occur in
the area beneath the sampling manifold.
During the test period, all pots in the potroom
group shall be operated such that emissions
are representative of normal operating
conditions in the potroom group.
5 3.5 Sample recovery. Use the sample
recovery procedure described in Method ISA
or!3B.
5.4 Analysis, Use the analysis procedures
described in Method 13A or 13B.
6. Calculations.
6.1 Isokinetic sampling check.
6.1.1 Calculate the mean velocity (vm) for
the sampling run. as measured by the
anemometer in the section of the roof monitor
containing the sampling manifold If two or
more sub-runs have been performed, the
tester may opt to calculate the mean velocity
for each sub-run.
6.1.2 Using Equation 14-1. calculate the
expected average velocity (va) in the
sampling duct, corresponding to each value of
vm obtained under Section 6.1.1.
6.1 3 Calculate the actual average velocity
(vj in the sampling duct for each run or sub-
run, according to Equation 2-9 of Method 2,
and using data obtained from Method 13.
6.1 4 Express each value v, from Section
6.1 3 as a percentage of the corresponding va
value from Section 6 1.2.
IV-415
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
6.1.4.1 If v, is less than or equal to 120
percent of vd, the results are acceptable (note
that in cases where the above calculations
have been performed for each sub-run, the
results are acceptable if the average
percentage for all sub-runs \e less than or
equal to 120 percent).
6.1.4.2 If v. is more than 120 percent of vd,
multiply the reported emission rate by the
following factor.
200
6.2 Average velocity of roof monitor
gases. Calculate the average roof monitor-
n
velocity using all the velocity or volumetric
flow readings from Section 5.1.2.
6.3 Roof monitor temperature. Calculate
the mean value of the temperatures recorded
in Section 5.2.
6.4 Concentration of fluorides in roof
monitor air (in mg F/m3).
6.4.1 If a single sampling train was used
throughout the run, calculate the average
fluoride concentration for the roof monitor
using Equation 13A-2 of Method 13A.
6.4.2 If two or more sampling trains were
used (i.e., one per sub-run), calculate the
average fluoride concentration for the run, as
follows:
(Equation 14-2)
Where:
C,=Average fluoride concentration in roof
monitor air, mg F/dscm.
F,=Total fluoride mass collected during a
particular sub-run, mg F (from Equation
13A-1 of Method ISA or Equation 13B-1
of Method 13B).
Vm(sui)=Total volume of sample gas
passing through the dry gas meter during
a particular sub-run, dscm (see Equation
5-1 of Method 5).
n=Total number of sub-runs.
6.5 Average volumetric flow from the roof
monitor of the potroom(s) (or potroom
segment(s)) containing the anemometers is
given in Equation 14-3.
Vw(A) (Ma) P,,,|293 K)
(760mmHg)
(Equation 14-3)
Where:
Qro=Average volumetric flow from roof
monitor at standard conditions on a dry
basis, m3/min.
A = Roof monitor open area. m2.
vml = Average velocity of air in the roof
monitor, m/min, from Section 6.2.
Pm = Pressure in the roof monitor; equal to
barometric pressure for this application,
mm Hg.
Tm = Roof monitor temperature. °C, from
Section 6.3.
Md = Mole fraction of dry gas. which is
given by:
M. = n B.J
Note.—B»s is the proportion by volume of
water vapor in the gas stream, from Equation
5-3, Method 5.
7. Bibliography.
1. Shigehara, R. T. A guideline for
Evaluating Compliance Test Results
(Isokinetic Sampling Rate Criterion). U.S.
Environmental Protection Agency, Emission
Measurement Branch. Research Triangle
Park, North Carolina. August 1977.
|FR Doc 80-19516 Filed 6-27-80 8 45 am|
BILLING CODE 6SCO-01-M
IV-416
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SECTION V
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
Proposed Amendments
-------
V. PROPOSED AMENDMENTS
Subpart
A General Provisions
Definitions
D Fossil-Fuel-Fired Industrial Steam Generators
Advance Notice of Proposed Rulemaking
E Incinerators
Review of Standards
F Portland Cement Plants
Review of Standards
G Nitric Acid Plants
Review of Standards
H Sulfuric Acid Plants
Review of Standards
J Petroleum Refinery
Review of Standards
Clarification of Definition
L Secondary Lead Smelters
Review of Standards
M Secondary Brass and Bronze Ingot Production
Review of Standards
N Iron and Steel Plants, Basic Oxygen Furnace
Review of Standards
0 Sewage Treatment Plants
Review of Standards
AA Electric Arc Furnaces (Steel Industry)
Review of Standards
CC Glass Manufacturing Plants
Proposed Standards
-------
Subpart
FF
JJ
KK
NN
PP
Appendix A
Appendix B
Stationary Internal Combustion Engines
Proposed Standards
Organic Solvent Cleaners
Proposed Standards
Lead-Acid Battery Manufacture
Proposed Standards
Automobile and Light Duty Truck Surface Coating Operations
Proposed Standards
Phosphate Rock Plants
Proposed Standards
Ammonium Sulfate Manufacture
Proposed Standards
Method 12 - Inorganic Lead Emissions from Stationary Sources,
see Subpart KK
Method 23 - Halogenated Organics from Stationary Sources,
see Subpart JJ
Method 24 (Candidate 1) - Volatile Content (as Carbon) of
Paint, Varnish, Lacquer, or Related Products, see Subpart MM
Method 24 (Candidate 2) - Volatile Organic Compound Content
(as Mass) of Paint, Varnish, Lacquer, or Related Products,
see Subpart MM
Method 25 - Total Gaseous Nonmethane Organic Emissions as
Carbon: Manual Sampling and Analysis Procedure, see Subpart MM
Performance Specification 1 - Opacity Continuous Monitoring
Systems in Stationary Sources
Performance Specification 2 - S02 and NOX Continuous Monitoring
Systems in Stationary Sources
Performance Specification 3 - C02 and 02 Continuous Monitors
in Stationary Sources
Performance Specification 4 - Carbon Monoxide Continuous
Monitoring Systems in Stationary Sources
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
GENERAL PROVISIONS
SUBPART A
-------
Federal Register / Vol. 44. No. 106 / Thursday. May 31.1979 / Rule8 and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
[ 40 CFR Parts 90 *>d 61]
[FRL 1085-1]
Standards of Performance for New
Stationary Sources and National
Emission Standards for Hazardous Air
Pollutants; Definition of "Commenced"
4BENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.
SUMMARY: This action proposes an
amendment to the definition of
"commenced" as used under 40 CFR
Parts 60 and 61 (standards of
performance for new stationary sources
and national emission standards for
hazardous air pollutants). The
legislative history of the Clean Air Act
Amendments of 1977 indicates that EPA
should revise the definition of
"commenced" to be consistent with the
definition contained in the prevention of
significant deterioration requirements of
the Act. This proposal would effect that
revision.
DATES: Comments must be received on
or before July 30,1979.
ADDRESSES: Comments should be
submitted to Jack R. Farmer, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. Public comments
received may be inspected and copied
at the Public Information Reference Unit
(EPA Library) Room 2922, 401 M Street,
S.W., Washington, D.C.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number 919-
541-5271.
SUPPLEMENTARY INFORMATION: For
many of EPA's regulations, it is
important to determine whether a
facility has commenced construction by
a certain date. For instance, as provided
under section 111 of the Clean Air Act,
facilities for which construction is
commenced on or after the date of
proposal of standards of performance
are covered by the promulgated
standards. The definition of
"commenced" is thus one factor
determining the scope of coverage of the
proposed standards. "Commenced" is
currently defined under 40 CFR Part 60
as meaning:
• * * with respect to the definition of "new
source" in section lll(a)(2) of the Act that an
owner or operator has undertaken a
continuous program of construction or
modification or that an owner or operator has
entered into a contractual obligation to
undertake and complete, within • reasonable
time, a continuous program of construction or
modification.
A similar definition (minus the
reference to section lll(a)(2)) is used
under 40 CFR Part 61. As provided under
section 112 of the Act, facilities which
commence construction after the date of
proposal of a national emission
standard for a hazardous air pollutant
are subject to different compliance
schedule requirements than those
facilities which commence before
proposal.
The Clean Air Act Amendments of
1977 include a definition of
"commenced" under Part C—Prevention
of Significant Deterioration (PSD) of Air
Quality. The PSD definition of
"commenced" requires an owner or
operator to obtain all necessary
preconstruction permits and either (1) to
have begun physical on-site construction
or (2) to have entered into a binding
agreement with significant cancellation
penalties before a project is considered
to have "commenced."
On November 1,1977, Congress
adopted some technical and conforming
amendments to the Clean Air Act
Amendments of 1977. Representative
Paul Rogers presented a Summary and
Statement of Intent which stated:
In no event is there any intent to inhibit or
prevent the Agency from revising its existing
regulations to conform with the requirements
of section 165. In fact, the Agency should do
so as soon as possible. It is also expected
that the Agency will act as soon as possible
to revise its new source performance
standards and the definition of 'commenced
construction' for the purpose of those revised
standards to conform to the definition
contained in part C
In view of this background, EPA has
decided to make the definition of
"commenced" as used under Part 60
consistent with the definitions used
under the PSD requirement of Parts 51
and 52. Even though Congress did not
specify any changes to the definition
under Part 61, it is reasonable to also
change that definition to be consistent
with those under Parts 60, 51, and 52.
The manner in which the definition
would be interpreted is expressed in the
preamble to the PSD regulations 43 FR
26395-26396. For complete consistency
with the Clean Air Act and Parts 51 and
52, a new definition of "necessary
preconstruction approvals or permits"
has also been added.
EPA does not intend that sources
would be brought under the standards
by the revised definitions that would not
have been covered by the existing
definitions, The revised definitions
would be effective 30 days after
promulgation of the final definitions.
Facilities which have commenced
construction under the present
definitions before the effective date of
the revised definitions would be
considered to have commenced
construction under the revised
definitions, i.e., the revised definitions
would not be applied retroactively.
Note, however, that under the PSD
regulations, sources could be required to
apply control technology capable of
meeting the most recent standard of
performance even though that standard
is not applicable, because the applicable
standard of performance requirements
are only the minimum criteria for
granting a PSD permit.
During the public comment period,
comments are invited regarding the
impact of the revised definition. In
particular, comments are invited
regarding actual compliance problems
which may occur because of this
revision.
Dated: May 23,1979.
Douglas M. Costle,
Administrator.
It is proposed to amend 40 CFR Parts
60 and 61 by amending § § 60.2(i) and
61.02(d) and by adding §§ 60.2(cc) and
61.02(q) as follows:
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Subpart A—General Provisions
§60.2 Definitions.
(i) "Commenced" means, with respect
to the definition of "new source" in
section lll(a)(2) of the Act, either that:
(1) An owner or operator has obtained
all necessary preconstruction approvals
or permits and either has:
(i) Begun, or caused to begin, a
continuous program of physical on-site
construction of the facility to be
completed within a reasonable time; or
(U) Entered into binding agreements or
contractual obligations, which cannot be
cancelled or modified without
substantial loss to the owner or
operator, to undertake a program of
construction of the facility to be
completed within a reasonable time, or
(2) An owner or operator had
commenced construction before
(effective date of this definition) under
V-A-7
-------
Federal Register / Vol. 44. No. 106 / Thursday, May 31, 1979 / Proposed Rules
the definition of "commenced" in effect
before (effective date of this definition).
*****
(cc) "Necessary preconstruction
approvals or permits" means those
permits or approvals required under
Federal air quality control laws and
regulations and those air quality control
laws and regulations which are part of
the applicable State implementation
plan.
(Sec. 111. 301(a) of the Clean Air Act as
amended (42 U.S.C.7411, 7601(a))),
V-A-8
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
FOSSIL FUEL-FIRED STEAM GENERATORS
SUBPART D
-------
Federal Register / Vol. 44. No. 126 / Thursday. June 26. 1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 60]
[FRL 1094-6]
Standards of Performance for New
Stationary Sources; Fossll-Fuel-Flred
Industrial Steam Generators
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Advance Notice of Proposed
Rulemaking. _^__^_
SUMMARY: EPA seeks comments on its
plan to develop and implement new
source performance standards for air
pollutants from fossil-fuel-fired
industrial (non-utility) steam generators.
The Clean Air Act, as amended, August
1977, requires the EPA to develop
standards for categories of fossil-fuel-
fired stationary sources. The standards
will require application of the best
systems of emission reduction for
particulates, sulfur dioxide, and nitrogen
oxides to new industrial steam
generators.
DATES: Comments must be received on
or before August 27,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), United States Environmental
Protection Agency, 401 M Street, S.W.
Washington, D.C. 20460, ATTN: Docket
No. A79-02.
FOR FURTHER INFORMATION CONTACT:
Stanley T. Cuffe, Chief, Industrial
Studies Branch (MD-13), Emission
Standards and Engineering Division,
United States Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, (919) 541-5295.
SUPPLEMENTARY INFORMATION: In
December 1971, pursuant to Section 111
of the Clean Air Act, the Administrator
promulgated standards of performance
for particulate, sulfur dioxide, and
oxides of nitrogen from new or modified
fossil fuel fired steam generators with
greater than 250 million BTU/hour heat
input (40 CFR 60.60). Since that time, the
technology for controlling these
emissions has been improved. In August
1977, Congress adopted amendments to
the Clean Air Act which specified that
the Environmental Protection Agency
develop standards of performance for
categories of fossil-fuel-fired stationary
sources. The standards are to establish
allowable emission limitations and
require the achievement of a percentage
reduction in the emissions. EPA is
required to consider a broad range of
issues in promulgating or revising a
standard issued under Section 111 of the
Clean Air Act.
Pursuant to the requirements of the
Act, EPA developed and proposed on
September 19,1978, a revised standard
applicable to fossil-fuel-fired utility
boilers with heat input greater than 250
MM BTU/hour.
Development of Industrial Boiler
Standard
In June 1978, the Agency initiated a
program to develop standards which
would apply to all sizes and categories
of industrial (non-utility) fossil-fuel-fired
steam generators. In this program, the
Agency is studying the technological,
economic, and other information needed
to establish a basis for standards for
particulate, sulfur dioxide and oxides of
nitrogen emissions from fossil-fuel-fired
steam generators. Pertinent information
is being gathered on eight technologies
for reducing boiler emissions: oil
cleaning and existing clean oil, coal
cleaning and existing clean coal;
synthetic fuels; fluidized bed
combustion; particulate control; flue gas
desu'furization; NOx combustion
modifications; and NOx flue gas
treat.-nent. The studies for each
technology will discuss the
characteristics, emission reduction
methods and potential control costs,
energy and environmental
considerations and emission test data. A
status report on the studies was
presented to the National Air Pollution
Control Techniques Advisory
Committee (NAPCTAC), on January 11.
1979. Future presentations to the
NAPCTAC will be announced in the
Federal Register. The final technological
and economic documentation necessary
to support the standards is scheduled for
completion by June 1980. Interested
persons are invited to participate in
Agency efforts by submitting written
data, opinions, or arguments as they
may desire. The Agency is specifically
interested in information on the
following subjects.
a. Should one standard be proposed
for all industrial applications or should
standards be set for separate industrial
categories?
b. Should a single standard be
proposed for all sizes of industrial
boilers or should several standards be
proposed for various boiler size
categories?
c. Should emerging technologies such
as solvent refined coal, fluidized bed
combustion, and synthetic natural gas
be exempt from industrial boiler
standards, should they have separate
standards, or should they be required to
meet the same standards as
conventional boilers burning natural
fuels?
d. Will enforcement of standards at
cogeneration facilities present special
problems which should be considered?
e. How prevalent is the use of lignite
and anthracite coal in industrial boilers?
f. Are there special problems which
should be considered when controlling
partioulate, SO,, or NO, emissions from
combustion of lignite or anthracite
coals?
Dated: June 13,1979.
Douglas M. Costle,
Administrator.
(FR Doe. 79-20058 Filed 6-27-Tfc S.-45 amj
BILLING CODE MW-01-M
V-D-2
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
INCINERATORS
SUBPARTE
-------
Federal Register / Vol. 44, No. 229 /.Tuesday, November 27,1979 / Proposed Rules
40 CFR Part 60
[FRL 1310-2]
Standards of Performance for New
Stationary Sources: Incinerators;
Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standards.
SUMMARY: EPA has reviewed its
standard of performance for municipal
incinerators (40 CFR 60.50, Subpart E).
The review is required under the Clean
Air Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent to investigate the
establishment of a revised standard
which would be consistent with the
performance capabilities of
demonstrated best available control
technology and which would include a
limitation on the opacity of emissions
DATES: Comments must be received by
January 28, 1980.
ADDRESS: Send comments to. Central
Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street SW., Washington, D.C. 20460,
Attention: Docket A-79-18. Comments
should be submitted in duplicate if
possible.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, Telephone: (919) 541-
5271. The document "A Review of
Standards of Performance for New
Stationary Sources—Incinerators"
(EPA-450/3-79-009) is available upon
request from Mr. Robert Ajax (MD-13),
Emission Standards and Engineering
Division, U.S. Environmental Protection
Agency, Research Triangle Park. N.C
27711.
SUPPLEMENTARY INFORMATION:
Background
N'evv Source Performance Standards
(\SPS) for incinerators were
promulgated by the Environmental
Protection Agency on December 23, 1971
(40 CFR 60.50, Subpart E). These
standards regulate the emission of
particulate matter to the atmospheie
from municipal solid waste incinerators
having charging rates greater than 45 Mg
(50 tons) per day. These regulations
apply to any affected facility which
commenced construction or
modification after August 17,1971
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. Following adoption of the
Amendments, EPA contracted with the
MITRE Corporation to undertake a
review of the municipal incinerator
industry and the current standard. The
MITRE review was completed in March
1979. This notice announces EPA's
decision regarding the need for revision
of the standard. Comments on the
results of this review and on EPA's"
decision are invited.
Findings
Industry Status: In 1972 there were 193
incinerator plants operating in the U.S.
By 1977 this number had decreased to
103 plants which include a total of 252
furnaces and a total solid waste
disposal capacity of about 36,000 Mg/
day (40,000 tons/day). The estimated
national particulate emissions from
municipal incineration in 1975 were
between 60,000 and 100,000 tons or
between 0.4 and 0.6 percent of all
particulate emissions in the U.S.
Since 1971 five new incinerator
facilities involving a total of eighfnew
furnaces with a combined capacity of
2,700 Mg/day (2,970 tons/day) have
become operational. In 1978,17 cities
were identified where new incinerators
are planned or under construction. Both
existing units and the units which are
planned or under construction are
concentrated primarily in the Northeast
and Midwest.
Coincineration: A factor having an
increasingly important impact on the use
of incineration as a waste disposal
process is the increasing cost of energy
and the relatively new concept of
resource recovery not only for recycling
of material but also for utilization of the
energy content of solid waste as a
processed fuel source. A recent survey
indicates that there are at least 28
resource recovery systems in operation,
under construction, or in the final
contract stage. Total capacity of these
operations will be about27,000 Mg/day
(30,000 tons/day), or about three-fourths
of the current installed incinerator
capacity. For the most part, these
systems are characterized by
substantial processing of solid waste
into usable recycled material and a
homogenous fuel.
The processing of solid waste prior to
combustion is a growing trend that has
implications in the definition of
incineration and the applicability of the
standard. Refuse derived fuel (RDF) may
be used in an industrial or utility boiler
which may or may not be located at the
new solid waste processing center.
Similarly, RDF may be used to provide
fuel for incinerating sewage sludge in a
fluidized bed reactor. Such
coincineration of municipal solid waste
and sewage sludge has been practiced
in Europe for several years and on a
limited scale in the U.S. Where energy
resources are scarce and land disposal
is economically or technically
"unfeasible, the recovery of the heat
content of dewatered sludge as an
energy source will become more
desirable. Due to the institutional
commonality of these wastes and
advances in the preincineration
processing of municipal refuse to a
waste fuel, many communities may find
joint incineration in energy recovery
incinerators an economically attractive
alternative to their waste disposal
problems.
Coincineration of municipal solid
waste and sewage sludge as described
above is not explicitly covered in 40
CFR 60. The particulate standard for
municipal solid waste described in
Subpart E (0.18 grams/dscm or 0.08
grains/dscf at 12 percent CO2) applies to
the incineration of municipal solid waste
in furnaces with a capacity of at least 45
Mg/day (50 tons/day). Subpart 0, the
particulate standard for sewage sludge
incineration (0.65 grams/kg dry sludge
input or 1.3 Ib/ton dry sludge), applies to
any incinerator that burns sewage
sludge with the exception of small
communities practicing coincineration.
When coincineration is practiced,
determination of the applicability of the
two standards is made by EPA's Office
of Enforcement according to policies
which are described in the information
document identified at the beginning of
this notice. Such determinations ere not
straight forward, however, due to the
differing form of the two standards and
the relative stringency which, in terms
of particulate matter concentration or
grain loading, differs by a factor of more
than two.
Particulate Matter Emissions and
Control Technology
Control systems on municipal
incinerators have evolved from the use
of simple settling chambers which
remove large particles, to the use of
electrostatic precipitators (ESPs) that
remove up to 99 percent of all
particulate matter. Many of the
incinerators constructed prior to 1971
utilized mechanical cyclone collectors
with removal efficiencies in the range of
60 to 80 percent. Various scrubber
techniques including the submerged
entry of gases, the spray wetted-wall
cyclone, and the venturi scrubber were
also employed. High efficiency
electrostatic precipitators were utilized
in a limited number of cases.
Since the adoption in 1971 of the new
source performance standard, the
control device which has been most
widely used and which has been most
V-E-2
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Federal Register / Vol. 44. No. 229 / Tuesday. November 27, 1979 / Proposed Rules
effective is the electrostatic precipitator
A limited number of venturi scrubbers
and, in one case, a fabric filter have also
been employed.
In this review of the standard, a total
of 19 emission tests were identified
which had been performed on 14
incinerators. The control equipment on
these incinerators was designed to
comply with the Federal new source
performance standard for particulate
matter or State or local standards which
are as stringent or more stringent than
the NSPS. The emission tests in each
case were performed with EPA Method
5. A summary of the test results is
provided in Table 1.
Table \.-Munapal Incinerator Test Results
Stale
City/name
(Tons/day)
Control
Test results
Massachusetts
Massachusetts
Tennessee . .
Virginia
Utah . ..
District ol Columbia ...
Ntmois
Maryland
Pennsylvania
Pennsylvania
Illinois
Kentucky
Wisconsin
Rhode Island
Nashville
Norfolk (Navy)
Ogden-3
Washington . .
Chicago NW
EC Philadelphia.
NW Philadelphia
Calumet
Louisville
Sheboygan Falls
Pawlucket .
The results shown in Table 1 indicate
that ESP control technology is capable
of limiting emissions to the values well
below the 0.18 g/dscm (0.08 gr/dscf)
level at 12 percent COj. Specifically, the
results from 11 tests performed at 9
facilities employing electrostatic
precipitators showed results ranging
from 041 to 0.14 g.dscm (0.018 to 0.06 gr/
dscf) at 12 percent CO2; 10 of the 11
were below 0.114 g/dscm (0.05 gr/dscf)
The Baltimore Number 4 incinerator
emission control system meets the strict
Maryland standard for incinerators of
0.07 g/dscm (0.03 gr/dscf] at 12 percent
CO2. Similarly, the Saugus,
Massachusetts, facility was designed for
the State standard of 0.11 g/dscm (005
gr/dscf) at 12 percent CO-i and was
successfully tested at this level of
compliance.
The use of scrubbers on municipal
incinerators has met with mixed results
and an overall difficulty in complying
with the particulate emission standard
Although the data obtained from five
tests at three venturi scrubber-
controlled sources ranged from 0.015 to
0.166 g/dscm (0.046 to 0.0775 gr/dscf).
the scrubber performance results, which
are discussed in more detail in the
information document, indicate that
venturi scrubbers for control of
municipal waste particulate emissions
may involve considerable risk of
nonattainment of the current NSPS. The
150
600
360
280
150
200
400
300
300
300
200
200
30-90
200
FF
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
VS (15)
VS (15-18)
S(7-8|
VS (35-40)
(Gr/dscf at
12 pet CO,)
0024
0049
0016
005
0045
0 040/0 06
0 030/0 050
0025
0047
0046
0 046/0 049
005/006
011
0416
00775
Year
1975
1976
1976
1976
1974
1973
1971/75
1976
1977
1976
1974
1976
1977
1976
1976
Pawtucket facility venturi scrubber, for
example, operates at pressure drops
higher than the original design to barely
meet the standard of 0.18 g/dscm (0.08
gr/dscf) at 12 percent CO2.
The Sheboygan Falls, Wisconsin,
incinerator utilizes a spray chamber
with baffles. Although reportedly
designed to meet a 0.08 gr/dscf
standard, this type of control technology
would not normally be expected to
exhibit the control efficiency necessary
to obtain the standard.
Since 1971, only the East Bridgewater,
Massachusetts, facility has been tested
with a fabric filter control device. In
1975, that facility tested at 0.054 g/dscm
(0.024 gr/dscf) at 12 percent CO2, well
below the Massachusetts standard of
0.11 g/dscm (0.05 gr/dscf) at 12 percent
CO2. However, problems of bag and
baghouse corrosion and periodic high
opacity observations have persisted
Currently, Framingham,
Massachusetts, \a the only other
municipal incinerator facility with a
fabric filter control system. The
specially coated bags are designed to
prevent deterioration and to achieve
0.07 g/dscm (0.03 gr/dscf) at 12 percent
CO,.
Gaseous and Trace Metal Emissions
Gaseous and trace metal emissions
are not specifically controlled under the
present NSPS although the incinerator
and the particulate matter control
equipment do limit such emissions.
Among possible gaseous emissions, the
potential for high levels of hydrochloric
acid (HCL) from the increased
incineration of poly vinyl chlorides has
received particular attention. Similarly.
lead and cadmium have been subject to
several studies. Cadmium emissions are
reported to represent approximately 0.2
percent of all particulate emissions and
about 0.4 percent of emissions less than
2 microns. Lead concentrations are
reported to represent about 4 percent of
all particulate matter and 11 percent of
respirable particulates emitted from the
scrubber. Emission factors are 9X10~'
kg/Mg (18X10'Mb/ton) refuse for
cadmium and 1.9X10"'kg/Mg (3.8X10"'
Ib/ton) refuse for lead.
In this review of the current NSPS no
new findings were identified which
indicate the need for a specific,
nationally applicable limitation on the
gaseous or trace metal emissions. There
is, however, currently a program
underway within EPA to independently
look at the need to regulate cadmium
from incinerators and other sources.
Separate documents have been prepared
which examine emissions, resulting
atmospheric concentrations, and
population exposure. These documents
are part of an overall EPA program to
satisfy requirements of the 1977 Clean
Air Act to evaluate the need to regulate
emissions of cadmium to the air.
Opacity
The current NSPS does not contain a
standard for opacity because testing of a
limited number of incinerators priot to
promulgation of the standard in 1971 did
not indicate a consistent relationship
between emission opacity and
particulate mass concentrations.
However, a survey of current State
regulations shows that every State has
an opacity standard for new
incinerators of 20 percent or stricter
except Illinois (30 percent), Indiana (40
percent), and Delaware (no standard)
Maryland has a "no visible emissions"
standard and the District of Columbia
has a new source ban on the
incineration of municipal waste.
However, data were not found in this
review of the NSPS to determine
whether sources are consistently in
compliance with these limits.
Conclusions
Based upon a review of the current
NSPS and other available information as
summarized above, EPA concludes that
there is a need to undertake a program
to revise the standard. This program,
which is expected to begin in FY 1980,
will be directed toward:
V-E-3
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Federal Register / Vol. 44. No. 229 / Tuesday, November 27,1979 / Proposed Rules
(1) Investigation of a more restrictive
particulate matter limitation consistent
with the capabilities of the best
available technology. This is based upon
the available data which indicate that
the capability of electrostatic
precipitators applied to incinerators has
improved measurably since the standard
was developed in 1971. This
investigation will include analysis of the
costs associated with a more restrictive
standard.
(2) Establishment of an opacity
standard. Such a standard is considered
important by EPA as a means for
assessing proper operation and
maintenance of particulate matter
control equipment and is included in
most of the Agency's particulate matter
NSPS. Although a relationship between
particulate mass and opacity was not
established when the standard was
adopted in 1971, the additional number
of well controlled plants which are now
in operation and the widespread
existence of State opacity limits are
expected to provide a basis for
estalishment of an opacity standard.
Consistent with EPA policy, such a
standard would not be more restrictive
than the particulate mass standard.
(3) Establishment of a consistent basis
for the limitation of particulate
emissions from differing combustion
devices independent of the fuel or waste
material being fired. While a single
standard is probably not possible, there
is a need to investigate the possibility of
expressing standards for sludge
incinerators, and municipal incinerators
on a common basis, and of making the
standards more uniform. To do so, EPA
plans to closely coordinate the
development of the industrial and
waste-fired boiler standards which are
now underway, and the planned
revision of the sewage sludge
incinerator standard and the municipal
incinerator standard.
(4) In addition, if the need to reduce
cadmium emissions is indicated as a
result of the EPA program noted above,
appropriate action will be taken to limit
cadmium emissions.
Public Participation
All interested persons are invited to
comment on this review, the conclusions
and EPA's planned action.
Dated November 16, 1979.
Barbara Blum,
Acting Administrator
|FR Doc 79-36474 Filed 11-26-79 845 dm]
V-E-4
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PORTLAND CEMENT PLANTS
SWMRT F
-------
Federal Register / Vol. 44. No. 205 / Monday October 22. 1979 / Proposed Rules
40 CFR Part 60
Standards of Performance for New
Stationary Sources: Portland Cement
Plants; Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standards of performance for portland
cement plants (40 CFR 60.60). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
that, based on an assessment of the
industry, applicable control technology,
and results of performance tests
conducted pursuant to the standard,
EPA has determined that no revision to
the particulate emission limitation is
needed but that the standard should be
revised to require continuous opacity
monitoring.
DATES: Comments must be received by
December 21,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. A-79-19.
The document, "A Review of
Standards of Performance for New
Stationary Sources—Portland Cement
Industry" (EPA-450/3-79-012), is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
On August 17,1971, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate matter emissions
from portland cement plants. The
standard, promulgated on December 23,
1971, applies to any facility constructed
or modified after August 17,1971, which
manufactures portland cement by either
the wet or dry process. Specific affected
facilities are the: kiln, clinker cooler,
raw mill system, finish mill system, raw
mill dryer, raw material storage, clinker
storage, finished product storage,
conveyor transfer points, bagging, and
bulk loading and unloading and
unloading systems.
The standard prohibits the discharge
into the atmosphere from any kiln any
gases which:
1. Contain particulate matter in excess
of 0.15 kg/Mg (0.30 Ib/ton) feed to the
kiln, or
2. Exhibit greater than 20 percent
opacity.
The standard prohibits the discharge
into the atmosphere from any clinker
cooler any gases which:
1. Contain particulate matter in excess
of 0.050 kg/Mg (0.10 li/ton) feed (dry
basis) to the kiln, or
2. Exhibit 10 percent opacity or
greater.
The standard prohibits the discharge
into the atmosphere from any affected
facility other than the kiln and clinker
cooler any gases which exhibit 10
percent opacity, or greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll[b)(l)(B)]. This notice announces that
EPA has undertaken a review of the
standard of performance for portland
cement plants. As a result of this review,
EPA has concluded that the present
particulate emission limit is appropriate,
and does not need revision. However, a
provision to require opacity monitoring
should be added. In addition, EPA is,
however, planning to undertake a
program, in its Office of Research and
Development, to investigate and
demonstrate methods such as
combustion modifications which could
reduce NO, emissions from combustion
used in process sources such as cement
plants. Positive results from this
program would form the basis for a
possible revision to the standard in 1982
or 1983. Comments on these findings and
plans are invited.
Findings
Industry Status
Capacity. There are currently 53
cement companies producing portland
cement in the U.S. The 53 companies
operate 158 cement plants throughout
the U.S. with single plant capacity
ranging from 50,000 Mg to 2,161,000 Mg
per year. The industry also includes 8
plants with only clinker grinding
facilities which use either an imported
or domestic clinker as feed material.
Cement plants are found in nearly every
State because of the high cost of
transportation. The actual clinker
capacity of these plants is also
distributed throughout the U.S., although
some regions have little capacity due to
a lack of demand; and although many
areas of the Country are presently
experiencing cement shortages and
delays, announced capacity increases in
these areas are still small.
Energy Considerations. The portland
cement industry is very energy intensive
with energy costs accounting for
approximately 40 percent of the cost of
cement. Accordingly, significant
emphasis in the industry is on increasing
energy efficiency. For this reason,
almost all new and planned construction
will use the dry process which can be
twice as energy efficient as the wet
process. Additional savings can be
realized by using preheaten, ••ptdaBy
suspension preheaten.
These process change* have both
positive and negative effect! on
particulate emissions. The replacement
of wet process units with dry process
units increases potential emissions,
particularly in the grinding, mixing,
blending, storage, and feeding of raw
materials to the kiln. The suspension
preheater, on the other hand, tends to
decrease particulate emissions due to its
multicyclone construction. It also
ensures more thorough contact of the
kiln exhaust gases with the feed
material which may increase sorption of
sulfur oxide from the exhaust on the
feed.
Economic Considerations. Almost aH
cement produced is utilized by the
construction industry. As a result, the
production of cement follows the
cyclical pattern of the construction
industry. Relatively high cement
production has occurred during periods
of growth in new home and other
construction markets, and production
has decreased in such periods of
recession as occurred in 1973-1975.
In contrast, over the short term,
production capacity has not closely
paralleled actual production. This is due
apparently to the lead time required to
add capacity, to the difficulty in
accurately predicting future demand,
and to economic and other factors
including the effect of pollution control
requirements on the closure of old,
marginal plants.
An examination of production and
capacity over the past 10 years suggests
the difficulty which the industry has
experienced in attempting to meet
demand while avoiding excess capacity.
In the early 1970's, utilization of
production capacity was greater than 90
percent. However, wage and price
controls were in effect from 1971 to 1973
during which time the industry
experienced its lowest profit margin
since the 1930's. New plant construction
was postponed while some older plants
were being closed. As a result, regional
cement shortages occurred in 1972-1973.
When price controls were removed in
V-F-2
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Federal Register / Vol. 44. No. 205 / Monday, October 22, 1979 / Proposed Rules
1973, the price of cement jumped 14
percent and some new capacity
construction was begun. Shortly
thereafter, the Country entered a
recession and cement production fell to
70 percent of capacity.
The cyclic occurrence of high demand
exceeding capacity has been evidenced
again in the past several years. The
rapid growth in the construction
industry since 1975 has increased the
demand for cement and parts of the U.S.
have seen shortages, particularly in the
West. At the »ame time, the industry has
not rapidly added new capacity.
although mt Bureau of Mines project*
high demand in the early 1980's.
In considering whether pollution
control costs influenced the recent lag in
capacity, die Council on Wage and Price
Stability concluded that:
... ttw added pollution control cost* do
change the way a firm would consider a new
investment decision by »«aHrig larger price
increases necessary for the expenditure* to
be committed, this does not mean that the
imposition of these controls has necessarily
cause any reduction in new capacity
expenditure* in the cement industry.
However, this analysis does leave open the
possibility that aa investment decision could
be changed for a marginal plant because of
pollution control cost* (particularly a plant
selling cement for $40 per ton and using a 12
percent rate of return). (Prices and Capacity
Expansion in the Cement Industry, Council
on Wage and Price Stability, Washington,
B.C., 1977.)
Since cement is already selling for as
high as $53 per ton on the West Coast, it
is very likely that capital investment
will not be stifled by pollution control
expenditures.
Emission Control Status
Fifty-one cement kilns and clinker
coolers have been identified which are
operating and are subject to the new
source performance standard. Of these,
49 are in compliance with 0.15 kg/Mg
kiln feed (kiln) and 0.05 kg/Mg kiln feed,
(cooler) emission limit*. One completed
kiln has only recently been tested and
data are not available; and one facility
has notified its State authority that it
cannot meet the standards. Also, five
cement kilns potentially subject to the
standard were identified for which data
were not available. The number of
sources with other NSPS-affected
facilities was not determined, although
there are none reported that are not in
compliance with the applicable 10
percent opacity standard.
For the 29 kilns and 20 clinker cooler*
which were in compliance, the kiln test
results averaged 0.073 kg/Mg and
ranged from a high of 0.142kg/Mg feed
to a low of 0.013kg/Mg feed. The range
for kilns with emissions controlled by
ESP is 0.142 to 0.020 kg/Mg, and for kilns
with fabric filter baghouses the range is
0.132 to 0.013 kg/Mg dry kiln feed. The
data indicate that neither the ESP nor
the baghouse is significantly better at
controlling cement kiln particulate
matter emissions.
Cement plant clinker coolers have
been tested at emission levels ranging
from a high of 0.061 kg/Mg to a low of
0.005 kg/Mg dry kiln feed with a mean
of 0.024 kg/Mg. Compliance test data on
a single wet scrubber show emissions
near the mean emission level for fabric
filter baghouse controls (0.022 kg/Mg).
Data for affected facilities using gravel
bed filters indicate a mean emission
level of 0.034 kg/Mg dry feed (0.023-
0.045kg/Mg).
The compliance test data were
analyzed to determine if the type of
control technology, the process type (i.e.,
wet or dry), or Interaction of process
type and control technology affected the
ability to control the emission of
particulate matter from portland cement
kilns or clinker coolers. This analysis
indicates that no control technology in
use today is more effective for
controlling particulate matter emissions.
Although comparison of mean values
Indicates that the possibility that
emissions from dry process kilns are
controlled slightly more effectively than
wet process kilns, the difference is not
statistically significant
Nitrogen Oxide Emissions
Cement kilns are a very large and
presently unregulated source of nitrogen
oxides (NO.) emissions. Based upon
estimated NO. emissions of 1.3 kg/Mg of
cement produced and 71.4 million Mg of
portland cement produced in 1977, an
estimated 93,000 Mg of NO, were
emitted by portland cement plants that
year. The main factors that result in the
production of NO. are the flame and kiln
temperature, the residence time that
combustion gases remain at this
temperature, the rate of cooling of these
gases, and the quantity of excess air in
the flame. Control of these factors may
permit the operator to sharply reduce
the emission of NOr but such practices
have not been demonstrated in cement
plants for NO, emissions.
Opacity Monitoring
When the NSPS for portland cement
plants was established in 1971 no
provisions were included to require
continuous monitoring of opacity. This
was, in part, because the presence of
water vapor in the exhaust gases from
wet-process facilities would affect
monitor accuracy. In addition,
monitoring systems had not been
demonstrated at baghouse controlieJ
facilities where stack gases are emitted
from roof monitors or multiple stub
stacks. However, since the standard
was adopted, a monitoring system has
been demonstrated at a steel plant
utilizing baghouse controls and stub
stacks.
Conclusions
On the basis of the findings which are
summarized above, EPA has concluded
that the current particulate matter
standards are appropriate and effective
and that no revision is needed. While
the compliance test data do show that
the mean results are well below the
standards, the range of data suggest that
the standard is set at a level which
reflects the performance of the best
systems of emission reduction.
However, it is concluded that the
standard should be revised to include
provisions requiring the continuous
monitoring of opacity. This conclusion is
based upon the demonstration of
opacity monitors on baghouse stub
(lacks and on the shift in the portland
cement industry toward the dry process,
as well as EPA's belief that continuous
monitoring represents an important and
effective means for assuring proper
operation and maintenance of
particulate matter control equipment.
Adoption of any opacity monitoring
requirement will be preceded by a
proposal and the opportunity for public
comment. The Agency expects to
undertake development and to propose
this revision during 1980.
It is also concluded that the lack of
demonstrated control technology and an
emission limitation for NO, is an
important deficiency. The Agency is
therefore planning to evaluate, develop,
and demonstrate means for limiting NO,
emissions. This program, which will
include other industrial process fuel
users, will be aimed at transferring
technology being employed to control
NO, emissions from steam generators If
this proves successful, the results will be
used as a basis for development of NO,
standards.
Public Participation
All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Dated October 16, 1979
Douglas M. Costle.
Administrator
|FR Doc 79-32M6 Fifed !0-l<»-?» 8 45 am]
V-F-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
NITRIC ACID PLANTS
SUBPART G
-------
Federal Register / Vol. 44, No. 119 / Tuesday, June 19, 1979 / Proposed Rules
[40 CFR Part 60]
[FRL 1095-1]
Review of Standards of Performance
for New Stationary Sources: Nitric
Acid Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standards.
SUMMARY: EPA has reviewed the
standard of performance for nitric acid
plants. The review is required under the
Clean Air Act, as amended August 1977.
The purpose of this notice is to
announce EPA's intent not to undertake
revision of the standards at this time.
DATES: Comments must be received on
or before August 20,1979.
ADDRESSES: Send comments to the
Central Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street, S.W., Washington, D.C. 20460,
Attention: Docket No. A-79-08. The
document "A Review of Standards of
Performance for New Stationary
Sources—Nitric Acid Plants" (EPA
report number EPA-450/3-79-013) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, (919) 541-5271.
SUPPLEMENTARY INFORMATION:
Background
Prior to the promulgation of the NSPS
in 1971, only 10 of the existing 194 weak
nitric acid (50 to 60 percent acid)
production facilities were specifically
designed to accomplish NO, abatement.
V-G-2
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Federal Register / Vol. 44, No. 119 / Tuesday, June 19, 1979 / Proposed Rules
Without control equipment, total NO,
emissions are approximately 3,000 ppm
in the stack gas, equivalent to a release
of 21.5 kg/Mg (43 Ib/ton) of 100 percent
acid produced.
At the time of the NO, New Source
Performance Standard (NSPS)
promulgation there were no State or
locat NO, emission abatement
regulations in effect in the U.S. which
applied specifically to nitric acid
production plants. Ventura County,
California, had enacted a limitation of
250 ppm NO, to govern nitric acid plants
as well as steam generators and other
sources.
In August of 1971, the EPA proposed a
regulation under Section 111 of the
Clean Air Act to control nitrogen oxides
emissions from nitric acid plants. The
regulation, promulgated in December
1971, requires that no owner or operator
of any nitric acid production unit (or
"train") producing "weak nitric acid"
shall discharge to the atmosphere from
any affected facility any gases which
contain nitrogen oxides, expressed as
NOj, in excess of 1.5 kg per metric ton of
acid produced (3.0 Ib per ton), the
production being expre*sed as 100
percent nitric acid; and any gases which
exhibit 10 percent opacity or greater.
The Clean Air Act Amendment* of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of the
standard of performance for nitric acid
plants and invites comment on the
results of this review.
Findings
Industry Growth Rate
The average rate of production
increase for nitric acid fell from 9
percent/year in the 1960-1970 period to
0.7 percent from 1971 to 1977. The
decline in,demand for nitric acid
parallels that for nitrogen-based
fertilizers during the same period.
Nitric acid production shows an
increasing trend toward plant/unit
location and growth in the southern tier
of States. In 1971,48 percent of the
national production was in the south.
This figure increased to 54 percent in
1976.
About 50 percent of plant capacity in
1972 consisted of small to moderately
sized units (50 to 300-ton/day capacity).
Because of the economies of scale some
producers are electing to replace their
existing units with new, larger units.
New nitric acid production units have
been built as large as 910 Mg/day (1000
tons/day). The average size of new units
is approximately 430 Mg/day (500 tons/
day).
Control Technology
A mixture of nitrogen oxides (NO,) is
present in the tail gas from the ammonia
oxidation process for the production of
nitric acid. In modern U.S. single
pressure process plants producing 50 to
60 percent acid, uncontrolled NO,
emissions are generated at the rate of
about 21 kg/Mg of 100 percent acid (42
Ib/ton) corresponding to approximately
3000 ppm NO, (by volume) in the exit
gas stream. The catalytic reduction
process which was considered the best
demonstrated control technology at the
time the present standard was
established has been largely supplanted
by the extended absorption process as
the preferred control technology for NO,
emissions from new nitric acid plants.
The latter control system appears to
have become the technology of choice
for the nitric acid industry due to the
increasing cost and danger of shortages
of natural gas us«d in the catalytic
reduction process. Since the energy
crisis of the mid-1970's, over 50 percent
of the nitric acid plants that had come
on stream through mid-1978 and almost
90 percent of the plants scheduled to
come on stream through 1979 use the
extended absorption process for NO,
control.
Levels Achievable with Demonstrated
Control Technology
All 14 of the new or modified
operational nitric acid production units
subject to NSPS and tested showed
compliance with the current standard of
1.50 kg/Mg (3 Ib/ton). The average of
seven sets of test data from catalytic
reduction-controlled plants is 0.22 kg/
Mg (0.44 Ib/ton), and the average of six
sets of test data from extended
absorption-controlled plants is 0.91 kg/
Mg (1.82 Ib/ton). All of the plants tested
were in compliance with the opacity
standard. It appears that the extended
absorption process, while it has become
the preferred control technology for NO,
control, cannot control these emissions
as efficiently as the catalytic reduction
process. In fact, over half of the test
results for extended absorption were
within 20 percent of the NO, standard.
The extended absorption process thus
appears to have limitations with respect
to NO, control, and compares
unfavorably with catalytic reduction in
its ability to reduce NO, emissions much
below the present NSPS level.
Economic Considerations Affecting the
t NSPS
The anhualized costs of the extended
absorption process and the catalytic
reduction NO, control methods appear
to be quite comparable. Capital cost for
the extended absorption process is
appreciably higher than that for
catalytic reduction. However, this is
offset by the higher operating cost of the
latter system which requires
increasingly costly natural gas.
Conclusions
Based on the above findings, EPA
concludes that the existing standard of
performance is appropriate at this time,
While lower emission levels are
attainable, the energy penalty and
shortages of natural gas are concluded
to be a basis for retaining the current
standard of performance under Section
111 of the Clean Air Act. However, the
recent deregulation will alter the price
•nd availablity of natural gas, and
provides a basis for optimism about its
future availability for process and
pollution control purposes. The Agency,
therefore, plans to continue to assess the
standard as, the effect of deregulation
materializes. Moreover, it should be
noted that for the purpose of attaining
and maintaining national ambient air
quality standards and prevention of
significant deterioration requirements,
State Implementation Plan new source
reviews may in come cases require
greater emission reductions than those
required by the standards of
performance for new sources.
Public participation
All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Comments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmenal Protection Agency,
Research Triangle Park, North Carolina
27711.
Dated: June 11, 1979.
Douglas M. Costle,
Administrator.
[FR Doc. 78-19002 Filed 6-18-79; 8:45 am]
BILLING CODE (MO-01-M
V-G-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
SULFUBIC ACIO PLANTS
SUBPART H
-------
PROPOSED RULES
NEW STATIONARY SOURCES: SULFURIC ACID
PLANTS
Review of Performance Standard!
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standards of performance for sulfuric
acid plants (40 CFR 60.80). The review
is required under the Clean Air Act, as
amended August 1977. The purpose of
this notice is to announce EPA's deci-
sion to not revise the standards at this
time and to solicit comments on this
decision.
DATES: Comments must be received
by May 14,1979.
ADDRESS: Send comments to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, North Carolina
27711.
FOR FURTHER
CONTACT:
INFORMATION
Mr. Robert Ajax. telephone: (919)
641-5271. The document "A Review
of Standards of Performance for
New Stationary Sources—Sulfuric
Acid Plants" (EPA report number
EPA-450/3-79-003) is available upon
request from Mr. Robert Ajax (MD-
13), Emission Standards and En-
gineering Division, Environmental
Protection Agency, Research Trian-
gle Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:
BACKGROUND
Prior to the proposal of the standard
of performance in 1971, almost all ex-
isting contact process sulfuric acid
plants were of the single-absorption
design and had no SO* emission con-
trols. Emissions from these plants
ranged from 1500 to 6000 ppm SO, by
volume, or from 10.8 kg of SO2/Mg of
100 percent acid produced (21.5 lb/
ton) to 42.5 kg of SO,/Mg of 100 per-
cent acid produced (85 Ib/ton). Several
State and local agencies limited SO,
emissions to 500 ppm from new sulfu-
ric acid plants, but few such facilities
had been put into operation (EPA,
1971).
In August of 1971, the Environmen-
tal Protection Agency (EPA) proposed
a regulation under Section 111 of the
Clean Air Act to control SOa and sul-
furic acid mist emissions from sulfuric
acid plants. The regulation, promul-
gated in December 1971, requires that
no owner or operator of any new sul-
furic acid production unit producing
sulfuric acid by the contact process by
burning elemental sulfur, alkylation
acid, hydrogen sulfide, organic sul-
fides, mercaptans, or acid sludge shall
discharge into the atmosphere any
gases which contain sulfur dioxide in
excess of 2 kg/Mg (4 Ib/ton); any gases
which contain acid mist, expressed as
H^SO,. in excess of 0.075 kg/Mg of
acid produced (0.15 Ib/ton), expressed
as 100 percent HjSO4; or any gases
which exhibit 10 percent opacity or
greater. Facilities which produce sul-
furic acid as a means of controlling
SOj emissions are not'included under
this regulation.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of per-
formance for new stationary sources
at least every 4 years [Section
lll(bXlXB)]. This notice announces
that EPA has completed a review of
the standard of performance for sulfu-
ric acid plants and invites comment on
the results of this review.
FINDINGS
INDUSTRY GROWTH
Since the proposal, 32 contact proc-
ess sulfuric acid units have been con-
structed. Of these, at least 24 units
result from growth in the phosphate
fertilizer industry and are dedicated to
the acidulation of phosphate rock,
mainly in the Southern U.S.
In 1976, over 70 percent of the total
national production of new sulfurio
acid was in the South. It is projected
that three of the four units predicted
to be coming on line each year will
most probably be located in the South.
BEST DEMONSTRATED CONTROL
TECHNOLOGY
Sulfur dioxide and acid mist are
present in the tail gas from the con-
tact process sulfuric acid production
unit. In modern four-stage converter
contact process plants burning sulfur
with approximately 8 percent SO2 in
the converter feed, and producing 98
percent acid, SOa and acid mist emisi-
sions are generated at the rate of 13 to
28 kg/Mg of 100 percent acid (26 to 56
Ib/ton) and 0.2 to 2 kg/Mg of 100 per-
cent acid (0.4 to 4 Ib/ton), respectively.
The dual absorption process is the
best demonstrated control technology
for SOj emissions from sulfuric acid
plants, while the high efficiency acid
mist eliminator is the best demonstrat-
ed control technology for acid mist
emissions. These two emission control
systems have become the systems of
choice for sulfuric acid plants built or
modified since the promulgation of
the NSPS. Twenty-eight of the 32 sul-
furic acid production plants subject to
the standard incorporate the dual ab-
sorption process; all 32 plants use the
high efficiency acid mist eliminator.
COMPLIANCE TEST RESULTS
All 32 sulfuric acid production units
subject to the standard showed com-
pliance with the current SO, standard
of 2 kg/Mg (4 Ib/ton). The 29 compli-
ance test results for dual absorption
plants ranged from a low of 0.16 kg/
Mg (0.32 Ib/ton) to a high of 1.9 kg/
Mg (3.7 Ib/ton) with an average of 0.9
kg/Mg (1.8 Ib/ton). Information re-
ceived on the performance of several
sulfuric acid plants indicates that low
SO, emission results achieved in NSPS
compliance tests apparently do not re-
flect day-to-day SO, emission levels.
These levels appear to rise toward the
standard as the conversion catalyst
ages and its activity drops. Additional-
ly, there may be some question about
the validity of low SO, NSPS values,
i.e., less than 1 kg/Mg (2 Ib/ton), due
to errors in the application of the
original EPA Method 8. This method
was revised on August 18, 1977, to in-
clude more detailed procedures to pre-
vent such errors.
All 32 affected sulfuric acid produc-
tion units also showed compliance
with the current acid mist standard of
0.075 kg/Mg of 100 percent acid (0.15
Ib/ton). The compliance test data are
all from plants with acid mist emission
control provided by the high efficien-
KDERAL REGISTER, VOL 44, NO. 52—THURSDAY, MARCH 15, 1979
V-H-2
-------
cy acid mist eliminator. The data
showed a range with a low of 0.008 kg/
Mg (0.016 Ib/ton) to a high of 0.071
kg/Mg (0.141 Ib/Con), and an overall
average value of 0.04 kg/Mg (0.081 lb/
ton). Acid mist emission (and related
opacity) levels are unaffected by fac-
tors affecting SO, emissions, i.e., con-
version efficiency and catalyst aging.
Rather, acid mist emissions are pri-
marily a function of moisture levels in
the sulfur feedstock and air fed to the
sulfur burner, and the efficiency of
the final absorber operation. The
order-of-magnitude spread observed in
compliance test values is probably a
result of variation in these factors. Ad-
ditionally, the potential for impreci-
sion in the application of the original
EPA Method 8 may have contributed
to this spread.
POSSIBLE REVISION TO STANDARD
The compliance test data indicate
that the available control technology
could possibly meet both lower sulfur
dioxide and sulfuric acid mist emission
standards. However, the available test
data indicate that variability in indi-
cated emission rates occurs—possibly
as a result of process variables, and
test method precision. Therefore, to
meet a tighter standard designers and
operators would need to design for at-
tainment of a lower average emission
rate in order to retain a margin of
safety needed to accommodate emis-
sion variability. The available compli-
ance data do not provide a basis for
concluding that this is possible.
In contrast, the effect of catalyst
aging is controllable by more frequent
replacement. As an outside limit, com-
plete replacement of catalyst in the
first 3 beds of a four-bed converter 3
times as frequently as is normally
practiced could potentially maintain
emissions in the range of 1 to 1.5 kg/
Mg and would result in a net emission
reduction of approximately 0.3 kg/Mg
(0.6 Ib/ton).
Based on an estimated sulfuric acid
plant growth rate of four new produc-
tion lines per year between 1981 and
1984, a 50 percent reduction of the
present SO, NSPS level—from 2 kg/
Mg (4 Ib/ton) to 1 kg/Mg (2 Ib/ton)—
would result in a drop in the estimated
SO, contribution to these new sulfuric
acid plants to the total national SO,
emissions, from 0.04 percent to 0.02
percent (8,000 tons to 4,000 tons).
CONCLUSIONS
Based upon the above findings, EPA
concludes that the current best dem-
onstrated control technology, the duel
absorption process and the acid mist
-eliminator are identical in basic design
to that used as the rationale for the
r;6riginal SO, standard. Therefore, from
*he standpoint of control technology,
and considering costs, and the small
PROPOSED RULES
quantity of emissions in question, it
does not appear necessary or appropri-
ate to revise the present standard of
performance adopted under Section
111 of the Clean Air Act. It should be
noted that for the purpose of attain-
ing national ambient air quality stand-
ards and prevention of significant de-
terioration, State Implementation
Plan new source reviews may in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources.
PUBLIC PARTICIPATION
All interested persons are Invited to
comment on this review, the conclu-
sions, and EPA's planned action. Com-
ments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
(Section 11U6X1XB) of the Clean Air Act,
as amended (42 U.S.C. 741K6X1XB)).
Dated: March 9, 1979.
DOUGLAS M. COSTLE,
Administrator.
[PR Doc. 79-7926 Filed 3-14-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. 52—THURSDAY, MARCH 15, 1979
V-H-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PETROLEUM REFINERY
SUBPART)
-------
Federal Register / Vol. 44, No. 205 / Monday October 22, 1979 / Proposed Rules
40 CFR Part 60
[FRL 1295-1]
Standards of Performance for New
Stationary Sources: Petroleum
Refineries Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed its
standard of performance for petroleum
refineries (40 CFR 60.1130, Subpart J). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent to undertake the
development of a revised standard
which would limit SO» emissions from
catalyst regenerators.
DATE: Comments must be received by
December 21,1979.
ADDRESS: Send comments to: Central
Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street, S.W., Washington, D.C. 20460,
Attention: Docket A-79-09.
The document "A Revie\v of
Standards of Performance for New
Stationary Sources—Petroleum
Refineries" (EPA-450/3-79-008) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711,
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, Telephone: (919) 541-
5371.
SUPPLEMENTARY INFORMATION:
Background
New Source Performance Standards
(NSPS) for petroleum refineries were
promulgated by the Environmental
Protection Agency on March 8, 1974. (40
CFR 60.100, Subpart J). These standards
regulate the emission of particulate
matter and carbon monoxide, and the
opacity of flue gases from fluid catalytic
cracking unit (FCCU) catalyst
regenerators and FCCU regenerator
incinerator-waste heat boilers. They
also regulate the emission of sulfur
dioxide from fuel gas combustion
devices. These regulations apply to any
affected facility which commenced
construction or modification afier June
11,1973.
The Clean Air Act Amendments of
197? require that the Administrator of
the EPA review and, if appropridte,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of thn
standard of performance for petroleum
refineries and invites comment on the
results of this review.
Findings
On the basis of a review of
compliance data available in EFA's
Regional Offices and a review of
literature describing recent control
technology applicable to cataljst
regenerators and fuel gas combustion
devices, EPA has made the following
conclusions regarding the need to rexise
the existing standard.
Particulate Matter
The available data indicate that the
current limitation on particulate matter
emissions accurately reflects the
performance capability of best available
control systems. It is, therefore,
concluded that no revision should be
made to'the particulate standard. New
technologies such as high efficiency
separators, high temperature
regenerators, and new catalysts have
•reduced the tojal quantity of
uncontrolled particulate matter emitted.
However, the method established in the
standard for calculating the allowable
emissions effectively corrects for the
reduction due to changes in catalysts
and operating procedures.
While it is concluded that the
particulate matter standard should not
be revised, a question has been raised
as to the validity of Reference Method 5
when high concentrations of
condensible sulfur compounds are
present. This test method, which is used
to measure compliance with the
particulate standard, operates at a
nominal temperature of 120°C and, as
such, is capable of collecting
condensible matter which exists in
gaseous form at stack temperature. If
significant quantities of such
condensible material exist which are not
controllable by the best systems of
emission reduction, then a facility
employing such systems could be found
to be in non-compliance with the
standard. An analysis of data available
when the standard was established
indicated this was not a problem at that
time. However, with high sulfur content
feed, there is evidence that condensible
sulfur oxides may exist at
concentrations sufficient to affect
compliance.
EPA is currently studying this
question. Depending on the results of
this study, EPA may revise the standard
or the test method.
Carbon Monoxide
The present standard for carbon
monoxide emissions was established at
a level which would permit regenerator
in situ combustion. This method of
controlling carbon monoxide emissions
offers production and energy efficiencies
but is recognized to be less effective
than a carbon monoxide boiler. No new
data were obtained during this review to
alter the original finding that it is not
practical to control CO emissions to less
than 500 ppm by in situ regeneration
and, therefore, no revision in the
standard is planned at this time.
However, it should be noted that the
recent advent and increased use of CO
oxidation catalysts and additives may
provide data showing that
concentrations lower than 500 ppm are
achievable. If such data become
available, the Agency will consider
revision of the standard. It should be
further noted that for the purpose of
attaining and maintaining the national
ambient air quality standards, State
Implementation Plan new source
reviews may,-in some cases, require
greater CO emission reductions than
those required by the standards of
performance for new sources.
At the time the standard was
established, EPA concluded that CO
emissions should be continuously
monitored. A requirement for such
monitoring was, therefore, included in
the standard. This requirement is
applicable to all catalyst regenerators
subject to the standard. However, the
effective date of the monitoring
requirement was deferred until EPA
develops performance specifications for
CO monitoring systems. EPA has found
no basis for revising this monitoring
requirement and performance
specifications are currently under
development and evaluation. It is
planned to issue an advanced notice of
proposed rulemaking in 1979 setting
forth the specifications which have been
developed and which will be assessed
in field studies.
Sulfur Dioxide
The present standard currently limits
SO> emissions resulting from the
combustion of fuel gas. The catalyst
regenerator is also a significant source
of SO? emissions but is not subject to
the standard. The review considered
both the need to revise the current
limitation and the need to include
limitations on SOi emissions from the
catalyst regenerator-
Available compliance test data
indicate that the current standard
limiting sulfur to 230 mg HaS/dscm from
combustion of fuel gas is being met and,
in some cases, exceeded by a wide
margin. Six tests showed an average of
107 mg H5S/dscm and a range of 7 to 229
mg HiS/dscm. While these data indicate
t-hat a reduction in the present limitation
V-J-2
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Federal Register / Vol. 44. No. 265 / Monday, October 22. 1979 / Proposed Rules
is possible, the range exhibited is
consistent with the control device
performance documented at the time the
standard was established. On the basis
of this, along with the increased sulfur
content of feedstock expected with
increased imports and the variable
crude oil supply conditions now
existing, it is concluded that the fuel gas
sulfur limitation is appropriate and that
no revision is needed,
A deficiency in the current standard
limiting sulfur in fuel gas relates to the
lack of a continuous monitoring method.
EPA recognized the need for continuous
monitoring at the time the standard was
adopted. However, at that time, no
monitoring systems had been
demonstrated to be adequate for this
purpose and EPA had not established
performance specifications for such
systems. Consequently, application of
the monitoring requirement was
deferred until performance
apecifications could be adopted. Since
the adoption of the standard, EPA has
pursued a program to develop and
assess the performance of an HtS
monitoring system. On this basis,
performance specifications are now
being developed. It is planned to issue
an advanced notice of proposed
rulemaking in 1979 setting forth the
specifications which have been
developed and which will be assessed
in field studies,
During the review of the standard, an
ambiguity was identifed in the current
limitation on sulfur in fuel gas
concerning the applicability of this
limitation to fuel gas burned in waste-
heat boilers. To clarify this, an
amendment was prepared which was
published in the Federal Register on
March 12,1979. This amendment makes
clear that fuel gas fired in waste-heat
boilers is not exempt from the standard.
Sulfur dioxide emissions from fluid
catalytic cracking unit (FCCU) catalyst
regenerators are not regulated by the
standard. However, sulfur dioxide
scrubber technology is available and
being used to control steam generator
emissions and a limited number of
FCCU regenerators. Also, Amoco Oil
Company has developed a new cracking
process which reduces sulfur oxide
emissions from FCCU regenerators. The
process uses a new catalyst that retains
sulfur oxides and returns them to the
reactor where they are removed with the
product stream. If a low sulfur product '.s
required, the sulfur will be removed by
amine stripping or hydrotreating and
eventually recovered in a sulfur
recovery unit. Pilot tests indicate that
the new catalyst is capable of reducing
sulfur oxide emissions 80 to 90 percent
and commercial tests are planned to
confirm these data.
The potential uncontrolled emissions
from new, modified, or reconstructed
catalyst regenerators are significant.
Uncontrolled emission rates from
catalyst regenerators are typically 5 to
10 Mg/day and range up to 100 Mg/day
from the largest units. The growth rate
in terms of new catalyst regenerators is
uncertain due to the present uncertainty
of petroleum supplies and demand.
However, for perspective a growth rate
of 0.5 percent in capacity from 1979
through 1985 would result in additional
emissions from uncontrolled new
sources of 23 Mg per day in 1986; a
growth rate of 0.75 percent would result
in additional uncontrolled emissions of
58 Mg SO,/day. Emissions from
modified or reconstructed sources would
add to this total.
Based on the existence of these SOi
control technologies, EPA plans to
initiate a program later this year to
assess the applicability, cost,
performance, and non-air environmental
impacts of these technologies. If
supported by the findings of this
program EPA will propose a limit on
FCCU SO, emissions.
Volatile Organic Compounds
The emission of volatile organic
compounds (VOC) from FCC unit
regenerators is not limited in the present
NSPS. These are, however, of concern,
both because of their role as oxidant
precursors and as potentially hazardous
compounds. Of particular concern are
the polynuclear aromatic compounds
(PNA) because of their potential
carcinogenic effects. The most abundant
PNA measured in regenerator flue gas is
benzo-a-pyrene (BAP) with a
concentration of 0.218 kg BAP/1,000
barrels of feed. The concentration of
BAP can effectively be reduced in a
carbon monoxide boiler to 1.41 X 10''
kg BAP/1,000 barrels of feed. However,
there are no data indicating the
concentration of BAP in the flue gas
from high temperature (in situ)
regeneration nor from regenerators using
CO oxidation promoting catalyst. This,
therefore, has been identified as an area
for future study by EPA's Office of
Research and Development.
Public Participation
All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Douglas M. Costle,
Administrator.
Dated. October 15, 1979.
|FR Doc 79-32567 Filed 10-l»-78. 8 45 am)
V-J-3
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Federal Register / Vol. 45. No. 43 / Monday. March 3.1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1423-2]
Standards of Performance for New
Stationary Sources; Petroleum
Refineries; Clarifying Amendment
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.
SUMMARY: This proposed action clarifies
which gaseous fuels used at petroleum
refineries are covered by the existing
standards of performance for petroleum
refineries (40 CFR 60.100). This action
will not change the environmental,
energy, and economic impacts of the
existing standards.
DATE: Comments must be received on or
before May 2,1980.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to: Central Docket Section (A-
130), Attention: Docket Number A-79-
56, U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460. Docket. The
Docket, Number A-79-56, is available
for public inspection and copying at
EPA's Central Docket Section, Room
2902 Waterside Mall, Washington, D.C.
20460.
FOR FURTHER INFORMATION CONTACT:
Susan R. Wyatt, Emission Standards
and Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5477.
SUPPLEMENTARY INFORMATION: On
March 12,1979, EPA published in the
Federal Register (44 PR 13480) a
clarifying amendment intended to
"reduce confusion concerning the
applicability of the sulfur dioxide
standard to incinerator-waste heat
boilers installed on fluid or Thermofor
catalytic cracking unit catalyst
regenerators and fluid coking unit coke
burners." That action included a change
in the definition of "fuel gas." it now
appears the revised definition of "fuel
gas" could easily be interpreted to
include natural gas as a fuel gas. This
would mean that refineries using natural
gas would be subject to the expense of
performance testing, monitoring, and
reporting requirements even though the
natural gas contained essentially no
sulfur and did not result in emissions of
sulfur dioxide when combusted.
The intent of the existing standards of
performance for refinery fuel gas has
always been to prevent emissions of
sulfur dioxide resulting from the burning
of gaseous fuels containing hydrogen
sulfide. Generally, natural gas used in
refineries is purchased from outside
sources and delivered to the refinery via
pipelines. This natural gas contains only
trace amounts of hydrogen sulfide due
to specifications established to protect
the pipelines from corrosion. It would
impose an unnecessary burden on
refineries to require performance testing,
monitoring, and reporting where this
natural gas is burned by itself.
In a few cases, however, a refinery
may generate natural gas. There may be
no legal or technical requirement that
this gas be desulfurized before
combustion. If this gas contains
appreciable hydrogen sulfide and other
sulfur constituents, significant emissions
of sulfur dioxide would result when it is
burned. The existing standards of
performance for petroleum refineries
were intended to cover these types of
gases. Consequently, the definition of
"fuel gas" is rewritten to clarify that
only natural gas generated at a
petroleum refinery is to be considered
fuel gas. The effective date of the
revised definition would be March 12,
1979.
Miscellaneous: Under Executive
Order 12044, EPA is required to judge
whether a regulation is "significant" and
therefore subject to the procedural
requirements of the Order or whether it
may follow other specialized
development procedures. EPA labels
these other regulations "specialized." I
have reviewed this regulation and
determined that it is a specialized
regulation not subject to the procedural
requirements of Executive Order 12044.
Dated: February 26,1980.
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations by revising paragraph (d) as
follows:
60.101 Definitions,
*****
(d) "Fuel gas" means natural gas
generated at a petroleum refinery, or
any gas generated by a refinery process
unit, which is combusted separately or
in any combination with any type of
natural gas. Fuel gas does not include
gases generated by catalytic cracking
unit catalyst regenerators and fluid
coking burners.
*****
(Sec. Ill, 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601(a))
|FR Doc. ao-«9M Filed 2-29-ao: 8:45 «n|
V-J-4
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
SECONDARY BRASS OR BRONZE INGOT PRODUCTION PLANTS
SUBPART M
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Federal Register / Vol. 44, No. 119 / Tuesday, June 19,1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 60]
[FRL-1231-1]
Review of Standards of Performance
for New Stationary Sources:
Secondary Brass and Bronze Ingot
Production
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standard of performance for secondary
brass and bronze ingot production
plants (40 CFR 60.130, Subpart M). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent not to undertake revision of
the standards at this time.
DATES: Comments must be received on
or before August 20,1979.
ADDRESSES: Comments should be sent
to the Central Docket Section (A-130).
U.S. Environmental Protection Agency,
401 M Street, SW., Washington, D.C.
20460, Attention: Docket No. A-79-10.
The Document "A Review of Standards
of Performance for New Stationary
Sources—Secondary Brass and Bronze
Plat Plants" (EPA-450/3-79-011) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
In June of 1973, the EPA proposed a
standard under Section 111 of the Clean
Air Act to control participate matter
emissions from secondary brass and
bronze ingot production plants (40 CFR
60.230, Subpart M). The standard,
promulgated in March 1974, limits the
discharge of any gases into the
atmosphere from a reverberatory
furnace which;
1. Contain particulate matter in excess
of 50 mg/dscm (0.022 gr/dscf).
2. Exhibit 20 percent opacity or
greater.
In addition, any blast (cupola) or
electric furnace may not emit any gases
which exhibit 10 percent opacity or
greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years (Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of the
standard of performance for secondary
brass and bronze ingot production
plants and invites comment on the
results of this review.
Findings
Industry Statistics
In 1969, there were approximately 60
brass and bronze ingot production
facilities in the United States. Currently,
only 35 facilities are operational, and
only one facility has become operational
since the promulgation of the NSPS in
1974. No new facilities or modifications
are know to be currently planned or
under construction.
Ingot production has shown a steady
decline from the 1966 peak year
production of 315,000 Mg (347,000 tons)
to a low of 160,000 Mg (186,000 tons) in
1975, the last year for which nationwide
statistics were published. The decline
has been caused by a decline in the
demand for products made with brass or
bronze and large scale substitution of
other materials or technologies for the
previously used braae or bronze. No
information has been reported which
would indicate a reversal of the decline
in brass and bronze ingot production or
in the number of operating plants.
Emissions and Control Technology
The current best demonstrated control
technology, the fabric filter, is the same
as when the standards were originally
promulgated. No major improvements in
this technology have occurred during the
intervening period.
High-pressure drop venturi scrubbers
are used, to some extent, in the brass
and bronze industry, but their overall
control efficiency is lower than that of
fabric filters. Electrostatic precipitators
have not been used in the industry due
to both the low gas flow rates and high
resistivity of metallic fumes.
Only one facility has become subject
to the standard since its original
promulgation. This facility was tested in
February 1978. The average test result of
16.9 milligrams/dry standard cubic
meters (mg/dscm), or 0.0074 grains/dry
standard cubic feet (gr/dscf), is lower
than most of the test data used for
justification of the current standard of
50 mg/dscm (0.022 gr/dscf), but this
single test is not considered sufficient to
draw any overall conclusion about
improved control technology.
Fugitive emissions continue to be a
problem in the brass and bronze
industry. In most cases, these emissions
are very difficult to capture and equally
difficult to measure during testing. It
was primarily for the former reason that
the current particulate standard does
not apply during pouring of the ingots.
This overall situation has not changed in
that only complete enclosure of the
furnace can result in full control of
fugitive emissions. However,
information is available indicating that
there may be additives capable of
reducing fugitive emissions during
pouring. Also, improved control of
fugitive emissions may be possible
through improved hood design.
Conclusions
Based on the above findings, EPA
concludes that the existing standard of
performance is appropriate and no
revision is needed. While extension of
the standard to include fugitive
emissions would be possible, the lack of
anticipated growth in the industry does
not justify such action.
PUBLIC PARTICIPATION: AH interested
persons are invited to comment on this
review and the conclusions.
Dated: June 12,1979.
Douglas M. Costle,
Administrator.
(PR Doc. 79-19003 Filed 0-18-79, 8.15 am|
BHJ-ING CODE 6560-01-M
V-M-2
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ENVIRONMENTAL
PROTECTION
AGENCY
BASIC OXYGEN PROCESS
FURNACES
Standards of Performance For New
Stationary Sources
SUBPART N
-------
PROPOSED RULES
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Port 60]
[PRL 1012-1]
STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES: IRON AND STEEL
PLANTS, BASIC OXYGEN FURNACES
Review of Slandardi
AGENCY: Environmental Protection
Agency (EPA).
ACTION. Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for basic
oxygen process furnaces (BOPFs) used
at iron and steel plants. The review is
required under the Clean Air Act, as
amended in August 1977. The purpose
of this notice is to announce EPA's
intent to propose amendments to the
standards at a later date.
DATES: Comments must be received
by May 21, 1979.
ADDRESS: Send comments to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
27711.
FOR FURTHER INFORMATION
CONTACT:
Mr. Robert Ajax, telephone: (919)
541-5271.
The document "A Review of Stand-
ards of Performance of New Station-
ary Sources—Iron and Steel Plants/
Bassic Oxygen Furnaces" (report
number EPA-450/3-78-116) is availa-
ble upon request from Mr. Robert
Ajax (MD-13), Emission Standards
and Engineering Division, U.S. Envi-
ronmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
SUPPLEMENTARY INFORMATION:
BACKGROUND
Paniculate matter emissions from
BOPFs fall in two categories, primary
and secondary. Emissions associated
with the oxygen blow portion of the
BOPF are termed "primary" emis-
sions. These emissions are generated
at the rate of 25 to 28 kg/Mg (50 to 55
Ib/ton) of raw steel. Emissions gener-
ated during ancillary operations, such
as charging and tapping, are termed
"secondary" or fugitive emissions.
These emissions are generated at a
lower rate in the range of 0.5 to 1 kg/
Mg (1 to 2 Ib/ton) of raw steel.
In June of 1973, EPA proposed a reg-
ulation under Section 111 of the Clean
Air Act to control primary particulate
emissions from basic oxygen process
furnaces at iron and steel plants. The
regulation, promulgated in March
1974, requires that no owner or opera-
tor of any furnace producing steel by
charging scrap steel, hot metal, and
flux materials into a vessel and intro-
ducing a high volume of an oxygen-
rich gas shall discharge into the at-
mosphere any gases which contain
particulate matter in excess of 50 mg/
dscm (0.022 gr/dscf).
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of per-
formance for new stationary sourcs at
least every 4 years (Section
HKbXlxB)). This notice announces
that EPA has completed a review of
the standard of performance for basic
oxygen process furnaces at iron and
steel plants and invites comment on
the results of this review.
FINDINGS
INDUSTRY GROWTH RATE
The present economic conditions in
the United States and worldwide steel
industry have created a significant
excess U.S. BOPF capacity and a
tightening of the availablitly of capital
for future expansion. Since the pro-
mulgation of the BOPF standard, new
BOPF construction has declined sig-
nificantly. For example, three of the
four units scheduled for startup in
1978 were originally scheduled to
begin production in 1974. This coupled
with the lack of any additional indus-
try announcements of new U.S. BOPF
contruction, indicates that construc-
tion of new BOPFs which would be
subject to a revised new source per-
formance standard (NSPS) is not
likely to commence before 1980, if
then. Construction of new plants
beyond 1980 will be dictated by domes-
tic economic conditions and interna-
tional competition, and is, therefore,
uncertain.
PRIMARY EMISSION CONTROL
Review of the literature and per-
formance test data indicates that the
use of a closed hood in conjunction
with a scrubber or an open hood in
conjunction with either a scrubber or
electrostatic precipitator currently
represents the best demonstrated con-
trol technologies for controlling BOPF
primary emissions. All BOPFs that
have been installed since 1973 incorpo-
rate closed hood systems for particu-
late emission control. The closed hood
control system in combination with a
venturi scrubber has become the
system of choice of the U.S. steel in-
dustry because this system saves
energy and has generally lower main-
tenance requirements compared with
the older open-hood electrostatic pre-
cipitator system. Use of the closed
hood system requires that approxi-
mately 80 percent less air be cleaned
than with the open hood system. The
potential* also exists with the closed
hood system for using the carbon
monoxide off-gas as a fuel source.
As of early 1978, no NSPS compli-
ance tests had been carried out since
the promulgation of the standard. Per-
tinent data are available, however,
from emission tests on a limited
number of new BOPFs. These tests.
carried out using EPA Method 5, indi-
cate that primary particulate emission
levels of between 32 and 50 mg/dscf
(0.014 and 0.022 gr/dscf) are being
achieved using the same control tech-
nology as that existing at the time the
standard for primary emissions was es-
tablished for BOPFs. The rationale
for the current NSPS level of 50 mg/
dscm (0.022 gr/dscf) for primary stack
emissions, as described in 1973, is
therefore, still considered to be valid.
SECONDARY EMISSION CONTROL
TECHNOLOGY
Secondary or fugitive emissions not
captured by the BOPF primary emis-
sions control system during various
BOPF ancillary operations currently
amount to more than 100 tons annual-
ly. One of the principal sources of
these emissions, the hot metal charg-
ing cycle, can generate amounts of fu-
gitive emissions on the order of 0.25
kg/Mg (0.5 Ib/ton) of charge. These
emissions are presently uncontrolled
in most of the older BOPFs and only
partially controlled in most BOPFs
that have come on stream during the
past 5 years.
Control of secondary emissions in-
volves a developing technology that
requires in-depth study to determine
the most effective methods of fume
capture. Although potentially expen-
sive to construct, the complete furnace
enclusure equipped with several auxil-
iary hoods is currently the only dem-
onstrated technology exhibiting the
potential for effectively minimizing fu-
gitive emissions from a new BOPF.
Seven new BOPFs installed in the
U.S. in the past 7 years ha\e incorpo-
rated partial or full furnace enclosures
as part of the original particulate
emission control system. Since these
designs had deficiencies, these systems
are operating with varying degrees of
success;. Six new furnace enclosure in-
stallations due to commence oper-
ations in 1978, including four on new
BOPFs and two retrofit installations.
will incorporate a secondary hood
Inside the furnace enclosure with suf-
ficient volume for fugitive emission
control.
CLARIFICATION OF WORDING OF NSPS
STANDARD
Review of the existing standard re-
vealed possible ambiguity in the word-
ing of the NSPS with regard to the
FEDERAL REGISTER, VOL. 44, NO. 56—WEDNESDAY, MARCH 21, 1979
V-N-2
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
SEWAGE TREATMENT PLANTS
SUBPART 0
-------
Federal Register / Vol. 44. No. 229 / Tuesday, November 27,1979 / Proposed Rules
40 CFR Part 60
1FRL 1310-3]
Standards of Performance for New
Stationary Sources: Sewage
Treatment Plants; Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for sewage
treatment plant sludge incinerators (40
CFR 60.150). The review is required
under the Clean Air Act, as amended
August 1977. The purpose of this notice
is to announce EPA's plan to defer
decision on the need to revise the
standards and to undertake a program
to further assess emission rates, control
technology, and the current standard.
DATES: Comments must be received by
January 28,1980.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130). U.S. Environmental Protection
Agency. 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. A-79-17.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271 The document "A Review of
Standards of Performance for New
Stationary Sources—Sewage Sludge
Incinerators" (EPA-450/3-79-010) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park. North Carolina 27711.
SUPPLEMENTARY INFORMATION:
Background
Prior to the promulgation of the NSPS
in 1974, most sewage sludge incinerators
utilized low pressure scrubbers (2 to 8
in WG) to reduce emissions to the
atmosphere. These scrubbers were
designed to meet State and local
standards that were on the order of 0.2
to 0.9 grams/dry standard cubic meter
(dscm) or 0.1 to 0.4 grains/dry standard
cubic foot (dscf) at 50 percent excess air
Incineration standards, for the most
part, reflected general incineration of all
types with emphasis on municipal solid
waste. A separate standard for sewage
sludge incineration emissions was
unusual. Control efficiencies, based on
an uncontrolled rate of 0.9 grains/dscf,
were between 50 and 90 percent.
In June of 1973, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate matter emissions
from sewage sludge incinerators. The
standard, promulgated in March 1974
and amended in November 1977, applies
to any incinerator constructed or
modified after June 11,1973, that burns
wastes containing more than 10 percent
sewage sludge (dry basis) produced by
municipal sewage treatment plants, or
charges more than 1000 kg (2205 Ib/day)
municipal sewage sludge (dry basis).
The standard prohibits the discharge of
particulate matter at a rate greater than
0.65 grams/kg of dry sludge input (1.30
Ib/ton) and prohibits the discharge of
any gases exhibiting 20 percent opacity
or greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)J. This notice announces that
EPA has undertaken a review of the
standard of performance for sewage
sludge incinerators and sets forth initial
findings based on this review. EPA is
however, deferring a final decision on
the need to revise the standard until
further data can be obtained and
analyzed pertaining to the form of the
standard, parameters affecting emission
rates, and coincineration. Comments on
these findings and this action are
invited.
Findings
Status of Sen-age Sludge Incinerators
It is estimated that approximately 240
municipal sludge incinerator units are
presently in operation. A large number
of incinerators were built in the 1967-
1972 period and this growth has
continued, although at a somewhat
slower rate since 1972. A compilation of
incinerator units subject to the
construction grants program indicated
that 92 new units were either in the
contruction or planning stages in mid-
1977. A total of 23 sludge incinerators
have been identified which are subject
to the standard and which have been
tested for compliance.
Emission Rates and Control Technology
Particulate matter from the inert
material in sludge is present in the flue
gas of sewage sludge incinerators.
Uncontrolled emissions may vary from
as low as 4 g/kg (8 Ib/ton) dry sludge
input to as high as 110 g/kg (220 Ib/ton)
dry sludge input depending upon the
incinerator type and the sludge
composition (e.g., percent volatile solids,
percent moisture, and source treatment).
Since adoption of the standard, wet
scrubbers operating with pressure drops
in the range of 7 to 32 in. WG and a
mean of 20 in. WG have been employed
exclusively and have been successful for
controlling emissions to the level
required by the standard. The average
emission from tests of 26 facilities since
1974 was 0.55 g/kg with a standard
deviatin of 0.35 g/kg (1.1 ±0.7 Ib/ton)
dry sludge input. When tests from one
obviously underdesigned facility and
three facilities not subject to the
standard were deleted, the average
emission was 0.45 g/kg with a standard
deviation of 0.17 g/kg (0.91 ± 0.33 lb/
tori) dry sludge input or about 30 percent
below the standard. The scrubber
configurations which were employed
included three-stage perforated plate
impingment scrubbers operating at 7 to 9
in WG and venturi scrubbers, or venturi
scrubbers in series with various
impingment plate scrubbers operating in
the 9 to 32 in. WG range.
While these test results are consistent
with the standard, an analysis of the test
results shows an inconsistent
relationship between scrubber pressure
drop and emissions as expressed in
units of the standard. This appears to be
due to both the facility type and input
sludge composition, particularly solids
content. Moreover, experimental data
from some of the tested units suggest
that incinerators burning sludge below
20 percent solids may have difficulty
complying with the NSPS. Because
combustion air requirements per unit of
dry sludge increase with increasing
sludge moisture, actual stack volume
concentrations of 0.01 grains/dry
standard cubic meter or less are needed
to meet the standard when high
moisture sludges are incinerated. For
example, two incinerators burning
sludges of 16 percent solids achieved
only marginal compliance and low
volume concentrations of 0 009 and 0.010
grains/acf.
An additional finding based on an
analysis of the test data which are now
available concerns the relationship
between emissions expressed in terms
of grain loading on a dry basis and
emissions per weight of dry sludge
burned. As initially proposed, the
standard was expressed as a volume
concentration standard equal to 0.031
grains/dscf. Due to comments received
relative to the use of dilution air and the
difficulties involved in measuring and
correcting to dry volume, the
promulgated standard was established
at 1.3 Ib/dry ton sludge input. This was
based on data available at the time of
promulgation showing that the
promulgated and proposed standards
were equivalent. However, an analysis
V-0-2
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Federal Register / Vol. 44. No. 229 / Tuesday. November 27, 1979 / Proposed Rules
of the. data which are now available
indicate a nominal equivalence between
1.8 Ib/ton dry sludge and 0.031 grains/
dscf for typical sludges.
One factor at least partially
responsible for the difference in
equivalent emission factors, in addition
to affecting the relationship between
pressure drop and mass emissions, is
the moisture content in the input sludge.
The average solids content of the sludge
associated with the data cited above is
24 percent. However, tests of two other
facilities with input sludge having a
relatively high solids content of between
27 and 33 percent showed an
equivalence similar to that found by
EPA in 1973 (e.g., 0.03 grains/dscf
equivalent to 1.3 Ib/ton dry sludge
input).
Opacity levels from successful
emissions tests never exceeded 15
percent and were most often either 0 or
5 percent. These results are similar to
those found when the standard was first
proposed as a 10 percent value with
exceptions allowed during 2 minutes of
a 60 minute test cycle. This standard
was changed to 20 percent with no
exemptions except during startup, shut
down, or malfunctions. The current data
indicate that the rationale used to arrive
at the 20 percent opacity level till
applies. This rationale, in addition to
field observations obtained with Method
9, involved instrumental data and
theoretical projections of the opacity
which could, under extreme conditions,
occur at a facility complying with the
particulate matter standard. A
reevaluation of this standard was
undertaken and reaffirmation was
announced in the Federal Register on
February 18,1976.
Application of the Standard to
Coincineration
The coincineration of municipal solid
waste and sewage sludge has been
practiced in Europe for several years,
and on a limited scale in the U.S.
However, as energy resources become
scarce and more costly, and where land
disposal is economically or technically
unfeasible, the recovery of the heat
content of dewatered sludge as an
energy source will become more
desirable. Due to this and the
institutional commonality of these
wastes and advances in the
preincineration processing of municipal
refuse to a waste fuel, many
communities may find joint incineration
in energy recovery incinerators an
economically attractive alternative to
their waste disposal problems.
Coincineration of municipal solid
waste and sewage sludge, as described
above, is not explicitly covered in 40
CFR 60. The particulate standard for
municipal solid waste described in
Subpart E (0.18 g/dscm or 0.08 g/dscf at
12 percent COa) applies to the
incineration of municipal solid waste in
furnaces with a capacity of at least 45
Mg/day (50 tons/day). Subpart O, the
particulate standard for sewage sludge
incineration (0.65 g/kg dry sludge input
or 1.3 Ib/ton dry sludge), applies to any
incinerator that burns sewage sludge,
with the exception of small communities
practicing coincineration.
To clarify the situation when
coincineration is involved, EPA adopted
the policy that when an incinerator with
a capacity of at least 45 Mg/day (50
tons/day) burns at least 50 percent
municipal solid waste, then the Subpart
E applies regardless of the amount of
sewage sludge burned. When more than
50 percent sewage sludge and more than
45 Mg/day (50 tons) is incinerated, the
standard is based upon Subpart O or,
alternatively, a proration between
Subparts O and E. The proration
scheme, however, has a discontinuity
when a municipal incinerator burns 50
percent solid waste.
The alternative of prorating the
Subparts E and O is not straight-
forward, since the two standards are
stated in different units. The proration
scheme requires a transformation of the
municipal incineration standard
(Subpart E) from grams per dry standard
cubic meter (grains per dry standard
cubic foot) at 12 percent COj to grams
per kilograms (pounds per dry ton)
refuse input, or a transformation of the
sewage sludge standard (Subpart O)
from grams per dry kilograms (pounds
per dry ton) input to grams per dry
standard cubic meter at 12 percent CO*
Such transformations are dependent on
the percent CO, in the flue gas stream,
the stoichiometric air requirements,
excess air, the volume of combustion
products to require air, and percent
moisture in refuse or sludge, and the
heat content of the sludge and solid
waste.
Other Pollutants
Incineration of sewage sludge results
in the emission to the atmosphere of
trace elements and compounds, some of
which are hazardous or potentially
hazardous. Substances of concern
include mercury, lead, cadmium,
pesticides, and organic matter. Among
these, mercury emissions from sewage
sludge incinerators are specifically
limited under the National Emission
Standards for Hazardous Air Pollutants
(40 CFR 61.50 et seq.).
The emission of other trace
compounds and elements, while not
subject to specific limitations is
controlled by particulate matter control
equipment or directly by the high
temperatures in the combustion process
and with the exception of cadmium, no
data were obtained during this review to
indicate a need for specific limitations
on emissions of these materials resulting
from incineration of typical sludges.
Tests have shown high destruction
efficiencies for pesticides, and organics
in sewage sludge incinerators. Similarly,
test data suggest that high pressure
scrubbers of the type normally
employed to meet the particulate
standards also reduce lead emissions to
below the level required to meet
ambient standards. In contrast, data
suggest that cadmium emissions may
not be adequately controlled. A separate
program is underway in EPA to
independently assess the need to
regulate cadmium. Final decisions on
this will be announced in a separate
action. In the event that the need to limit
cadmium emissions from sewage sludge
incinerators is indicated, appropriate
action will be taken.
Conclusions
The available test data support the
validity of the standard. However, the
marginal compliance of several facilities
operating with high pressure drops, the
apparent relationship between sludge
moisture content and emission rates,
and the inconsistent relationship
between pressure drop and scrubber
performance as measured in terms of the
standard are matters which require
further study. Such a study will be
undertaken later and will include further
analysis of data regarding sludge
dewatering, incinerator types, control
technology, and the relationship
between control device operating
parameters, sludge solids content,
emission rates, and alternative forms for
expression of emission rates. This will
also include an analysis of alternativp
means for establishment of standards
applicable to coincineration. A final
conclusion on the need for revision of
the standard will not be made until this
study is complete.
Dated: November 16. 1979.
Barbara Blum,
Acting Administrator.
|FR Doc 79-36473 Filed 11-26-79, 845 urn]
V-0-3
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PROPOSED RULES
definitions of a BOPP. Also, the defi-
nition of the operating cycle during
which sampling is performed requires
clarification. Specifically, the stack
emissions averaged over the oxygen
blow part of the cycle could be signifi-
cantly different from the emissions av-
eraged over a period or periods that
Includes scrap preheating and turn-
down for vessel sampling. The current
standard is unclear as to which averag-
ing time should be used. Since no tests
to date have come under the NSPS,
averaging time has not been an issue;
however, Interpreting the standard
will be a problem until this matter is
resolved.
CONCLUSIONS
Based upon the above findings, the
following conclusions have been
reached by EPA:
(1) The best demonstrated systems
of emissions control at the time the
standard for primary emissions was es-
tablished for BOPF have not changed
in the past 5 years. (See APTD-1352c
(EPA/2-74-003), Background Informa-
tion for New Source Performance
Standards, Volume 3, Promulgated
Standards.) These technologies con-
trol emissions to a level consistent
with the current standard; therefore,
revision to the existing standard is not
required, if only primary emissions are
•to be controlled.
(2) Secondary or fugitive emissions
from BOPFs represent a major air pol-
lution emission source. EPA, there-
fore, intends to initiate a project to
revise the existing standard of per-
formance to include fugitive emissions.
This development project is planned
to begin during 1979 and lead to a pro-
posal 20 months after initiation. In ad-
dition, an assessment of foreign tech-
nology, which ahs been initiated by
the Agency, will be included in the
basis for the revised standard. The as-
sessment may lead to further conclu-
sions about the allowable emissions
from the primary gas cleaning stack
due to the interdependence of primary
and secondary control technologies.
(3) The ambiguities in the present
standard concerning definition of a
BOPF and the operating cycle to be
measured should be clarified, and a
project to do so has been initiated.
PUBLIC PARTICIPATION
All interested persons are invited to
comment on this review, the conclu-
sions, and EPA's planned action. Com-
ments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
27711.
Dated: March 9, 1979.
BARBARA BLUM,
Acting Administrator.
[FR Doc. 79-8360* Filed 3-20-79; 8:45 am]
FEDERAL REGISTER, VOL. 44, NO. 56—WEDNESDAY, MARCH 21, >979
V-N-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
GLASS MANUFACTURING PLANTS
SUBPART CC
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Federal Register / Vol. 44, No. 117 / Friday, June 15,1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 601
[FRL 1203-7]
Standards of Performance for New
Stationary Sources; Glass
Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.
SUMMARY: The proposed standards
would limit emissions of participate
matter from new, modified, and
reconstructed glass manufacturing
plants. The standards implement the
Clean Air Act and are based on the
Administrator's determination that glass
manufacturing plants contribute
significantly to air pollution. The
intended effect is to require new,
modified, and reconstructed glass
manufacturing plants to use the best
demonstrated system of continuous
emission reduction, considering costs,
nonair quality health and environmental
impact, and energy impacts.
A public hearing will be held to
provide interested persons an opportuity
for oral presentation of data, views, or
arguments concerning the proposed
standards.
DATES: Comments. Comments must be
received on or before August 14,1979,
Public Hearing. The public hearing
will be held on July 9,1979 beginning at
9:30 a.m. and ending at 4:30 p.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony at the
hearing should contact EPA by June 29,
1979.
ADDRESSES: Comments. Comments
should be submitted to Central Docket
Section (A-130), United States
Environmental Protection Agency, 401M
Street, S.W., Washington, D.C. 20460,
Attention: Docket No. OAQPS 79-2.
Public Hearing. The public will be
held at Office of Administration
Auditorium, Research Triangle
Park, North Carolina 27771. Persons
wishing to present oral testimony should
notify Mary Jane Clark, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Rsearch Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
Standards Support Document. The
support document for the proposes
•tandards may be obained from the U.S.
EPA Library (MD-35), Research Triangle
Park, North Carolina 27711, telephone
number (919) 541-2777. Please refer to
"Glass Manufacturing Plants,
Background Information: Proposed
Standards of Performance," EPA-450/3-
79-005a.
Docket. A docket, number OAQPS 79-
2, containing information used by EPA
in development of the proposed
standard, is available for public
inspection between 8:00 a.m. and 4:00
p.m. Monday through Friday, at EPA's
Central Docket Section (A-130), Room
2903 B, Waterside Mall, 401 M Street.
S.W., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The standards would apply to glass
melting furnaces with glass
manufacturing plants with two
exceptions: day pot furnaces (which
melt two tons or less of glass per day)
and all-electric melting furnaces. No
existing plants would be covered unless
they were to undergo modification or
reconstruction. Change of fuel from gas
to fuel oil would be exempt from
consideration as a modification and
rebricking of furnaces would be exempt
from consideration as reconstruction.
Specifically, the proposed standards
would limit exhaust emissions from gas-
fired glass melting furnaces to 0.15
grams of particulate matter per kilogram
of glass produced for flat glass
production; 0.1 g/kg (0.2 Ib/ton) for
container glass production; 0.2 g/kg (0.4
Ib/ton) for wool fiberglass production;
0.1 g/kg (0.2 Ib/ton) for pressed and
blown glass production of soda-lime
formulation; and 0.25 g/kg (0.5 Ib/ton)
for pressed and blown glass production
of borosilicate, opal, and other
formulations. A15 percent allowance
above the emission limits for gas-fired
furnaces is proposed for fuel oil-fired
glass melting furnaces and an additional
proportionate allowance is proposed for
furnaces simultaneously firing gas and
fuel oil.
Summary of Environmental and
Economic Impacts
Environmental Impacts
The proposed standards would reduce
projected 1983 emissions from new
uncontrolled glass melting furnaces from
about 5,200 megagrams (Mo)/year (5,732
ton/year) to about 400 Mg/year (441
ton/year). This is a reduction of about
92 percent of uncontrolled emissions.
Meeting a typical State Implementation
Plan (SIP), however, would reduce
emissions from new uncontrolled
furnaces by about 3,700 Mg/year (4,079
ton/year), or by about 70 percent. The
proposed standard would exceed the
reduction achieved under a typical SIP
by about 1,100 Mg/year (1,213 ton-year).
This reduction in emissions would result
in a reduction of ambient air
concentrations of particulate matter in
the vicinity of new glass manufacturing
plants.
The proposed standards are based on
the use of electrostatic precipitators
(ESP's) and fabric filters, which are dry
control techniques; therefore, no water
discharge would be generated and there
would be no adverse water pollution
impact.
The solid waste impact of the
proposed standards would be minimal.
Less than 2 Mg (2.2 ton) of particulate
would be collected for every 1,000 Mg
(1,102 ton) of glass produced. These
dusts can generally be recycled, or they
can be landfilled if recycling proves to
be unattractive. The current solid waste
disposal practice among most controlled
plants surveyed is landfilling. Since
landfill operations are subject to State
regulation, this disposal method would
not be expected to have an adverse
environmental impact. The additional
solid material collected under the
proposed standard would not differ
chemically from the material collected
under a typical SIP regulation; therefore,
adverse impact from landfilling should
be minimal. Also, recycling of the solids
has no adverse environmental impact.
For typical plants in the glass
manufacturing industry, the increased
'energy consumption that would result
from the proposed standards ranges
from about 0.1 to 2 percent of the energy
consumed to produce glass. The energy
required in excess of that required by a
typical SIP regulation to control all new
glass melting furnaces constructed by
1983 to the level of the proposed
standards would be about 2,500
kilowatt-hours per day in the fifth year
and is considered negligible. Thus, the
proposed standards would have a
minimal impact on national energy
consumption.
Economic Impacts
The economic impact of the proposed
standards is reasonable. Compliance
with the standards would result in
annualized costs in the glass
manufacturing industry of about $8.5
million by 1983. For typical plants
constructed between 1978-1983 capital
costs associated with the proposed
V-CC-2
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Federal Register / Vol. 44, No. 117 / Friday. June 15. 1979 / Proposed Rules
standards would range from about
$235,000 for a small furnace in the
pressed and blown glass sector which
melts formulations other than soda-lime
to about $770,000 for a large pressed and
blown glass furnace which melts soda-
lime formulations. Annualized costs
associated with the proposed standards
would range from about $70,000/year to
about $235,000/year for the furnaces
mentioned above. Cumulative capital
costs of complying with the proposed
standards for the glass manufacturing
industry as a whole would amount to
about $28 million between 1978-1983.
The percent price increase necessary to
offset costs of compliance with the
proposed standards would range from
about 0.3 percent in the wool fiberglass
sector to about 1.8 percent in the
container glass sector. Industry-wide,
the price increase would amount to
about 0.7 percent.
The economic impact of the proposed
standards may vary depending on the
size of the glass melting furnace being
considered. EPA is requesting comments
specifically on the economic impact of
the proposed standards with regard to a
possible lower cut-off size for glass
melting furnaces.
Rationale
Selection of Source and Pollutants
The proposed Priority List, 40 CFR
60.16, identifies various sources of
emissions on a nationwide basis in
terms of the quantities of emissions from
source categories, the mobility and
competitive nature of each source
category, and the extent to which each
pollutant endangers health or welfare.
The sources on this proposed list are
ranked in decreasing order. Class
manufacturing ranks 38th on the
proposed list, and is therefore of
considerable importance nationwide.
The production of glass is projected to
increase at compounded annual growth
rates of up to 7 percent through the year
1983. In 1975, over 17 million megagrams
(18.8 million ton} of glass were
produced; by 1983 this production rate is
expected to increase by nearly 2.9
million Mg/year (3.2 million ton/year).
Geographically, the glass manufacturing
industry is relatively concentrated with
plants currently located in 17 states.
Total particulate emissions in the United
States in 1975 were estimated to be
about 12.4 million Mg/year (13.7 million
ton/year); by the year 1983 new glass
manufacturing plants would cause
annual nationwide particulate matter
emissions to increase by about 1,500
Mg/year (1.620 ton/year) with emissions
controlled to the level of a typical SIP
regulation.
On March 18,1977, the Governor of
New Jersey petitioned EPA to establish
standards of performance for glass
manufacturing plants. The petition was
primarily motivated by the Governor's
concern that the glass manufacturing
industry might locate plants in other
States rather than comply with New
Jersey's air pollution regulations limiting
emissions of particulate matter. The
glass manufacturing industry is not
geographically tied to either markets or
resources. Only a few States have
specialized air pollution standards for
glass manufacturing plants in their SIP's,
and these standards vary in the level of
control required. Therefore, new glass
manufacturing operations could be
located in States which do not have
stringent SIP regulations.
Glass manufacturing plants are
significant contributors to nationwide
emissions of particulate matter,
especially when viewed as contributors
to emissions in the limited number of
States in which they are located. They
rank high with regard to potential
reduction of emissions. Since they are
free to relocate in terms of both markets
and required resources, the possibility
exists that operations could be moved or
relocated to avoid stringent SIP
regulations, thereby generating
economic dislocations. For these
reasons, emissions of particulate matter
from new glass manufacturing plants
have been selected for control by NSPS.
Glass manufacturing plants also emit
other criteria pollutants: sulfur oxides
(SO,), nitrogen oxides (NOJ, carbon
monoxide, and hydrocarbons. Carbon
monoxide and hydrocarbon emissions
from efficiently operated glass
manufacturing plants, however, are
negligible.
Nationwide, the largest aggregate
emissions from glass manufacturing
plants are NO,. The techniques
generally applicable to control NO,
produced by combustion are staged
combustion, off-stoichiometric
combustion, or reduced-temperature
combustion. To date none of these
techniques has been applied to the
control of NO, emissions from glass
melting furnaces. Accordingly, there is
no way of determining how effective
they might be in such applications.
Consequently, NO, was not selected for
control by standards of performance.
SOt emissions result from combustion
of sulfur-containing fuels and from
chemical reactions of raw materials. In
general there are two alternatives for
control of SO, emissions: (1) scrubbing
of exhaust gases containing SO,, and (2)
reducing the sulfur content of fuel and
raw materials. SO* emissions from glass
melting furnaces are in most cases
already less than the emission limits of
applicable SIP's for fuel burning sources.
Flue-gas scrubbing for control of SO*
emissions from glass melting furnaces is
not considered economically
reasonable.
There are difficulties as well with the
use of low-sulfur fuels or reduction of
sulfur content of raw materials. Using
low-sulfur fuel would not adequately
address the problem of SOj control for
two reasons. Natural gas is the preferred
fuel for glass melting furnaces. The only
alternative fuel currently in use or
projected for future use by the glass
manufacturing industry is distillate fuel
oil, which normally contains more sulfur
than natural gas. The elimination of
sulfur-containing fuel oil is not
considered reasonable. Alternatively,
standards of performance based solely
on combustion of low-sulfur fuels could
distort existing fuel distribution
patterns, since low-sulfur fuels could be
diverted to new facilities to meet NSPS
in areas that have no difficulty attaining
or maintaining the National Ambient Air
Quality Standards (NAAQS) for SO,.
This would reduce the supply of low-
sulfur fuels for existing facilities in areas
that have great difficulty attaining or
maintaining the NAAQS for SO,.
Consequently, standards of performance
for SO, emissions based on use of low-
sulfur fuels do not seem reasonable.
Use of reduced-sulfur raw materials
has not been demonstrated as a means
of reducing SO, emissions from glass
melting furnaces. There is a wide variety
of formulations, most of which are
considered by the industry to be trade
secrets. The present state of glass
making is such that formula alterations
of the type envisioned here would lead
to glass of unpredictable quality. For
these reasons, standards of performance
for SO, emissions from glass melting
furnaces based on reduced-sulfur raw
materials, or any other approach, do not
seem reasonable and have not been
proposed.
Selection of Affected Facility
Ninety-eight percent of the particulate
matter emitted from glass manufacturing
plants is emitted in gaseous exhaust
streams from glass melting furnaces.
Only two percent of the particulate
matter emitted from glass manufacturing
plants is emitted from raw material
handling and glass forming and
finishing. Therefore, the glass melting
furnace has been selected as the
affected facility.
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Federal Register / Vol. 44, No. 117 / Friday, June 15, 1979 / Proposed Rules
The proposed standards would apply
to all glass melting furnaces within glass
manufacturing plants with two
exceptions: day pot furnaces and all-
electric melters. A day pot furnace is a
glass melting furnace which is capable
of producing no more than two tons of
glass per day. These small glass melting
furnaces constitute an extremely small
percentage of total glass production and
their control is not considered
economically reasonable. Therefore, the
regulation exempts day pot furnaces
from the proposed standards.
Well operated and maintained all-
electric furnaces have particulate
emissions only slightly higher than
fossil-fuel fired furnaces controlled to
meet the proposed standards. Most of
these furnaces are open to the
atmosphere and do not have stacks.
Thus, control and measurement of
emissions from all-electric furnaces does
not appear to be economically
reasonable. Therefore, all-electric
melting furnaces are not regulated by
the proposed standards.
Selection of Format
Two alternative formats were
considered for the proposed standards:
mass standards, which limit emissions
per unit of feed to the glass furnace or
per unit of glass produced by the glass
furnace; and concentration standards,
which limit emissions per unit volume of
exhaust gases discharged to the
atmosphere.
Enforcement of concentration
standards requires a minimum of data
and information, decreasing the costs of
enforcement and reducing chances of
error. Furthermore, vendors of emission
control equipment usually guarantee
equipment performance in terms of the
pollutant concentration in the discharge
gas stream.
There is a potential for circumventing
concentration standards by diluting the
exhaust gases discharged to the
atmosphere with excess air, thus
lowering the concentration of pollutants
emitted but not the total mass emitted.
This problem can be overcome,
however, by correcting the
concentration measured in the gas
stream to a reference condition such as
a specified oxygen percentage in the gas
stream.
Concentration standards would
penalize energy-efficient furnaces, since
a decrease in the amount of fuel
required to melt glass decreases the
volume of gases released but not the
quantity of particulate matter emitted.
As a result, the concentration of
particulate matter in the exhaust gas
stream would be increased even though
the total mass emitted remained the
same. Even if a concentration standard
were corrected to a specified oxygen
content in the gas stream, this penalizing
effect of the concentration would not be
overcome.
Primary disadvantages of mass
standards, as compared to concentration
standards, are that their enforcement Is
more costly and that the more numerous
calculations required increase the
opportunities for error. Detemining mass
emissions requires the development of a
material balance on process data
concerning the operation of the plant,
whether it be input flow rates or
production flow rates. Development of
this balance depends on the availability
and reliability of production figures
supplied by the plant. Gathering of these
data increases the testing or monitoring
necessary, the time involved, and,
consequently, the costs. Manipulation of
these data increases the number of
calculations necessary; e.g., the
conversion of volumetric flow rates to
mass flow rates, thus compounding error
inherent in the data and increasing the
chance for error.
Although concentration standards
involve lower resource requirements
than mass standards, mass standards
are more suitable for regulation of
particulate emissions from glass melting
furnaces because of their flexibility to
accommodate process improvements
and their direct relationship to quantity
of particulate emitted to the atmosphere.
These advantages outweigh the
drawbacks associated with creating and
manipulated a data base. Consequently,
mass standards are selected as the
format for expressing standards of
performance for glass melting furnaces.
The proposed standards express
allowable particulate emissions in
grams of particulates per kilogram of
glass pulled. While emissions data
referring to raw material input as well
as data referring to glass pulled were
used in the development of the
standards, an examination of the
several sectors of the glass
manufacturing industry indicated that
an emission rate based on quantity of
glass pulled would be more
representative of industry practice.
Further, emissions are more dependent
on pull rate than on rate of raw material
input. Accordingly, the mass of glass
pulled is used as the denominator in the
proposed standards. Raw material input
data could be employed to estimate
glass pulled from a furnace if a
quantitative relationship between raw
material input and glass pulled were
developed following good engineering
methods.
Selection of the Best System of Emission
Reduction and Emission Limits
Introduction
Particulate emissions from glass
melting furnaces can be reduced
significantly by the use of the following
emission control techniques:
electrostatic precipitators, fabric filters,
and verituri scrubbers. Since these
emission control techniques do not
achieve the same level of control for
glass melting furnace emissions within
all sectors of the glass manufacturing
industry, they are discussed separately
for each sector.
Process modifications such as batch
formulation alteration and electric
boosting also may be capable of
reducing particulate emissions from
glass melting furnaces. The test data
available for furnaces where process
modifications are used as emissions
reduction techniques indicate that
emission, reduction by process
modification is indifmite with respect to
the effectiveness of the techniques.
Accordingly, the selection of the best
system of emission reduction is based
on the use of add-on emission reduction
techniques of known effectiveness.
However, there is nothing in this
proposal nor is it the intent of this
proposal to preclude the use of process
modifications to comply with the
proposed standards.
The glass manufacturing industry is
divided into four principal sectors
designated by Standard Industrial
Classifications (SIC's). The container
glass sector (SIC 3221] manufactures
containers for commercial packing and
bottling and for home canning by
pressing (stamping) and/or blowing (air-
forming) molten glass usually of soda-
lime recipe. The pressed and blown
glass, not elsewhere classified, sector
(SIC 3229) includes such diverse
products as: table, kitchen, art and
novelty glassware; lighting and
electronic glassware; scientific,
technical, and other glassware; and
textile glass fibers. Based on the
differing rates of particulate matter
emissions, it is necessary to subdivide
the pressed and blown glass sector into
plants producing glass from soda-lime
formulations and plants producing glass
from other formulation (primarily
borosilicate, opal and lead). Glass
manufacturing plants in the wool
fiberglass sector are classified under
mineral wool (SIC 3296); fiberglass
insulation is a major product. The flat
glass sector (SIC 3211) uses continuous
glass forming processes, and materials
almost exclusively of soda lime
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Federal Register / Vol. 44, No. 117 / Friday, June 15, 1979 / Proposed Rules
formulation, to manufacture sheet, plate,
float, rolled, and wire glass.
Each of the glass manufacturing
sectors is unique both from a technical
and an economic standpoint. Thus,
uncontrolled participate emission rate,
furnace size, and the applicability of
emission control techniques vary from
one sector to another. Since the products
manufactured by the different sectors of
the glass manufacturing industry serve
different markets, each sector is working
in a different economic environment. For
these reasons it was apparent that no
single model furnace could adequately
characterize the glass manufacturing
industry. Accordingly, several model
furnaces were specified in terms of the
following parameters: production rate,
stack height, stack diameter, exhaust
gas exit velocity, exhaust gas flow rate,
and exhaust gas temperature. The
evaluation, of these parameters may be
found in the Background Information
document. The model furnace
production rate specified for the
container glass sector was 225 Mg/day
(250 ton/day). For pressed and blown
glass furnaces melting soda-lime and
other formulations two model furnace
production rates were specified: 45 Mg/
day (50 ton/day) and 90 Mg/day (100
ton/day). Model furnace production
rates for the wool fiberglass and flat
glass sector were 180 Mg/day (200 ton/
day) and 635 Mg/day (700 ton/day),
respectively.
Review of the performance of the
emission control techniques led to the
identification of two regulatory options
for each sector. These options specify
numerical emission limits for glass
melting furnaces in each sector of the
glass manufacturing industry. The
environmental impacts, energy impacts,
and cost and economic impacts of each
regulatory option were compared with
those associated with a typical SIP
regulation and those associated with no
control.
Container Glass
Uncontrolled particulate emissions
from container glass furnaces are
generally about 1.25 g/kg (2.5 Ib/ton) of
glass pulled. Emission tests (using EPA
Method 5) on three container glass
furnaces equipped with ESP's indicate
an average particulate emission of 0.06
g/kg (0.12 Ib/ton) of glass pulled.
Emission test data for container glass
furnaces equipped with fabric filters are
not available. However, emission test
results for a pressed and blown glass
furnace melting a soda-lime formulation
essentially identical to that used for
container glass indicate that emissions
can be reduced to 0.12 g/kg (0.24 Ib/ton)
of glass pulled with a fabric filter. This
fabric filter installation was tested with
the Los Angeles Air Pollution Control
District particulate matter test method
(LAAPCD Method), which considers the
combined weight of the particulate
matter collected in water-filled
impmgers and of that collected on a
filter. EPA Method 5 also uses impingers
and a filter, but considers only the
weight of the particulate matter
collected on the filter. The LAAPCD
Method collects a larger amount of
particulate matter than does EPA
Method 5, and, consequently, greater
mass emissions would be reported for
comparable tests. An emission level of
0.1 g/kg (0.2 Ib/ton) as determined by
EPA Method 5, could be achieved by a
container glass furnace equipped with a
properly designed and operated fabric
filter.
EPA Method 5 tests of four furnaces
equipped with venturi scrubbers
indicated an average particulate
emission of 0.21 g/kg (0.42 Ib/ton) of
glass pulled.
Based on the data cited above, an
emission level of 0.1 g/kg (0.2 Ib/ton) of
glass pulled from container glass
furnaces can be achieved with ESFs or
fabric filters. An emission level of 0.2 g/
kg (0.4 Ib/ton) of glass pulled can
reasonably be achieved with a venturi
scrubber when operated at a pressure
drop somewhat higher than the average
of those scrubbers tested. ESP's and
fabric filters could also be designed to
achieve an emission level of 0.2 g/kg (0.4
Ib/ton) of glass pulled.
On the basis of these conclusions, two
regulatory options for reducing
particulate emissions from container
glass furnaces were formulated. Option I
would set an emission limit of 0.1 g/kg
(0.2 Ib/ton), requiring a particulate
emission reduction of somewhat over 90
percent as compared with an
uncontrolled furnace. Option II would
set an emission limit of 0.2 g/kg (0.4 lb/
ton), requiring a particulate emission
reduction of about 85 percent.
By 1983 approximately 1900 gigagrams
(Ggj/year (2.1 million ton/year) of
additional production is anticipated in
the container glass sector. About 25 new
container glass furnaces of about 225
Mg/day (250 ton/day) production
capacity (the size of the model furnace)
would be built in order to provide this
additional production. If uncontrolled,
these new container glass furnaces
would add about 2,400 Mg/year (2,646
ton/year) to national particulate
emissions by 1983. Compliance with a
typical SIP regulation would reduce this
impact to about 1,000 Mg/year (1,102
ton/year). Under Option I, emissions
would be reduced to about 19 percent of
those emitted under a typical SIP
regulation. Under Option II, emissions
would be reduced to about 38 percent of
those emitted under a typical SIP
regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled container glass furnace
producing 225 Mg/day of glass would be
less than 1 fig/ms. The annual maximum
ground-level concentration resulting
from compliance with a typical SIP
regulation. Option I, or Option II would
also be less than 1 pg/m'. The
calculated maximum 24-hour ground-
level particulate concentration near an
uncontrolled container glass furnace
producing 225 Mg/day of glass would be
approximately 10 jig/m*. The
corresponding concentration for
complying with a typical SIP regulation
would be 5 fig/m1. Under Option I, with
an ESP or a fabric filter being employed
for control, the maximum 24-hour
ground-level concentration would be
reduced to 1 jig/m". Under Option II,
with the same techniques being
employed, the concentration would be
reduced to 2 fig/ms. Use of a venturi
scrubber to meet the Option II emissions
limit would only reduce the
concentration to 6 jig/m*due to the
decreased stack height of a scrubber-
controlled plant and the resulting
increased building wake effects.
With one exception, standards of
performance for container glass
furnaces would have no water pollution
impact. The exception would be the use
of a venturi scrubber to comply with a
standard based on Option II. Such a
system, applied to a furnace producing
225 Mg/day of glass, would discharge
about 0.5 m'/hr of waste water
containing about 5 percent solids. The
waste water would probably be
discharged directly to an available
waste water treatment system. To date,
however, only a few container glass
furnaces have been controlled with
venturi scrubbers; dry collection
techniques have been preferred.
Consequently, few container glass
manufacturers would be expected to
install venturi scrubbers on their
furnaces to comply with a standard
based on Option II. The overall water
pollution impact would then be
negligible.
The potential solid waste impacts of
the regulatory options would result from
collected particulate matter. Solid waste
from container glass furnaces, other
than collected particulate matter, is
minimal since cullet is normally
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Federal Register / Vol. 44. No. 117 / Friday, June 15, 1979 / Proposed Rules
recycled back into the glass melting
process. Under a typical SIP regulation,
about 1.400 Mg/year (1,543 ton/year) of
particulate matter would be collected
from the 25 new 225 Mg/day container
glass furnaces projected to come on-
stream during the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about
800 Mg/year (882 ton/year) and about
600 Mg/year (661 ton/year),
respectively, to the solid waste collected
under a typical SIP regulation. Option I
would increase the mass of solids for
disposal by about 60 percent over that
resulting from compliance with a typical
SIP regulation, and Option n would
increase it by about 45 percent. The
additional solid material collected under
Option I or Option II would not differ
chemically from the material collected
under a typical SIP regulation. Collected
solids either are recycled back into the
glass melting process or are disposed of
in a landfill. Recycling of the solids has
no adverse environmental impact, and,
since landfill operations are subject to
State regulation, this disposal method
also would not be expected to have an
adverse environmental impact.
The potential energy impacts of the
regulatory options would be due to the
energy used to drive the fans in
emission control systems and the energy
used to charge the electrodes in ESP's.
Since ESP's have been the predominant
control system use'd in the industry, the
energy requirements estimated for a
typical SIP regulation, Option I, and
Option II were based on the use of
ESP's. The energy required to control
particulate emissions from the 25 new
container glass furnaces would be about
40 million kWh (22 thousand barrels of
oil/year) for a typical SIP regulation for
the new furnaces equipped with ESP's.
This required energy would be about 0.2
percent of the total energy use in the
container glass sector. There would be
no energy impact associated with either
Option I or Option II because the energy
required to operate an ESP for Option I
or Ogtion II is essentially the same as
the energy required to operate an ESP
for a typical SIP regulation.
Incremental installed cost (cost in
excess of a typical SIP regulation cost)
in January 1978 dollars associated with
Option I for controlling particulate
emissions from a 225 Mg/day container
glass furnace would be about $700
thousand for an ESP and about $1.2
million for a fabric filter. Incremental
installed cost associated with Option II
would be about $450 thousand for an
ESP, and about $1 million for a fabric
filter. The incremental installed cost of
control equipment associated with
Option I level of control would be about
1.6 times the incremental installed cost
associated with Option II if ESP's were
selected. If fabric filters were selected,
the incremental installed cost associated
with the Option I level of control would
be about 1.2 times the incremental
installed cost associated with Option II.
Incremental annualized costs
associated with Option I for a 225 Mg/
day furnace would be about $200
thousand/year and about $350
thousand/year for an ESP and a fabric
filter, respectively. Incremental
annualized costs associated with Option
II would be about $130 thousand/year
for an ESP, and about $300 thousand/
year for a fabric filter. The incremental
annualized cost associated with Option
I would be about 1.5 times the
incremental annualized cost associated
with Option II if ESP's were used. If
fabric filters were used the incremental
annualized cost associated with Option
I would be about 1.2 times the
incremental annualized cost associated
with Option II.
Based on the use of control equipment
with the highest annualized cost (worst
case conditions), a price increase of
about 1.8 percent would be necessary to
offset the cost of installing control
equipment on a 225 Mg/day container
glass furnace to meet the emissions limit
of Option I. A price increase of a~bout 1.5
percent would be necessary to comply
with the emission limit of Option II.
Incremental cumulative capital costs
for the 25 new 225 Mg/day container
glass furnaces during the 1978-1983
period associated with Option I would
be about $17 million if ESP's were used.
Use of ESP's to comply with a standard
based on Option II would require
incremental cumulative capital costs of
about $11 million for the same period.
Fifth-year annualized costs for
controlling container glass melting
furnaces to comply with Option I would
be about $5 million/year. To comply
with Option II, fifth-year annualized
costs would be about $3 million/year.
A summary of incremental impacts (in
excess of impacts of a typical SIP
regulation] associated with Option I and
Option II is shown in Table 1. Air
impacts, expressed in Mg/year of
particulate matter emissions reduced,
would approximate the quantity of
particulate matter collected and
disposed of as solid waste.
Tabto \.—Summary of Incremental Impacts
Associated With Regulatory Options
Impacts
A»' Water Energy' Economic"
Regulatory
option:
1 800 None Negligible ... -1.8
II 600 Negligible ....Negligible ... ~1.!>
'Mg/Yr reduced.
'Barrels of oil/day
' Percent price Increase.
Consideration of the beneficial impact
on national particulate emissions, the
degree of water pollution impact, the
small potential for adverse solid waste
impact, the lack of energy impact, the
reasonableness of cost impact, and the
general availability of demonstrated
emission control technology leads to the
selection of Option I as the basis for
standards for glass melting furnaces in
the container glass sector.
Pressed and Blown Glass—Soda-Lime
Formulation
Because the glass production rates,
the furnace configurations, and the glass
formulations melted in furnaces in this
sector are very similar to those in
container glass sector, the quantity and
chemical composition of particulate
emissions approximate those of
container glass furnaces. On the basis of
this similarity of process and emissions,
the emission reduction techniques which
have been shown to be effective for
container glass furnaces would also be
effective in reducing particulate
emissions from furnaces in this sector.
Uncontrolled particulate emissions
from pressed and blown glass furnaces
melting soda-lime formulations are
generally about 1.25 g/kg (2.5 Ib/ton) of
glass pulled from the furnace. Test data
for a pressed and blown glass furnace
melting a soda-lime formulation and
equipped with a fabric filter indicate
particulate emissions of 0.12 g/kg (0.24
Ib/ton) of glass pulled using the
V-CC-6
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Federal Register / Vol. 44, No. 117 / Friday. June 15, 1979 / Proposed Rules
LAAPCD Method. No emissions data for
pressed and blown glass furnaces
equipped with ESP'8 are available.
However, emission tests- using EPA
Method 5 on three container-glass
furnaces equipped with ESP's indicate
an average particulate emission rate of
0.06 g/kg (0.12 Ib/ton) of glass pulled.
Because of the similarities between this
sector and the container glass sector,
both ESP's and fabric filters would be
expected to be capable of reducing
emissions to about 0.1 g/kg (0.2 Ib/ton)
of glass pulled.
Based on the similarity of pressed and
blown glass production methods in this
sector to those of the container glass
sector, as well as on test data available
on container glass furnace emissions,
two regulatory options were formulated.
The regulatory options are identical to
those formulated for container glass
furnaces. Option I would set an
emission limit of 0.1 g/kg (0.2 Ib/ton) of
glass pulled, which would require a
particulate emission reduction of about
90 percent. Option II would set an
emission limit of 0.2 g/kg (0.4 Ib/ton) of
glass pulled, which would require about
85 percent particulate emission
reduction.
By 1983 approximately 310 Mg/year
(342 ton/year) of additional production
is anticipated in this glass
manufacturing sector. About four new 45
Mg/day (50 ton/day] (small) and six
new 90 Mg/day (100 ton/day) (large)
furnaces would be built in order to
provide this production. Emissions from
the large furnaces would have to be
reduced in order to comply with a
typical SIP regulation, while small
furnaces would meet a typical SIP
regulation without reducing emissions. If
uncontrolled, the four new small
furnaces would add about 80 Mg/year
(88 ton/year) to national particulate
emissions by 1983, while the six new
large furnaces would add about 230 Mg/
year (254 ton/year). Compliance with a
typical SIP regulation would reduce the
impact of the new large furnaces to
about 70 Mg/year (77 ton/year). Under
Option I, these furnace emissions would
be reduced to about 26 percent of those
emitted under a typical SIP regulation.
Under Option II, large furnace emissions
would be reduced to about 53 percent of
those emitted under a typical SIP
regulation.
The small furnaces would be in
compliance with a typical SIP regulation
without control. Under Option I,
emissions would be reduced to about 8
percent of uncontrolled emissions.
Under Option II, emissions would be
reduced to about 16 percent of
uncontrolled emissions.
The effect of a typical SIP regulation
for both 90 Mg/day (100 ton/day) and 45
Mg/day (50 ton/day) furnaces would be
a reduction of about 48 percent of
uncontrolled emissions. Under Option I,
emissions would be reduced to about 16
percent of those emitted under a typical
SIP regulation. Under Option II,
emissions would be reduced to about 33
percent of those emitted under a typical
SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled pressed and blown glass
furnace producing 45 Mg/day of glass
would be less than 1 /ig/mj, as would
the concentrations resulting from
compliance with Option I or Option II.
Corresponding annual maximum
ground-level concentrations near an
uncontrolled pressed and blown glass
furnace producing 90 Mg/day of glass
would also be less than 1 pg/m*.
Emissions from uncontrolled furnaces of
either size in this sector would result in
calculated maximum 24-hour ground-
level concentrations of 3 WJ/m3. Under
Option I this concentration would be
reduced to below 1 wj/ms. Under Option
II it would be reduced to about 1 ji£/m>-
Since fabric filters and electrostatic
precipitators are likely to be the control
systems installed on furnaces in this
sector to comply with standards, there
would be no water pollution impact
associated with standards based on
either Option I or Option IL
Under a typical SIP regulation, no
particulate matter would be collected
from the four new 45 Mg/day pressed
and blown glass furnaces projected to
come on-stream during the 1978-1983
period. The six new 90 Mg/day furnaces
would collect about 160 Mg/year (176
ton/year) under a typical SIP regulation.
For the six 90 Mg/day furnaces the
amounts collected in addition to those
collected through compliance with a
typical SIP regulation would be about 50
Mg/year (55 ton/year) for Option I and
about 33 Mg/year (36 ton/year) for
Option II. Compliance with standards
based on Option I and Option n would
result in the collection of about 72 Mg/
year (79 ton/year) and about 68 Mg/year
(75 ton/year), respectively, of solid
waste from the four 45 Mg/day furnaces.
Option I would increase the mass of
solids for disposal by 100 percent and by
about 31 percent over that required by a
typical SIP regulation for 45 Mg/day and
90 Mg/day furnaces, respectively.
Option II would increase the mass of
solids for disposal by 100 percent and 21
percent over that required by a typical
SIP regulation for 45 Mg/day and 90 Mg/
day furnaces, respectively. The total
masses of solids for disposal collected
from all new furnaces would be about
122 Mg/year (135 ton/year) and 101 Mg/
year (111 ton/year) for Option I and
Option II, respectively.
The additional solid material
collected under Option I and Option II
would not differ chemically from the
material collected under a typical SIP
regulation. Collected solids either are
recycled back into the glass melting
process or are disposed of in a landfill.
Recycling of the solids has no adverse
environmental impact, and, since
landfill operations are subject to State
regulation, this disposal method also
would not be expected to have an
adverse environmental impact.
Since the four new 45 Mg/day
furnaces would be in compliance with a
typical SIP regulation without add-on
controls, there would be no associated
energy requirement. The estimated
energy required to control particulates
emissions from the four new 45 Mg/day
furnaces projected to come on-stream in
the 1978-1983 period to the levels
required by both Option I and Option II
would be about 1.5 million kWh (900
barrels of oil/year). The energy required
to control particulate emissions from the
six new 90 Mg/da-y furnaces would be
4.4 million kWh (2,500 barrels of oil/
year) for a typical SIP regulation, Option
I, or Option H if ESFs were installed.
The energy required to comply with
the emission limits of the regulatory
options would be about 0.5 percent of
the total energy use in this glass
manufacturing sector. The energy
impacts of both Option I and Option II
are negligible (~3 barrels of oil/day) for
the new 45 Mg/day furnaces. There
would be no energy impact associated
with either Option I or Option FI for the
new 90 Mg/day furnaces beyond the
impact associated with the requirements
to meet a typical SIP regulatioa
incremental installed costs in January
1978 dollars associated with Option I for
controlling particular emissions from a
45 Mg/day pressed and blown glass
furnace melting soda-lime formulations
would be about $740 thousand for an
ESP and about $710 thousand for a
fabric filter. Incremental installed costs
associated with Option II would be
about $645 thousand for an ESP, and
•bout $675 thousand for a fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
1.1 times the incremental installed costs
associated with Option 0 if ESP's were
selected If fabric filters were selected
the incremental installed cosfi
associated with the Option I level of
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Federal Register / Vol. 44. No. 117 / Friday, June 15. 1979 / Proposed Rule8
control would be about 1.1 times the
incremental installed costs associated
with Option II.
Incremental annualized costs for a 45
Mg/day furnace associated with Option
I would be about $230 thousand/year for
both ESP's and fabric filters.
Incremental annualized costs associated
with Option II would be about $205
thousand/year for an ESP, and about
$215 thousand/year for a fabric filter.
The incremental annualized costs
associated with Option I would be about
1.1 times the incremental annualized
costs associated with Option II if ESP's
were used. If fabric filters were used,
the incremental annualized costs
associated with Option I would be about
1.1 times the incremental annualized
costs associated with Option II.
Based on the use of control equipment
with the highest annualized costs (worse
case conditions), a price increase of
about 0.6 percent would be necessary to
offset the costs of installing control
equipment on a 45 Mg/day pressed and
blown glass furnace melting soda-lime
formulations to meet the emission limits
of Option I. A price increase of about 0.5
percent would be necessary to comply
with the emission limits of Option II.
Incremental cumulative capital costs
for the 1978-1983 period associated with
Option I for the four new 45 Mg/day
furnaces would be about $2.8 million if a
fabric filter were used. Use of an ESP to
comply with Option II would require
incremental cumulative capital costs of
about $2.6 million for the same period.
Fifth-year annualized costs for
controlling the furnace to comply with
Option I would be about $910 thousand.
To comply with Option II, fifth-year
annualized costs would be about $815
thousand.
Incremental installed costs in January
1978 dollars associated with Option I for
controlling particulate emissions from a
90 Mg/day pressed and blown glass
furnace melting soda-lime formulations
would be about $615 thousand for an
ESP and about $770 thousand for a
fabric filter. Incremental installed costs
associated with Option II would be
about $450 thousand for an ESP, and
about $680 thousand for a fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
1.4 times the incremental installed costs
associated with Option II, if ESP's were
selected. If fabric filters were selected
the incremental installed costs
associated with the Option I level of
control would be about 1.1 times the
incremental installed costs associated
with Option II.
Incremental annualized costs for a 90
Mg/day furnace associated with Option
I would be about $175 thousand/year
and about $235 thousand/ year for an
ESP and a fabric filter, respectively.
Incremental annualized costs associated
with Option II would be about $130
thousand/year for an ESP, and about
$205 thousand/year for a fabric filter.
The incremental annualized costs
associated with Option I would be about
1.3 times the incremental annualized
costs associated with Option II if ESP's
were used. If fabric filters were used the
incremental annualized costs associated
with Option 1 would be about 1.1 times
the incremental annualized costs
associated with Option II.
Based on the use of control equipment
with the highest annualized cost, a price
increase of about 0.6 percent would be
necessary to offset the costs of installing
control equipment on the large pressed
and blown glass furnace melting soda-
lime formulations to meet the emission
limits of Option I. A price increase of
about 0.5 percent would be necessary to
comply with the emission limits of
Option II.
Incremental cumulative capital costs
for the 1978-1983 period associated with
Option I for the six new 90 Mg/day
furnaces would be about $3.7 million if
ESP's were used. Use of ESP's to comply
with Option II would require
incremental cumulative capital costs of
about $2.7 million for the same period.
Fifth-year annualized costs for
controlling these glass melting furnaces
to comply with Option I would be about
$1.1 million. To comply with Option II,
fifth-year annualized costs would be
about $790 thousand.
A summary of incremental impacts (in
excess of impacts of the typical SIP
regulation) associated with Option I and
Option II is shown in Table II for both
small and large furnaces. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.
Tabto II.—Summary of Incremental Impacts
Associated With Regulatory Options
Impacts
Air1 Water Energy* Economic1
I 122 None
II 101 None
-3.0
-3.0
-0.6
-0.5
'Mg/Yr. reduced
'Barrel, of oil/day.
• Ptrcent pric* iocrnM.
Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact,
the reasonableness of energy and costs
impacts, and the general availability of
demonstrated emission control
technology leads to the selection of
Option I as the basis for standards for
pressed and blown glass furnaces
melting soda-lime formulations.
Pressed and Blown Glass—Other Than
Soda-Lime Formulations
Uncontrolled particulate emissions
from furnaces in this sector are about 5
g/kg (10 Ib/ton) of glass pulled.
Emission tests using EPA Method 5 on
four furnaces melting borosilicate
formulations and equipped with ESP's
yielded a representative emission rate of
about 0.50 g/kg (l.Olb/ton) of glass
pulled. A single emission test using EPA
Method 5 on an ESP-controlled furnace
melting fluoride/opal formulations
yielded an emission rate of 0.17 g/kg
(0.34 Ib/ton) of glass pulled. EPA
Method 5 tests of six ESP-controlled
furnaces melting lead glass yielded a
representative emission rate of 0.12 g/kg
(0.24 Ib/ton) of glass pulled. A single
EPA method 5 emission test of an ESP-
controlled furnace melting potash-soda-
lead glass yielded an emission rate of
0.03 g/kg (0.06 Ib/ton) of glass pulled.
An EPA method 5 emission test on a
furnace equipped with a fabric filter and
melting soda-lead-borosilicate glass
produced an emission rate of 0.17 g/kg
(0.34 Ib/ton) of glass pulled.
Upon consideration of the data cited
above, an emission limit of 0.25 g/kg (0.5
Ib/ton) of glass pulled was identified as
a reasonable limit for control for
pressed and blown glass furnaces
melting other than soda-lime
formulations. This limit was selected for
Option I; it provides for about 95 percent
particulate removal. Option II would set
an emission limit of 0.5 g/kg (1.0 Ib/ton)
of glass pulled, which provides for a
particulate removal of about 90 percent.
Fabric filters and ESP's could be
designed to achieve the levels of
emission reduction required by either
regulatory option.
By 1983 approximately 70 Gg/year
(77,200 ton/year) of additional.
production is anticipated in this sector.
One 45 Mg/day (50 ton/day) (small)
furnace and two 90 Mg/day (100 ton/
day) (large) furnaces would be built in
order to provide this production. If
uncontrolled, emissions from the one
new small pressed and blown glass
furnace melting formulations other than
soda-lime would add about 90 Mg/year
(100 ton/year) to national particulate
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emissions by 1963, while the emissions
from the two new large furnaces would
add about 260 Mg/year (287 ton/year)
during the same period.
Compliance with a typical SIP
regulation would reduce the impact from
the small furnace to about 27 Mg/year
(30 ton/year). Control to the Option I
emissions limit would reduce the
emissions to about 17 percent of those
emitted under a typical SIP regulation.
With Option II emissions would be
reduced to about 33 percent of those
emitted under a typical SIP regulation.
Compliance with a typical SIP
regulation would reduce the impact of
the large furnances to about 47 Mg/year
(52 ton/year). Under Option I, these
emissions would be reduced to about 28
percent of those emitted under a typical
SIP regulation. Under Option II, the large
furnace emissions would be reduced to
about 56 percent of those emitted under
a typical SIP regulation.
The effect of a typical SIP regulation
for both large and small furnaces would
be a reduction of about 79 percent.
Under Option I, emissions would be
reduced to about 25 percent of those
emitted under a typical SIP regulation.
Under Option II, emissions would be
reduced to about 50 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled 45 Mg/day pressed and
blown glass furnace melting
formulations other than soda-lime would
be less than 1 p.g/m9, as would be the
concentrations resulting from
compliance with a typical SIP
regulation, Option I, or Option II.
Corresponding annual maximum
ground-level concentrations near a 90
Mg/day furnace also would be less than
1 /Ag/m»
The calculated maximum 24-hour
ground-level concentration near an
uncontrolled 45 Mg/day furnace in this
sector would be 11 w?/ms. This
concentration would be reduced to 3 p.g/
ms with a typical SIP regulation. With
Options I and II, the concentrations
would be reduced to 1 fig/m* or less.
The calculated maximum 24-hour
ground-level concentration near an
uncontrolled 90 Mg/day fumance would
be 14 u£/ms. This concentration would
be reduced to 3 ng/m* with a typical SIP
regulation and to below 1 fig/m* with
Option I; with Option II it would reach 2
M8/m>-
Since fabric filters and ESP's are
likely to be the control systems installed
on furnaces in this sector to comply with
standards, there would be no water
pollution impact associated with
standards based on either Option I or
Option II.
Under a typical SIP regulation, about
64 Mg/year (71 ton/year) of particulate
matter would be collected from the one
new 45 Mg/day furnace projected to
come on-stream in the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about
23 Mg/year (25 ton/year] and 18 Mg/
year (20 ton/year), respectively, to the
solid waste collected under a typical SIP
regulation. Option I would increase the
mass of solids by about 36 percent over
that resulting from compliance with a
typical SIP regulation, and Option II
would increase it by about 28 percent.
Under a typical SIP regulation, about
210 Mg/year (232 ton/year) of
particulate matter would be collected
from the two new 90 Mg/day furnaces
projected to come on-stream in the 1978-
1983 period. Compliance with standards
based on Option I and Option II would
add about 34 Mg/year (38 ton/year) and
21 Mg/year (23 ton/year), respectively,
to the solid waste collected under a
typical SEP regulation. Option I would
increase the mass of solids by about 16
percent over that resulting from
compliance with a typical SIP
regulation, and Option II would increase
it by about 10 percent. The total mass of
solids for disposal collected from all
three new furnaces in this sector,
associated with Option I and Option n,
would be about 57 Mg/year (63 ton/
year) and about 39 Mg/year (43 ton/
year), respectively.
The additional solid material
collected under Option I or Option II
would not differ chemically from the
material collected under the typical SIP
regulation. Collected solids either are
recycled back into the glass melting
process or are disposed of in a landfill.
Recycling of the solids has no adverse
environmental impact, and, since
landfill operations are subject to State
regulation, this disposal method also is
not expected to have an adverse
environmental impact.
Since ESP's have been the
predominant control system used in the
industry and are anticipated as the
predominant system to be used for new
plants coming on-stream between 1978-
1983 regardless of which regulatory
option is selected, energy requirements
estimated for the typical SIP regulation,
Option I, and Option n are based on the
use of ESP's.
The energy required to control
particulate emissions from the new 45
Mg/day pressed and blown glass
furnace malting formulations other than
soda-lime to the level required by the
typical SIP regulation would be about
2.7 million kWh (1,500 barrels of oil/
year). The energy required to comply
with the Option I and Option II
emissions limits would be essentially
the same as that required for meeting a
typical SIP regulation.
Control to the level required by a
typical SIP regulation of the two new 90
Mg/day pressed and blown glass
furnaces melting formulations other than
soda-lime and projected to come on-
stream during the 1978-1983 period
would require about 6.6 million kWh
(3,700 barrels of oil/year) if an ESP were
used. The energy requirements to
achieve the Option I and Option II
emission limits would be essentially the
same as the requirements for meeting a
typical SIP regulation.
The energy required to comply with
the emission limits of the regulatory
options would be about 0.1 percent of
total energy use for all new furnaces in
this glass manufacturing sector.
Considering the small amounts of
additional oil and electricity required
and the slight increase in total energy
use in this sector, the energy impacts of
either Option I or Option II would be
negligible.
Incremental installed costs in January
1978 dollars associated with Option I for
controlling particulate emissions from a
45 Mg/day pressed and blown glass
furnace melting formulations other than
soda-lime would be about $760 thousand
for an ESP and about $235 thousand for
a fabric filter. Incremental installed
costs associated with Option n would
be about $320 thousand for an ESP, and
about $190 thousand for a fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
2.4 times the incremental installed costs
associated with Option II if ESP's were
selected. If fabric filters were selected
the incremental installed costs
associated with the Option I level of
control would be about 1.2 times the
incremental installed costs associated
with Option n level of control.
Incremental annualized costs for a 45
Mg/day furnace assoicated with Option
I would be about $230 thousand/year
and about $70 thousand/year for an ESP
and a fabric filter, respectively.
Incremental annualized costs associated
with Option n would be about $95
thousand/year for an ESP, and about
$60 thousand/year for a fabric filter. The
Incremental annualized costs associated
with Option I would be about 2.4 times
the incremental annualized costs
associated with Option II if ESP's were
used. If fabric filters were used the
incremental annualized costs associated
V-CC-9
-------
with Option I would be about 1.2 time*
the incremental annnalized costs
associated with Option IL
Based on die nee of control equipment
with the highest annualized costs (worse
case conditions), a price increase of
about 0.4 percent would be necessary to
offset the costs of installing control
equipment on a 45 Mg/day pressed and
blown glass furnace melting other than
soda-lime formulations to meet the
emission limits of Option I. A price
increase of about 0.3 percent would be
necessary to comply with the emission
limits of Option n.
Incremental cumulative capita! costs
for the 1976-1963 period associated with
Option I for the 45 Mg/day furnace
would be about $235 thousand if an ESP
were used. Use of an ESP to comply
with Option H would require
incremental cumulative capital costs of
about $190 thousand for the same
period. Fifth-year annualized costs for
controlling this furnace in this sector to
comply with Option I would be about
$70 thousand. To comply with Option II,
fifth-year annnalized costs would be
about $60 thousand.
Incremental Installed costs in January
1978 dollars associated with Option I for
controlling participate emissions from a
90 Mg/day pressed and blown glass
furnace melting other than soda-lime
formulations would be about $800
thousand for an ESP and about $260
thousand for a fabric filter. Incremental
installed costs associated with Option II
would be about $140 thousand for an
ESP, and about $180 thousand for a
fabric filter. The incremental installed
costs of control equipment associated
with the Option I level of control would
be about 5.7 times the incremental
installed costs associated with Option n
if ESFs were selected. If fabric filters
were selected the incremental installed
costs associated with the Option I level
of control would be about 1.4 times the
incremental installed costs associated
with Option n.
Incremental annualized costs for a 90
Mg/day furnace associated with Option
I would be about $245 thousand per year
and about $85 thousand per year for an
ESP and a fabric filter, respectively.
Incremental annualized costs associated
with Option 0 would be about $45
thousand per year for an ESP, and about
$55 thousand per year for a fabric filter.
The incremental annualized costs
associated with Option I would be about •
5.4 times the incremental annualized
costs associated with Option H if ESFs
were used. If fabric filters were used the
incremental annualized costs associated
with Option I would be about LS times
the incremental annualized costs
associated with Option II.
Based on the use of control equipment
with the highest annualized costs, a
price increase of about 0.8 percent
would be necessary to offset the costs of
installing control equipment on the 90
Mg/day pressed and blown glass
furnace melting formulations other than
soda-lime to meet the emission limits of
Option I. A price increase of about 0.5
percent would be necessary to comply
with the emission limits of Option II.
Incremental cumulative capital costs
for the 1878-1963 period associated with
Option I for the two new 90 Mg/day
furnaces would be about $500 thousand
if fabric filters were used. Use of ESP's
to comply with Option II would require
incremental cumulative capital costs of
about $300 thousand for the same
period. Fifth-year annualized costs for
controlling these glass melting furnaces
to comply with Option I would be about
$160 thousand. To comply with Option
Q, fifth-year annualized costs would be
about $85 thousand
A summary of incremental impacts (in
excess of impacts of the typical SIP
regulation) associated with Option I and
Option II is shown in Table III for both
small and large furnaces. Air impacts,
expressed in Mg/year of paniculate
matter emissions reduced, would
approximate the quantity of participate
matter collected and disposed of as
soild waste.
T*te HI.—Summary of Incremental Impact
Associated tHth fboutotory Opt/ons
A*' Water Enemy* Eoonomc1
ReguMovy
option:
67 No
-Negligible..
M Nora Nagkgtote..
-0.7
-04
•Mg/Yr
'P«OM* price
Consideration of the beneficial impact
on national particulate emissions, lack
of water pollution impact, the small
potential for adverse solid waste impact.
the lack of energy impact, the
reasonableness of cost impacts, and the
general availability of demonstrated
emission control technology leads to the
selection of Option I as the basis for
standards for pressed and blown glass
furnaces melting formulations other than
soda-lime.
Wool Fiberglass
Uncontrolled particulate emissions
from wool fiberglass furnaces are
generally about £ g/kg (10 Ib/tonj of
glass pulled. The average emission from
three furnaces in the wool fiberglass
sector equipped with ESP's was 0.18 g/
kg (0.36 Ib/ton) of glass pulled. EPA
Method 5 tests of three furnaces
equipped with fabric filters indicated
emissions of 0.2 g/kg (0.4 Ib/ton), 0.26 g/
kg (0.52 Ib/ton). and 0.55 g/kg (1.1 lb/
ton) of glass pulled. The test data cited
indicate that an emission limit of 0.2 g/
kg (0.4 Ib/ton) of glass pulled could be
met through the use of an ESP and that a
limit of 0.4 g/kg (0.8 Ib/ton) of glass
pulled could be met through the use of
either an ESP or a fabric filter.
On the basis of these conclusions, two
regulatory options for reducing
particulate emissions from wool
fiberglass furnaces were formulated.
Option 1 would set an emission limit of
O-2 g/kg (0.4 Ib/ton) of glass pulled,
which would provide for about 95
percent particulate removal Option II
would set an emission limit of 0.4 g/kg
(0.8 Ib/ton) of glass pulled, which would
provide for about 90 percent removal of
particulates.
By 1983 approximately 360 Gg/year
(397,000 ton/year) of additional
production is anticipated in the wool
fiberglass sector. About six new wool
fiberglass furnaces of about 180 Mg/day
(200 ton/day production capacity (the
size of the model furnace) would be
built in order to provide this additional
production. If uncontrolled, these new
wool fiberglass furnaces would add
about 1,800 Mg/year (1,984 ton/year) to
national particulate emissions by 1983.
Compliance with a typical SIP
regulation would reduce this impact to
about 210 Mg/year (232 ton/year).
Under Option I, emissions would be
reduced to about 33 percent of those
emitted under a typical SIP regulation.
Under Option II, emissions would be
reduced to about 66 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled wool fiberglass furnace
producing 180 Mg/day of glass would be
about 2 fig/ms. The annual maximum
ground-level concentrations resulting
from compliance with a typical SIP
regulation, Option I, or Option II would
be less than 1 jig/m*. The calculated
maximum 24-hour ground-level
particulate concentration near an
uncontrolled wool fiberglass furnace
producing 180 Mg/day of glass would be
about 29 fig/m'. The corresponding
concentration for complying with a
typical SIP regulation would be about 3
ug/ms. Under Option I with an ESP
employed for control, the maximum 24-
V-CC-10
-------
Federal Register
44, No
F:sda> ]une 15, 1979 /
Rales
.-. ,i'i; gr und ieve; concentration wnu'1
be redu ,ec 'o - ^g, rr* Under Option i]
it would oe reduced to 3 end 4 ng/m*
with the fabric filter and ESP,
respectively
Since fabric Alters and ESP's ar«
.ike;v to ye '.T- control systems ms*al!<-'d
:; A'tjoi fiberglass fun'Hcee t comp;y
*:!•• Mipnua"d!> Ihprp would ';"! no ',V>'D'
M; po"1 lr':r)ii,;! aghOt.'ited With
nd for a-: ESP and a fabric filter,
-«8pectiveiy The incremental installed
costs of control equipment associated
with the Option I level of control would
be nearly 5 times the incremental
installed costs associated with Option 11
if ESP's were selected !f fabric filters
were 8eifj.'!pd, the incremental installed
•osts i -•., i;u: about S:.:X!
T«W« IV.—6 jmma/y o< incremental Impacts
Associated With •iagu/atory Options
Impact*
Energy' Economic'
'tegutatcry
option
OJ
0.1
jnc» **»•§•
m •"
10
>'<•>!: if >he beneficial impact
~>ar»!cuia'e emission*, the
r ->oOutiin impact the small
i'-versi-' wid wa^te impact,
~- .-*• f e~,?rg\ md cost
^ t'. 'ier-.«, ava-i-ibillty of
•-• - -S nn '•";t,''}1
, c •• ^P!^, -. in of
• <• - •• «• j.'.'j-jrds for
"s. f • ,\ . . -
; ,- »t "! •• i j
1 - 'U;C "1O! c;rf(T '•'•".;:,' •
' i , H )•"•" CC'llf% '-C '.' =!tj '
T1 '!/•>; 'n' •; )•' it J"e Jisp'.^e'l c! " i
v- 'fii «'- ',- ->a ';: ,' f sou'Js rnu
-. i. H ••.-(•"»• ,1 .f'Tjentai TH-act an'1
'- e ',;!'!."'!' '"^rations ai'f *ii'nc
v ' •-( :.; ; ;": 'his oi8p<>8. TIP'" •''
t> , » :,lt -pr-pQ r,, >;i-.,c- •" a-" •*•
i ' "f1: , .T.r/aci
1 ;- ,: .i '>.: .''servj , et. „ •••d '>,
I'linc fi't- erri'Si'OCF '"rr i,^
,>(! - -.fj- on-sf^ar" • It;' >* '
' •; T:-!\- 'A'.th 3 ' "-;:8' '-•'
-A . ':ui be aoci1! '*. 1 n:!'1 :
' 4 J , -r- * si! jf OH \ , ' .f
• ' n 'i iv n)ta"):« >,»•"•• i , 3-"
v! • . , '-.' ; ri -ft tor r'it* -;"-3'T?
— 11 ••! f >! • <;T- , 'r-tion or.'sri*? -1 -
vc1 i1" ')e n 'g'.g'.ble — onjy .irc-it N'
m-rf-la r^f oil year
Incremental .retailed nos's ;• [an irv
:97fi doliam essoriated with Option •> li-r
jon':o''iae pf-rticulate emissions f^orn 3
*flO Mj?,'duy '.von fiberglass fumare
•vcuic be airut S500 thobsano for ->-
7-SP and dbo; ' $-1 thousand for a :;.; -
liter IncreTi-'nta, installed "ost(>
.issoc;ate i wth "'ption il woui-i v-'
ioo'.jr SI1 } th ?nsnnd ann abet* $3<'
1 •' " ••' --t I •*,.'. 1J J. 2-'0 '-OS'- dSSO^ia Ml
• • a ' K~-'J -vere asec ,f
;•;••• ::, 'i "*< * •? -Si-c 'h^ .ncrementa;
, ,,- ; • nzej -.'.s astii^; ateo with Option
. ntiii (i Tf- auu,.! "wo fitnes the
t • r*""f'pfd; annuajzea costs associated
-v.:h :pi:onil.
^a,tf»ii <\ 'he uee of contro. equipment
•<\!tn 'tie "igfjes' prirmazea costs (worst
case 'nnaitions., a price increase of
so ,u; U: T,t'rr;ent would bfc lecessary to
.ufset ;ritj ccs!« oi T.std.lmg control
•"cuipnent on j '80 Mg/day wool
''•;*,(;.'H.-iSS urnace "c meet tne emission
imitf -jf Oo"oi' i A ance ;ncrease of
i'Xiu •). 1 oev- fit would be necessary to
:cirnr >vin« witn 'he rtmsssion limits of
.'DUi 11 U
nr"^rri ".«• am native capital costs
' " '_!r - ?s< .lew 1wi Mg, day wool
" *'.-4 338 furnaces rinng the 1978-1983
" "]"• : -sssocia1- a wr.h Option I would
•• ar i>u( S3 mii icr: f F.SP's were asea
"•^e f i fr>hnc ^''ers -n comply with
'tjtirn ;' wouj'1 rt-nsnre mcrementa!
\ni: Jti.t> -a; ta, -JOB'S o! about S185
' ^usinc'or r.-spi-,' oenoa ;'iftr. yeiir
r u -azeu rosis icr contromng A joi
:~erg!;M9 rumdoes compiy.ng with
Option 1 woijjd be aoout $930 thousand.
To comply with Option 0, fifth-year
ii.nuaiized costs would be about $60
thousand.
A summary of incremental impacts
associated with Option I and Option Q
is shown in Table IV. Air impacts.
expressed in Mg/year of participate
matter emissions reduced, wouid
loproximate the quantity of participate
•natter collected and disposed of as
jriid waste.
"•' • •-*•• - !?•»••'-'-iJate emissions
*mn' rfe' "l •>-:» ^s-nares an.- about 1.5 g/
*g 13.0 T*.in] oi glass pulled Iliere are
?,o emissions tes' oata for flat glass
furnaces eouippea ^ith control devices
available for evaluation. However, the
soda-limp formulations melted in these
furnaces HH? quite simila^ TO those
aaeited "n container glass furnaces-, as
are 'i-e caetmnal composition and
physical haractenstics of the
oarticuiate emissions The pnmary
•lifference between t on;.uner glass and
flat giaBs ^irnaces :s that the
inconrroilen emission rates of flat glass
''urnaces are greater Given the
-Mmjlarrv of processes, niass
rmuiations. and emissions it is
•ixpecipn 'hat the percentage reduction
i n«r»,. i-.'au. emissions acnievedby
con'roi of Container glass '"umaces also
be a-:oieved with flat glass
This conclusion :s supported
-------
Federal Register / Vol. 44. No. 117 / Friday. June 15. 1979 / Proposed Rules
consistency, therefore. Option II would
set an emission limit of 0.3 g/kg (0.6 lb/
ton) of glass pulled, which would
provide about 80 percent control.
By 1983 approximately 240 Gg/year
(264,555 ton/year) of additional
production is expected in the flat glass
sector. One new flat glass furnace of
about 635 Mg/day (700 ton/day)
capacity (the size of the model" furnace)
would be built in order to provide this
additional production.
If uncontrolled, this new flat glass
furnace would add about 380 Mg/year
(397 ton/year) to national participate
emissions by 1983. Compliance with a
typical SIP regulation would reduce this
impact to about 90 Mg/year (100 ton/
year). Under Option I, emissions would
be reduced to about 40 percent of those
emitted under a typical SIP regulation.
Under Option D. emissions would be
reduced to about 80 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled flat glass furnace
producing 635 Mg/day of glass would be
about 1 fig/m*. The annual maximum
ground-level concentrations resulting
from compliance with a typical SIP
regulation, Option L or Option II, would
be less than 1 jig/ml The calculated
maximum 24-hour ground-level
particulate concentration near an
uncontrolled flat glass furnace
producing 635 Mg/day of glass would be
about 21 ug/m3. The corresponding
concentration for complying with a
typical SIP regulation would be about 5
Ug/m3. Under Option I, this
concentration would be reduced to
about 2 jig/ms. Under Option n it would
be reduced to about 5 >ig/ms.
Since the ESP is likely to be the
emission control system installed on flat
glass furnaces to comply with standards,
there would be no water pollution
impact associated with standards based
on either Option I or Option IL
Under a typical SIP regulation, about
270 Mg/year (298 ton/year) of
particulate matter would be collected
from the one new 635 Mg/day flat glass
furnace projected to come on-stream in
the 1978-1983 period. Compliance with
standards based on Option I and D
would add about 50 Mg/year (55 ton/
year) and about 20 Mg/year (22 ton/
year), respectively, to the solid waste
collected under a typical SIP regulation.
Option I would increase the mass of
solids for disposal by about 20 percent
over that resulting from compliance with
a typical SIP regulation, and Option D
would increase it by about 7 percent.
The additional solid material collected
under Option 1 or Option n would not
differ chemically from the material
collected under a typical SIP regulation.
Collected solids either are recycled back
into the glass melting process or are
disposed of m a landfill. Recyling of the
solids has no adverse environmental
impact, and, since landfill operations are
subject to State regulations, this
disposal method also is not expected to
have an advene environmental impact.
Since the energy requirements for an
electrostatic pretipitator do not vary
significantly over the range of emission
reductions considered here, the estimate
of energy required to control particulate
emissions from the one new flat glass
furnace would be about the same for
compliance with a typical SIP
regulation, Option I. or Option n—about
7.8 million kWh (4,300 barrels of oil/
year). The energy required to comply
with the emission limits of the
regulatory options would be about 0.2
percent of the total energy use in the flat
glass sector. There would be no
incremental energy impact associated
with either Option I or Option n as
compared with a typical SIP regulation.
The incremental installed cost in
January 1978 dollars associated with
Option I for controlling particulate
emissions from a 635 Mg/day flat glass
furnace would be about $605 thousand.
Incremental installed cost associated
with Option n would be about $140
thousand. The incremental installed cost
of control equipment associated with the
Option I level of control would be
somewhat more than four times the
incremental installed cost associated
with the Option II level of control
Incremental annualized cost
associated with Option I for a 635 Mg/
day flat glass furnace would be about
$190 thousand/year; the corresponding
incremental annualized cost for Option
II would be about $45 thousand/year.
The incremental annualized cost
associated with Option I would be more
than four times the incremental
annualized cost associated with Option
n.
A price increase of about 0.4 percent
would be necessary to offset the cost of
installing as ESP on a 635 Mg/day flat
glass furnace to meet the emission limit
of Option I. A price increase of about 0.1
percent would be necessary to comply
with the emission limit of Option n.
Incremental cumulative capital cost
for the one new 635 Mg/day flat glass
furnace during the 1978-1983 period
associated with Option I would be about
$605 thousand. Compliance with Option
II would require an incremental
cumulative capital cost of about $145
thousand for the same period. Fifth-year
annualized costs for controlling the one
new flat glass furnace to comply with
Option I would be about $190 thousand.
To meet the Option II emissions limit,
fifth-year annualized costs would be
about $45 thousand.
A summary of incremental impacts
associated with Option I and Option II
is shown in Table V. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.
Tcbte V.—Summary of Incremental Impacts
Afsooated With Regulatory Options
Mr1
Enogy* Economic'
Regulatory
option
I S20 None NegtgM* - -0.4
U 290None.-_._Nagtgibto-_ —0.1
'Mg/Yr. reduced
•Barrels of oil/itojr.
'fmvtmt pnoe IOITMW.
.Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact,
the lack of energy impact, the
reasonableness of cost impacts, and the
general availability of demonstrated
emission control technology leads to the
selection of the Option I as the basis for
standards for glass melting furnaces in
the flat glass sector.
Summary
If uncontrolled, total particulate
emissions from the 45 new glass melting
furnaces projected to come on-etream
between 1978 and 1983 would be about
5,200 Mg/year (5,732 ton/year).
Compared to a typical SIP regulation,
Option I would reduce particulate
emissions by an additional 1,100 Mg/
year (1,213 ton/year).
Ambient dispersion modeling
indicates that the annual maximum
ground-level particulate concentrations
near uncontrolled glass melting furnaces,
would be 2 fig/m' or less. Both a typical
SIP regulation and the Option I emission
limits would reduce the annual
maximum ground-level particulate
concentrations to under 1 /ig/m.The 24-
maximum ground-level particulate
concentrations near uncontrolled glass
melting furnaces would be less than 30
Ug/m3, with a median concentration of
about 11 fig/ms. Under a typical SIP
regulation these concentrations would
be reduced to 5 /ig/msor less. Control to
the Option I emission limits would
V-CC-12
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Federal Register / Vol. 44, No. 117 / Friday. June 15. 1979 / Proposed Rules
reduce the 24-hour maximum ground-
level concentrations near glass melting
furnaces to about 2 pg/m* or less.
The glass manufacturing process has
minimal water pollution potential.
Complying with a standard based on
Option I would have a negligible water
pollution impact, because control
systems installed to meet Option I
would not discharge waste water
streams.
The amounts of solid waste generated
in the control of particulates from glass
melting furnaces would approximate the
amount of particulate removed from
exhaust gases. Compliance with a
typical SIP regulation would produce
3,700 Mg (4,080 tons) of solid waste per
year. Meeting the Option I emission
limits would generate an additional
1,100 Mg/year (1,213 ton/year). Either
recycling or landfilling would present
minimal adverse environmental impact.
Totally recycling the collected solids
would have no adverse impact.
Landfilling operations must meet State
regulations, and therefore this disposal
method would have limited potential for
adverse environmental impact.
Implementing Option I would require
about 1.6 million kWh of electricity to
power the emission control equipment
installed above the requirements for
implementing a typical SIP regulation.
To meet this power requirement electric
utilities would require about 950 barrels
of oil/year, or about 3 barrels/day. The
energy that would be required to
operate emission reduction sytems to
meet a standard based on the Option I
limits would be 2 percent or less of the
total energy used in glass production.
Incremental cumulative capital costs
to the glass manufacturing industry for
controlling emissions from new glass
melting furnaces projected to come on-
stream during the 1978-1983 period to
comply with a standard based on the
Option I emission limits would be about
$27.9 million. The fifth-year annualized
costs to the glass manufacturing
industry associated with compliance
with the Option I emission limits would
be about $8.4 million. An industry-wide
price increase of about 0.7 percent
would be necessary to offset the costs of
installing control equipment to meet the
emission limits of Option L
Modification, Reconstruction, and Other
Considerations
An exemption from provisions of the
modification section (40 CFR § 60.14] is
proposed for those plants which convert
to fuel-oil firing, even though particulate
emissions would more than Likely be
increased. The primary objective of the
proposed standards is to control
emissions of particulates from glass
melting furnaces. The data and
information supporting the standards
consider essentially only those
emissions arising from the basic melting
process, not those arising from fuel
combustion. It is not the prime purpose
of these standards, therefore, to control
emissions from fuel combustion per se.
Consequently, since emissions from fuel
combustion are small in comparison
with those from the basic melting
process, and a conversion of glass
melting furnaces to firing oil rather than
natural gas will aid in efforts to
conserve natural gas resources, the
standards proposed herein include a
provision exempting fuel switching in
glass melting furnaces from
consideration as a modification. The
proposed increment in emissions
allowed fuel oil-fired glass melting
furnaces is 15 percent, a small
allowance; however, without this
exemption there would be a large
economic impact on the industry.
An exemption from reconstruction
provisions (40 CFR § 60.15) is proposed
for the cold refining (rebricking) of the
melter of an existing furnace. Under 40
CFR § 60.15 the Administrator must be
notified of intent to conduct such a
procedure 60 days in advance of
commencement, and will determine
whether or not the rebricking constitutes
a reconstruction. This rebricking
procedure has been a routine operation
in the glass manufacturing industry and
would not generally be considered an
opportunity to evade the provisions of
the standard by unduly extending the
useful life of an existing glass melting
furnace. Therefore, the exemption of
rebricking from reconstruction provision
has been proposed.
Glass melting furnaces fired with
number 2 fuel oil would be expected to
exhibit a 10 percent increase in
particulate emissions over those
produced in gas-fired furnaces since
particulates are formed by the
combustion of oil. Similarly, furnaces
fired with numer 4, 5, or 6 fuel oil would
show a 15 percent increase in
particulate emissions over those
produced in gas-fired furnaces. This
effect of fuel oil on furnace emissions
being recognized, it is proposed that the
emission limits for furnaces fired with
fuel oil be the limits for gas-fired
furnaces multiplied by 1.15. It is
additionally proposed that
simultaneously liquid and gas-fired
furnaces have emission limits based on
an equation, taking into consideraton
the relative proportions of the fuels
being fired.
Selection of Performance Test Methods
The use of EPA Reference Method 5—
"Determination of Particulate Emissions
from Stationary Sources" (Appendix A,
40 CFR § 60, Federal Register, December
23,1971) is required to determine
compliance with the mass standards for
particular matter emissions. Emission
test data used in the development of the
proposed standard were obtained either
by the LAAPCD sampling method or by
EPA Method 5. However, results of
performance tests using Method 5
conducted by EPA on existing glass
melting furnaces comprise a major
portion of the data base used in the
development of the proposed standard.
EPA Reference Method 5 has been
shown to provide a respresentative
measurement of particulate matter
emissions. Therefore, it has been
included for determining compliance
with the proposed standards.
Calculations applicable under Method
5 necessitate the use of data obtained
from three other EPA test methods
conducted previous to the performance
of Method 5. Method 1—"Sample and
Velocity Traverse for Stationary
Sources" must be conducted in order to
obtain representative measurements of
pollutant emissions. The average gas
velocity in the exhaust stack is
measured by conducting Method 2—
"Determination of Stack Gas Velocity
and Volumetric Flow Rate (Type S Pilot
Tube)." The analysis of gas composition
is measured by conducting Method 3—
"Gas Analysis for Carbon Dioxide,
Oxygen, Excess Air and Dry Molecular
Weight." These three tests provide data
necessary in Method 5 for converting
volumetric flow rate to mass flow rate.
In addition, Method 4—"Determination
of Moisture Conent in Stack Gases" is
suggested as an accurate mode of
predetermination of moisture content.
Since the proposed standards are
expressed as mass of emissions per unit
mass of glass pulled, it will be
neccessary to quantify glass pulled in
addition to measuring particulate
emissions. Glass production in Mg shall
be determined by direct measurement or
computed from materials balance data
using good engineering practices. The
materials balance computation may
consist of a process relationship
between feed material input rate and the
glass pull rate. In all materials balance
computations, glass pulled from the
furnace shall include product, cullet, and
any waste glass. The hourly glass pull
rate for a furnace shall be determined
by averaging the glass pull rate over the
time of the performance test.
V-CC-13
-------
iposed Rules
Selection -T': Mon'to.-n;. Requirements
To provide a convenient means for
enforcemen! personnel to ensure that
installed emission control systems
comply with standards >f performance
through proper operation and
maintenance, monitoring requirements
are generally included :r «tandards of
performancp For glass melting furnaces
the most strniRhtJorwar -nears of
ensuring prou* t -:nj i « *. -ior;n
released to Hn" t'Tiosp""'" EPXna-,
established o< ,'•• -,;<';* r:','*
3
acrm«i working hours d> EPA 3 Centra'
Docket Section -,n Washington I) C. .'See
ADDRESSES section of this preamble]
Miscellaneous
Thf- JocKe' IB an organized and
;omp,cte fre or all '.he 'niormation
considered bv EPA in the development
•ji '.hi,- rjiem.su Tig The pnnc;oai
if ; .•! 'he -K • ke! d-e '"i ',: a.ic-w,
. • ; '-.e'-sons -n laeitm ana lor.it-
ietfii r
-rrussi
scvin
c tn
7i a -i;!tt
ire hp
So'-' .
•f -,-ii;
inly play as prominent a roll- "
iming the "lowest achievable
n rate" for new or modified
"i .ocating in nonattainmert areas
rsp areas where statutorily-
en nealth and welfare stand. ir^
y violated. In this resper".,
T3 of the Act reqmrt s 'ha: n<''-
,f ed sources construr/po n an
^::h 8 in violation of "he \AA(J-
' ?ro ssions to -" --vei
•• ,• -s *hp ""-owe"! - <-'<-.\ .j":'
AER: ,P -
1 ' " 9 hr^ •=-.
mt-iV ,> 'i>m«{:e-. '" ,'.- . > j sampling
information on <>;••),
there are no continu•"!••
monitors oppratn.y ir.
cor.squfiiu!
> tie \ c'
emission rate rplur: >,'«
available R»snlu'!-, r;
prob.ems, den-!,); '"err
stars,ards *V rTstiii. ssicn rate
reiat or
dpvp,r,pment orogrh T' F-ir these
reasons, continuous nor.i'ormg of
particuiate emissions f"rom gia.se melting
furna'ps would no' ^r ••iquirec '">y the
pror.'Sec standard -
Public Hearing
A public hearing wslj 'oe leid fo
discuss these proposed standards 'n
accordance with Section 307fd)(5i of the
Clean \ir Act, Persons wishing 'o maxe
oral presentations sho'iid contact EPA
at the address given in the ADDRESSES
section of this preamble, Oral
presentations will be limited So 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Docket address
given in the ADDRESSES section of this
preamble.
A verbatim transcript of »he hearing
and written statement!) will be available
for public inspection and copying during
,."Jv ,, . - .-p. • , ,
•xpei's 3' •'• <'.:e
.'.- ,ia • ir.ng
lear ».r At.'. -pfl
,jjr-
.aoac.f -t rpi'-'C'rvs "-JOISSKJUS :x- ow
'hose .f, e:3 requ.ied o corni \ =/\if. Lit;
jtanOdras of pt-!crm>
mpos'Mon of a more stringent emission
standard in several situations For
axampie, applicable costs do not
• " on ,' signifi ,d i
- -* iif quality ."•
' i • ^* "hese '•:• •• >-
^: ",i n sourit > ,:"
' *-v;r ; employ L< '
' oo 169! Ji"' . ' -
: ." .r^o under •'".
" ' '^cnnoi-,,, ,
~ .r. r-d on d b i->e
'-, f. fi^v, «?fi\:r ci'i'
i"~ n ::; and otrir < '
. ;jy an ,j ,'.•.,
« i r>dt-M.r.r
?• ..IP * .
- • •-.' i i inainl>-.' . ,
'•'•'• r.r quant ' ••'
v, :t-n o proiPf!
• •• • v-jif.3fu for this p
SF'-i - ,. r soT.c cases "(-LI .re grec.-.
;rn>.s,,u -nuctujns than those reouirc
0- itd-i i',]s of ."if'rformann- * i1" Tirw
sources
rina:!', f idles, are free under Section
IW of t);,; ,\ci to establish even more
:" limits than those estaolisheii
i': son 111 of those necessary U
attain or "tminta-n the NAAQS -jnoer
ipctior. 10 Accordingly, new source;
7. ,v '.'; #or i> ^asts be suoject ;t
imitai u,i.s ,nore stringent tnan £PA >
*irtr.d«n:s (jf jerformanct; unuer aei.tio.
-------
Federal Register / Vol. 44. No. 117 / Friday, June 15, 1979 / Proposed Rules
111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the n^ed for
integration with other f rograms, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
An economic impact assignment has
been prepared as required under Section
317 of the Act and is included in the
Background Information Document.
Dated- May 22, 1979
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
Subpart CC—Standards of
Performance for Glass Manufacturing
Plants
Sec.
00.290 Applicability and designation of
affected facility
60.291 Definitions.
00.292 Standards lor participate matter
60.293 Test methods and procedures.
Authority: Sections 111 and 301(a) of the
Clean Air Act, as amended [42 U.S.C. 7411,
7601(a)], and additional authority as noted
below.
§ 60.290 Applicability and designation of
affected facility.
The affected facility to which the
provisions of this subpart apply is each
glass melting furnace within a glass
manufacturing plant.
§ 60.291 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A.
(a) "Glass manufacturing plant"
means any plant which produces glass
or glass products.
(b] "Glass melting furnace" means a
unit comprising a refractory vessel in
which raw materials are charged,
melted at high temperature, refined, and
conditioned to produce molten glass.
The unit includes foundations,
superstructure and retaining walls, raw
material charger systems, heat
exchangers, melter cooling system,
exhaust system, refractory brick work,
fuel supply and electrical boosting
equipment, integral control systems and
instrumentation, and appendages for
conditioning and distributing molten
glass to forming apparatuses.
(c) "Day pot" means any glass melting
furnace designed to produce less than
1800 kilograms of glass per day.
(d) "All-electric melter" means a glass
melting furnace in which all the heat
required for melting is provided by
electric current from electrodes
submerged in the molten glass, although
some fossil fuel may be charged to the
furnace as raw material.
(e) "Glass" means flat glass, container
glass; pressed and blown glass; and
wool fiberglass.
(f) "Flat glass" means glass made of
soda-lime recipe and produced into
continuous flat sheets and other
products listed in Standard Industrial
Classification 3211 (SIC 3211).
(g) "Container glass" means glass
made of soda-lime recipe, clear or
colored, which is pressed and/or blown
into bottles, jars, ampoules, and other
products listed in SIC 3211.
(h) "Pressed and blown glass" means
glass which is pressed and/or blown,
including textile fiberglass,
noncontinuous process flat glass,
noncontainer glass, and other products
listed in SIC 3229. It is separated into:
(1) Glass of soda-lime recipe; and
(2) Glass of borosilicate, opal, lead
and other recipes.
(i) "Wool fiberglass" means fibrous
glass of random texture, including
fiberglass insulation, and other products
listed in SIC 3296.
[}) "Recipe" means formulation of raw
materials.
(k) "Glass production" means the
weight of glass pulled from a glass
melting furnace.
(1) "Rebricking" means cold
replacement of damaged or worn
refractory parts of the glass melting
furnace. Rebricking includes
replacement of the refractories
comprising the bottom, sidewalls, or
roof of the melting vefssel; replacement
of refractory work in the heat
exchanger; replacement of refractory
portions of the glass conditioning and
distribution system.
(m) "Soda-lime recipe" means raw
material formulation of the following
approximate proportions: 72 percent
silica; 15 percent soda; 10 percent lime
and magnesia; 2 percent alumina; and 1
percent miscellaneous materials.
{ 60.292 Standards for paniculate matter.
(a) On or after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator of a glass melting
furnace subject to the provisions of this
subpart shall cause to be discharged
into the atmosphere, except as provided
in paragraph (d) of this section:
(1) From any glass melting furnace,
fired with a gaseous fuel, particulate
matter at emission rates exceeding those
specified in Table CC-1.
(2) From any glass melting furnace.
fired with a liquid fuel, particulate .
matter at emission rates exceeding 1.15
times those specified in Table CC-1.
(3] From any glass melting furnace,
simultaneously fired with gaseous and
liquid fuel, particulate matter at
emission rates exceeding those specified
by the following equation:
STD = X[1.15 (Y) + (Z)]
where:
STD = Particulate matter emission limit
X = Emission rate specified in Table CC-1
Y = Decimal percent of liquid fuel heating
value to total [gaseous and liquid) fuel
"Tieating value
kilojoules
kilojoules
Z - (1 - Y)
(b) Conversion of a glass melting
furnace to use of liquid fuel shall not be
considered a modification for purposes
of 40 CFR 60.14.
(c) Rebricking and the cost of
rebricking shall not be considered
reconstruction for the purposes of 40
CFR 60.15.
(d) This subpart shall not apply to day
pots and all-electric melters.
Tabte CC-1—Emsaion dates
Gins category
00*
pmcutate/kg
of glass
produced
(1) Flat Glass o 15
12) Container Glass 10
(3) Pressed and Blown Glass
(a) Other than wda-Hme reopes (i.e.
borosKicate, opal, lead, and other recipes,
including textile fiberglass) K
(b) Soda-lime recipes 10
(4) Wool Ffcergtass .20
§ 60.293 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided under
§ 60.8(b), shall be used to determine
compliance with § 60.292 as follows:
(1) Method 5 shall be used to
determine the concentration of
particulate matter and the associated
moisture content.
(2) Method 1 shall be used for sample
and velocity traverses, and
(3) Method 2 shall be used to
determine velocity and volumetric flow
rate.
(4) Method 3 shall be used for gas
analysis.
(b) For Method 5, the sample probe
and filter holder shall be heated to 121'C
(250°F). The sampling time for each run
V-CC-15
-------
Federal Register / Vol. 44. No. 117 / Friday. }une 15, 1979 / Proposed Rules
shall be at least 60 minutes and the
volume shall be at least 4.25 dscm.
(c) The particulate emission rate, E.
shall be computed as follows:
E = V x C
where:
(1) E is the particulate emission rate
lg/hr),
(2) V is the average volumetric flow
rate (dscm/hr) as found from Method 2:
and
(3) C is the average concentration (g/
dscm) of particulate matter as found
from Method 5.
(d) the rate of glass production, P (kg/
hr) shall be determined by dividing the
weight of glass pulled in kilograms (kg)
from the affected facility during the
performance test by the number of hours
(hr) taken to perform the performance
test. The glass pulled in kilograms shall
be determined by direct measurement or
computed from materials balance by
good engineering practice.
(e) The furnace emission rate shall be
computed as follows:
R = E/P
where:
(1) R is the furnace emission rate (g/
kg);
(2) E is the particulate emission rate
(g/hr) from (c) above; and
(3) P is the rate of glass production
(kg/hr) from (d) above.
[Sec. 114 of Clean Air Act as amended (42
U.S.C. 7414).]
|FR Doc 7»-18602 Filed 6-14-79. 8:45 am|
Federal Register / Vol 44. No. 159 / Wednesday. August IS, 1979 / Proposed Rules
[40 CFR Part 60]
IFRL 1297-3]
Standards of Performance for New
Stationary Sources; Glass
Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for glass manufacturing
plants, which were proposed on June 15,
1979 (44 FR 34640), is being extended
from August 14,1979, to September 14,
1979.
DATES: Comments must be received on
or before September 14,1979.
ADDRESSES: Comments should be
submitted to Central Docket Section (A-
130), United States Environmental
Protection Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. OAQPS 79-2.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271,
SUPPLEMENTARY INFORMATION: On June
15,1979 (44 FR 34840), the
Environmental Protection Agency
proposed standards of performance for
the control of emissions from glass
manufacturing plants. The notice of
proposal requested public comments on
the standards by August 14,1979. Due to
delay in the shipping of the Background
Information Document sufficient copies
of the document have not been available
to all interested parties in time to allow
their meaningful review and comment
by August 14.1979. EPA has received a
request from the industry to extend the
comment period by 30 days through
September 14,1979. An extension of thia
length is justified since the shipping
delay has resulted in approximately a
three-week delay in processing requests
for the document.
Dated: August 8, 1979.
David G. Hawkins,
Assistant Administratarfor Aif. Noise, and
Radiation.
[FR Doc. 7B-ZS23J FiM (-14-7* MS un]
V-CC-16
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
STATIONARY INTERNAL
COMBUSTION ENGINES
SUBPART FF
-------
Federal Register / Vol. 44. No. 142 / Monday, July 23.1979 / Proposed Rules
[FRL 10M-5]
[40 CFR Part 60]
Stationary Internal Combustion
Engines; Standards of Performance
for New Stationary Sources
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: The proposed standards,
which would apply to facilities that
commence construction 30 months after
today's date, would limit emissions of
nitrogen oxides (NO,) from new,
modified, and reconstructed stationary
gas, diesel, and dual-fuel internal
combustion (1C) engines to 700 parts per
million (ppm), 600 ppm, 600 ppm,
respectively at 15 percent oxygen (02)
on a dry basis. A revision to Reference
Method 20 for determining the
concentration of nitrogen oxides and
oxygen in the exhaust gases from large
stationary 1C engines is also proposed.
The standards implement the Clean
Air Act and are based on the
Administrator's determination that
stationary 1C engines contribute
significantly to air pollution. The intent
is to require new, modified, and
reconstructed stationary 1C engines to
use the best demonstrated system of
continuous emission reduction,
considering costs, non-air quality health,
and environmental and energy impacts.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before September 21,
1979.
Public Hearing The public hearing
will be held on August 22,1979
beginning at 9:30 a.m. and ending at 4:30
p.m.
Request to Speak at Hearing. Persons
wishing to attend the hearing or present
oral testimony should contact EPA by
August 15, 1979.
ADDRESSES: Comments. Comments
should be submitted to Mr. Jack R.
Farmer. Chief, Standards Development
Branch (MD-13), Emission Standards
and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
Public Hearing. The public hearing
will be held at the Environmental
Research Center Auditorium, Room
B101, Research Triangle Park, N.C.
27711. Persons wishing to attend or
present oral testimony should notify
Mary Jane Clark, Emission Standards
and Engineering Divison (MD-13),
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5271.
Standards Support Document. The
support document for the proposed
standards may be obtained from the
EPA Library {MD-35), Research Triangle
Park, North CaroKna 27711, telephone
number (919) 541-2777. Please refer to
"Standards Support and Environmental
Impact Statement: Proposed Standards
of Performance for Stationary Internal
Combustion Engines," EPA-450/3-78-
125a.
Docket. The Docket, number OAQPS-
79-5, is available for public inspection
and copying at the EPA's Central Docket
Section, Room 2903 B, Waterside Mall,
Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards, which are
summarized in Table A, would apply to
all new, modified, and reconstructed
stationary internal combustion engines
as follows:
1. Diesel and dual-fuel engines greater
than 560 cubic inch displacement per
cylinder (CID/cyl).
2. Gas engines greater than 350 cubic
inch displacement per cylinder (CID/
cyl) or equal to or greater than eight
cylinders and greater than 240 cubic
inch displacement per cylinder (CID/
cyl).
3. Rotary engines greater than 1500
cubic inch displacement per rotor.
The proposed standards,.which would
go into effect 30 months after the date of
proposal (i.e., today's date), would limit
the concentration of NO, in the exhaust
gases from stationary gas, diesel and
dual-fuel 1C engines to 0.0700 percent by
volume (700 ppm), 0.600 percent by
volume (600 ppm), and 0.0600 percent by
volume 600 ppm, respectively, at 15
percent oxygen (O2) on a dry basis.
These emission limits are adjusted
upward linearly for 1C engines with
thermal efficiencies greater than 35
percent.
Table 1^.—Summary of Internal Combustion Engine New Source Performance Standard
internal combustion engine size and fuel type NO, emission hmrt' (rtxn) ApplicaMity dale
Gas Engines > 350 CID/cyl or ^ 8 cylinders and > 240 CID/
cyl or 1500 > CID/rotor
600
600
700
30 months from date of
proposal (> e , today's date)
30 months from date of
proposal (i e , today's date)
30 months from date of
proposal 0 e . today's date)
•NO, emission limit adjusted upward lor internal combustion engines with thermal efficiencies greater than 35 percent
Measured NO, emissions adtusted to standard atmospheric conditions of 1013 Kilopascals (29 92 inches mercury). 29 4 de-
grees Centigrade (85 degrees Farhenheit), and 17 grams moisture per kilogram dry aid (75 grains moisture per pound of dry air|
n determining compliance with the NO, emission limit
The proposed standards would be
referenced to standard atmospheric
conditions of 101.3 kilopascals (29.92
inches mercury), 29.4 degrees centigrade
(85 degrees Fahrenheit), and 17 grams
mositure per kilogram dry air (75 grains
moisture per pound of dry air).
Measured NO, emission levels,
therefore, would be adjusted to standard
atmospheric conditions by use of
ambient'correction factors included in
the standard. Manufacturers, owners, or
operators may also elect to develop
custom ambient condition correction
factors, in terms of ambient temperature,
and/or humidity, and/or ambient
pressure. All correction factors would
have to be substantiated with data and
approved for use by EPA before they
could be used for determining
compliance with the proposed
standards.
Emergency-standby 1C engines and all
one- and two-cylinder reciprocating gas
engines would be exempt from the NO,
emission standard.
Summary of Environmental and
Economic Impacts
The proposed standards would reduce
uncontrolled NO, emissions levels from
stationary 1C engines by about 40
percent. Based on industry growth
projections, a reduction in national NO,
emissions of about 145,000 megagrams
per year (160,000 tons per year) would
V-FF-2
-------
Federal Register / Vol. .44. No. 142 / Monday. July 23. 1979 / Proposed Rules
be reahzed in the fifth year after the
standards go into effect. Except for a
few local areas (e.g^ Los Angeles), there
are currently no state standards
limintmg NO, emissions from 1C
engines.
The proposed standards, however,
would increase uncontrolled CO and HC
emissions levels from stationary 1C
engines. Based on industry growth
projections, an increase in national CO
emissions of about 216,000 megagrams
(238,OOCftons) annually would be
realized in the fifth year after the
standards go into effect. Similarly, an
increase in national total HC emissions
of about 4600 megagrams (5000 tons)
annually would be realized in the fifth
year after the standards go into effect.
The large increase in CO emissions is
chie primarily to carbureted or naturally
aspirated gas engines. These engines
operate closer to stoichiometric
conditions under which a small change
in the air-to-fuel ratio results in a large
increase in CO emissions.
Though total national CO emissions
would increase significantly, ambient air
CO concentrations in the immediate
vicinity of these carbureted or naturally
aspirated gas engines would not be
adversely affected. As a result of the
proposed standards of performance, the
CO emissions from a naturally aspirated
engine would increase about 160
percent. NO, emissions from the same
engine, however, would decrease
concurrently about 40 percent.
Thus, there exists a trade-off between
NO,-emissions reduction and CO
emissions increase, particularly for
carbureted or naturally aspirated gas
engines. It should be noted though that
CO emissions are considered to be a
local problem since CO readily reacts to
form COj. Additionally, moat naturally
aspirated gas engines are operated in
remote locations where CO is not a
problem. NO, emissions, however, are
linked to the formation of photochemical
oxidants and are subject to long range
transport. Also, NO, emission control
techniques are essentially design
modifications, not add-on equipment.
therefore. NO, emissions reductions are
much harder to achieve than CO or HC
emissions reductions which may be
achieved more easily from other
sources.
One alternative is to propose a CO
emissions limit based on the use of
oxidizing catalysts. These catalysts can
provide CO and HC emissions
reductions on the order of 90 percent.
Initial capital costs are high, however,
averaging about $7500 for a typical 1000
horsepower naturally aspirated gas
engine, or about 15 percent of the
purchase price of this engine. EPA feels
these costs for control of CO emissions
are unreasonable.
The trade-off between NO, and CO
emissions appears reasonable.
However, EPA invites comments from
state and local air pollution control
agencies, environmental groups, the
industry, and other interested
individuals concerning all aspeds of the
attractiveness of these standards which
reduce NO, emissions at the expense of
CO emissions.
Industry has requested a waiver from
the national mobile source standards for
diesel engines used in light duty
vehicles. Based on their tests, industry
believes that the application of NO,
control techniques to these mobile diesel
engines causes increased particulate
(smoke) emissions. The plumes from
most well maintained large-bore
stationary 1C engines, however, are
virtually invisible when the engine is
operating at steady state. Though
excessive retard will cause diesel,and
dual fuel units to emit smoke, the NO,
control results used in the development
of this standard were only considered if
the plume did not exceed ten percent
visibility. Therefore, EPA feels the NO,
control technique* used to meet the
proposed standards for large stationary
1C engines will not cause excessive
visible and/or particulate emissions.
However, EPA invites comments on the
aspects of the proposed standards
which reduce NO, emissions at the
expense of visible and/or particulate
emissions.
There would be essentially no advene
water pollution, solid waste, or noise
impact resulting from the proposed
standards.
The energy impact of the proposed
standards would be small.
Turbocharged gas 1C engine fuel
consumption would be increased about
two percent. Dual-fuel 1C engine fuel
consumption would be increased about
three percent. Diesel 1C engine fuel
consumption would be increased about
seven percent. Naturally aspirated gas
1C engine fuel consumption would be
increased by about eight percent. The
fifth year energy impact of the proposed
standards would be equivalent to an
increase in fuel oil consumption of about
1.5 million barrels of oil per year (4,300
barrels of oil per day). This represents
an increase of only 0.03 percent of the
oil projected to be imported in the
United States five years after the
standards go into effect In addition,
these estimates are based on "worse-
case" assumptions which yield the
greatest energy impacts, and actual
impacts are expected to be lower.
The economic impacts of the proposed
standards are considered reasonable.
The proposed standards, would increase
1C engine manufacturers' total capital
investment requirements for
developmental testing of engine models
by about $5 million. These expenditures
would be made over a two year period
Analysis of financial reports and other
public financial information indicates
that the manufacturers' overhead
budgets are sufficient to support these
requirements without adverse impact on
their financial positions. The proposed
standards would not give rise to a
significant sales advantage for one or
two manufacturers over competing
manufacturers. The maximum intra-
industry sales losses, based on "worst-
case" assumptions, would be abou4 six
percent.
The proposed standards would
increase the total annualized costs to
users of a large stationary 1C engines of
all fuel types by about two to seven
percent. The capital cost or purchase
price of a large stationary 1C engine
would increase by about two percent.
The proposed standards would
increase the total annualized costs for
all engine users by about $32 million in
the fifth year after standards go into
effect. The total capital investment
requirements for all users would equal
about 9.6 million on a cumulative basis
over the first five years the standards
are in effect.
These impacts would result in price
increases for the end products or
services provided by the industrial and
commercial users of large stationary 1C
engines. The electric utility industry
would pass on a price increase after five
years of 0.02 percent. After five years,
delivered natural gas prices would
increase 0.04 percent. Even after a full
phase-in period of 30 years, during
which new controlled engines would
replace all existing uncontrolled
engines, the electric utility industry
would pass on a price increase of only
0.1 percent. Delivered natural gas prices
would increase only 0.3 percent.
Rationale—Selection of Source for
Control
Stationary 1C engines are sources of
NO,, hydrocarbons (HC), particulates,
sulfur dioxide (SO,), and carbon
monoxide (CO) emissions. NO,
emissions from 1C engines, however, are
of more concern than emissions of these
other pollutants for two reasons. First,
compared to total U.S. emissions for
each pollutant, NO, is the primary
pollutant emitted by stationary engines.
Second, EPA has assigned a high
priority to development of standards of
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performance limiting NO, emissions. A
study by Argonne National Laboratory,
"Priorities and Procedures for
Development of Standards of
Performance for New Stationary
Sources of Atmospheric Emissions"
(EPA-450/3-76-020), concluded that
national NO, emissions from stationary
sources would increase by more than 40
percent between 1975 and 1990 in the
absence of additional emission controls.
Applying best technology to all sources
would reduce this increase but would
not prevent it from occurring. This
unavoidable increase in NO, emissions
is attributable largely to the fact that
current NO, emission control techniques
are based on combustion redesign. In
addition, few NO, emission control
techniques can achieve large (i.e., in the
range of 90 percent) reductions in NO,
emissions. Consequently, EPA has
assigned a high priority to the
•development of standards of
performance for major NO, emission
sources wherever significant reductions
in NO, can be achieved. Studies have
shown that 1C engines are significant
contributors to total U.S. NO, emissions
from stationary sources. Internal
combustion engines account for 16.4
percent of all stationary source NO,
emissions, exceeded only by utility and
packaged boilers.
Studies have investigated the effect
that standards of performance would
have on nationwide emissions of
particulates, NO,, SO,, HC, and CO
from stationary sources. The "Priority
List for New Source Performance
Standards under the Clean Air Act
Amendments of 1977," which was
proposed in the August 31,1978, Federal
Register, ranked sources according to
the impact, in tons per year, that
standards promulgated in 1980 would
have on emissions in 1990. This ranking
placed spark ignition 1C engines second
and compression ignition 1C engines
third on a list of 32 stationary NO,
emission sources. Consequently,
stationary 1C engines have been
selected for development of standards of
performance.
Selection of Pollutants
Nitrogen oxides, hydrocarbons, and
carbon monoxide.—Stationary 1C
engines emit the following pollutants:
NO,, CO. HC, particulates, and SO,. The
primary pollutant emitted by stationary
1C engines is NO,, accounting for over
six percent (or 16 percent of all
stationary source*) of the total U.S.
inventory of NO, emissions.
Stationary 1C engines also emit
substantial quantities of CO and HC.
Numerous small (1-100 hp) spark
ignition engines, which are similar to
automotive engines, account for about
20 percent of the uncontrolled HC
emissions and about 80 percent of the
uncontrolled CO emissions. The large
annual production of these small spark
ignition engines (approximately 12.7
million), however, makes enforcement of
a new source performance standard for
this group difficult.
Large-bore engines, which account for
three-quarters of NO, emissions from
stationary 1C engines, contribute
relatively small amounts to nationwide
HC and CO emissions, especially if one
considers that 80 percent of the HC
emissions from large-bore 1C engines are
methane. An additional factor in
considering CO and HC control is that
inherent engine characteristics result in
a trade-off between NO, control and
control of CO and HC.
As mentioned before, in some cases,
particularly naturally aspirated gas
engines, the application of NO, emission
control techniques could cause
increases in CO and HC emissions. This
increase in CO and HC emissions is
strictly a function of the engine
operating position relative to
stoichiometric conditions, not the NO,
control technique. These engines
operate closer to stoichiometric
conditions under which a small change
in the air-to-fuel ratio results in a large
increase in CO emissions. Any increase
in CO and HC emissions, however,
represents an increase in unbumed fuel
and hence a loss in efficiency. Since 1C
engines manufacturers compete with
one another on the basis of engine
operating costs, which is primarily a
function of engine operating efficiency,
the marketplace will effectively ensure
that CO and HC emissions are as low as
possible following application of NO,
control techniques.
Though total national CO emissions
would increase significantly, ambient air
CO concentrations in the immediate
vicinity of these carbureted or naturally
aspirated gas engines would not be
adversely affected. As a result of the
proposed standards of performance, the
CO emissions from a natually aspirated
engine would increase about 160
percent. NO, emissions from the same
engine, however, would decrease
concurrently about 40 percent.
Thus, there exists a trade-off between
NO, emissions reduction and CO
emissions increase, particularly for
carbureted or naturally aspirated gas
engines. It should be noted though that
CO emissions are considered to be a
local problem as CO readily reacts to
form CO,. Additionally, most naturally
aspirated gas engines are operated in
remote locations where CO is not a
problem. NO, emissions, however, are
linked to the formation of photochemical
oxidants and are subject to long range
transport. NO, emissions reductions are
also much harder to achieve than CO or
HC emissions reductions which may be
achieved more easily from other
sources.
In addition, promulgation of CO
standard of performance could, in effect,
preclude significant NO, control. NO,
emissions are primarily a function of
combustion flame temperature.
Decreasing the air-to-fuel ratio of a gas
engine lowers the flame temperature
and consequently reduces NO,
formation. As will be discussed later,
this technique is the most effective
means of reducing NO, emissions from
gas engines. CO emissions, however, are
primarily a function of oxygen
availability. Decreasing the air-to-fuel
ratio reduces oxygen availability and
consquently increases CO emissions.
Hence naturally aspirated gas engines
show a pronounced rise in CO emissions
as the air-to-fuel mixture becomes richer
(i.e., decreasing air-to-fuel ratio). Thus,
placing a limit on CO emissions from
internal combustion engines could
effectively limit the decrease in the air-
to-fuel ratio which would be applied to
reduce NO, emissions from naturally
aspirated gas engines and,
consequently, could limit the amount of
NO, emissions reduction achievable.
One alternative is to propose a CO
emissions limit based on the use' of
oxidizing catalysts. These catalysts can
provide CO and HC emissions
reductions on the order of 90 percent.
Initial capital costs are high, however,
averaging about $7500 for a typical 1000
horsepower naturally aspirated gas
engine, or about 15 percent of the
purchase price of this engine. EPA feels
these costs for control of CO emissions
are unreasonable.
The trade-off between NO, and CO
emissions appears reasonable, and
consequently, only NO, emissions from
large stationary 1C engines were
selected for control by standards of
performance.
EPA, however, invites comments from
state and local air pollution control
agencies, environmental groups, the
industry, and interested individuals
concerning all aspects of the
attractiveness of these standards which
reduce NO, emissions at the expense of
CO emissions.
Paniculate.—Virtually no data are
available on particulate emission rates
from stationary 1C engines. It is
believed, however, that particulate
emissions from stationary 1C engines are
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very low because the plumes from most
of these engines are not visible.
Therefore, neither particulate emissions
nor visible emissions (plume opacity)
were selected for control by standards
of performance.
Sulfur oxides.—Sulfur oxides (SO,)
emissions from an 1C engine depend on
the sulfur content of the fuel and the fuel
consumption of the engine. Scrubbing of
1C engine exhausts to control SO,
emissions does not appear to be
reasonable from an economic viewpoint.
Therefore, the only viable means of
controlling SOX emissions would be
combustion of low sulfur fuels. 1C
engines, however, currently burn low-
sulfur fuels and will likely continue to
do so because of the lower operating
and maintenance costs associated with
combustion of these fuels. Therefore,
SO, emissions were not selected for
control by standards of performance.
Selection of Affected Facilities
A relatively small number of large-
bore 1C engines account for over 75
percent of all NOX emissions from
stationary engines. The remaining
smaller bore 1C engines, which make up
the majority of all engine sales, are,
from a NOX emission standpoint, a
considerably less significant segment of
the industry. These engines have
different emission characteristics due to
thpir size, design, and operating
parameters. The NO, reduction
technology developed for use on the
largp-bore 1C engines may not be
directly applicable to these smaller
engines Therefore, at this time, only
Ittrgp-bore engines have been selected
for control by standards of performance.
Diesel engines.—The primary high
usdge (Idrge emissions impact) domestic
application of large-bore diesel engines
during the past five years has been for
oil nnd gas exploration and production.
The market for prime (continuous)
ele< trie generation and other industrial
Hpphcations all but disappeared after
the 1973 oil embargo, but was quickly
replaced by sales of standby electric
units for building services, utilities, and
nuclear power stations. The rapid
growth in the oil and gas production
market occurred because diesel units
are being used on oil drilling rigs of
various sizes. Sales of engines to export
applications have also grown steadily
since 1972, and are now a major
segment of the entire sales market.
Medium-bore as well as large-bore
engines are sold for oil.and gas
exploration, standby service, and other
industrial applications. Applying
standards of performance to medium-
bore engines serving the same
applications as large-bore designs
would increase the number of affected
facilities from about 200 to about 2,000
units per year (based on 1976 sales
information) but consequently further
reduce national NO, emissions.
Medium-bore sales accounted for
significant NO, emissions in 1976
(approximately 12,500 megagrams). It is
estimated that approximately 25
percent, or about 500 of these units in
high usage applications, accounted for
most of the medium/bore NO,
emissions, since most of the remainder
of these units were sold as standby
generator sets. Though the potential
achievable NO, reduction is significant,
this alternative causes the standard to
apply to lower power engine models
with fewer numbers of cylinders
competing with other unregulated
engines in different stationary markets
Additionally, considering this large
number, and the remoteness and
mobility of petroleum applications, this
alternative would create serious
enforcement difficulties. Consequently.
a definition is required that
distinguishes large-bore engines
competing with medium-bore high
power engines used for baseload
electrical generation from large-bore
engines competing solely with other
large-bore engines.
One approach would be to define
diesel engines covered by standards of
performance as those exceeding 560
cubic inch displacement per cylinder
(ie., CID/cyl). 1C engines below this size
are generally used for different
applications than those above it.
Considering the sizes and displacements
offered by each diesel manufacturer and
the applications served by diesel
engines, this definition was selected as
a reasonable approach for separating
large-bore engines that compete with
medium-bore engines from large-bore
engines that compete solely with each
other.
Dual-fuel engines.—The concept of
dual-fuel operation was developed to
take advantage of both compression
ignition performance and inexpensive
natural gas. These engines have been
used almost exclusively for prime
electric power generation. Shortages of
natural gas and the 1973 oil embargo
have combined to significantly reduce
the sales of these engines in recent
years. The few large-bore units that
were sold (11 in 1976) were all greater
than 350 CID/cyl.
Although a greater-than-350-CID/cyl
limit would subject nearly all new dual-
fuel sources to standards of
performance, the criterion chosen to
define affected diesel engines (i.e..
greater than 560 CID/cyl) has also been
•elected for dual-fuel engines. The
primary reason is that supplies of
natural gas are likely to become even
more scarce; thus dual-fuel engines will
likely operate as diesel engines.
Cos engines.—The primary
application of large-bore gas engines
during the past five years has been for
oil and gas production. The primary uses
are to power gas compressors for
recovery, gathering, and distribution.
About 75 to 80 percent of all gas engine
horsepower sold during the past five
years was used for these applications.
During this time, sales to pipeline
transmission applications declined.
Pipeline applications combined with
standby power, electric generation, and
other services (industrial and sewage
pumping) accounted for the remaining 20
to 25 percent of horsepower sales. The
growth of oil and gas production
applications during this period
corresponds to the increasing efforts to
find new, or to recover marginal. gas
reserves and distribute them to the
existing pipeline transmission network
It is estimated that the 400,000
horsepower of large-bore gas engine
capacity sold for oil and gas production
applications in 1976 emitted 35,000
megagrams of NO, emissions, or nearly
three times more NO, than was emitted
by the 200,000 horsepower of large-bore
diesel engine capacity sold for the same
application in that year. Thus, large-bore
gas engines are primary contributors of
NO, emissions from new stationary 1C
engines, and standards of performance
should be directed particularly at these
sources.
If affected engines were defined as
those greater than 350 CID/cyl, then all
competing manufacturers of large-bore
gas engines except one would be
affected by the proposed standards of
performance. This one manufacturer
produces primarily medium-bore
engines. Therefore, a 350 CID/cyl limit
would give this one manufacturer an
unfair competitive advantage over other
large-bore engine manufacturers.
Consequently, this definition should be
lowered, or another definition adopted.
to include the manufacturer in question.
Either of the following two definitions
would subject this manufacturer's gas
engine to standards of performance:
• Greater than 240 CID/cyl
• Greater than 350 CID/cyl or greater
than or equal to 8-cylinder and greater
than 240 CID/cyl
Both measures would essentially
include only this manufacturer's gas
engines which compete with other
manufacturer's large-bore gas engines.
The second definition has a slight
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advantage over the first since it includes
only gas engines produced by all
manufacturers that have competitor
counterparts-of about the came power.
Therefore, this second definition of
affected gas'engines was selected.
Rotary engines.—Rotary or wankel
type engines >have only recently been
introduced as power sources in package
Stationary applications. These internal
combustion engines convert energy in
the fuel directly to rotary motion rather
than through reciprocating pistons and a
crankshaft. These engines consist of a
triangular rotor rotating eccentrically
inside an epitrochoidal housing.
Until recently the largest rotary engine
in production was 90 cubic inches per
rotor. Now, however, one manufacturer
is producing a rotary engine with a
displacement of 2,500 cubic inches per
rotor. This engine is being offered as a
one rotor model rated at 550 horsepower
and a two rotor unit rated at 1,100
horsepower.
The displacement of the rotary engine
is defined as the volume contained in
the chamber, bordered by one flank of
the rotor and the housing, at the instant
the inlet port closes. These engines are
presently sold as naturally aspirated
gaseous fueled units primarily for fuel
gathering compressors and power
generation on offshore platforms.
NO, emissions from these large rotary
engines are similar to NO, emissions
from naturally aspirated four stroke,
gaseous fuel reciprocating engines.
Further sales of these engines are
estimated to be 50,000 horsepower per
year over the next five years. Since
these large rotary engines contribute to
NO, emissions, standards of
performance for new stationary 1C
engines should include these sources.
Due to design differences, rotary
engines develop more power per cubic
inch displacement than reciprocating
engines. If the lower cutoff limit for
affected rotary engines were 350 CID/
rotor—in an attempt to equate
displacement per cylinder and also use
the same limit as for gaseous fueled
engines—then rotary engines of
approximately 100 horsepower would be
regulated by standards of performance.
Thus rotary engine manufacturers would
be at a competitive disadvantage with
unregulated reciprocating engine
manufacturers in this power range. To
ensure that the standards of
performance do not alter the competitive
position of the two types of engines, the
lower size limit for affected rotary
engines should correspond to an engine
whose power output is the same as the
smallest affected reciprocating unit.
Based on this criterion of equivalent
horsepower, it is estimated that rotary
engines greater'than 1,500 CID/rotor
would compete with reciprocating
engines greater than 360 CID/cyc.
Therefore, a greater than 1,500 CID/
rotor definition of affected rotary
engines -is selected to subject these
engines to standards of performance.
The definition applies to rotary engines
of all fuel types.
Exemptions.—One and two cylinder
reciprocating engines could be covered
by the above definitions. These engines,
however, account for less than 10
percent of all engine horsepower and
therefore are less significant NO,
emitters. Additionally, the engines
operate at a small fraction of their
power output and probably have lower
NO, emissions than the larger, high
rated engines. Therefore, all one and
two cylinder reciprocating engines were
exempted from standards of
performance.
Emergency standby engines also
require special consideration. These
engines operate less than 200 hours per
year under all but very unusual
circumstances. Consequently, they add
relatively little to regional or national
total NO, emissions. The largest
category of emergency standby units is
for nuclear power plants, where these
engines provide power for the pumps
used for cooling the reactors. These
engines must attain a set speed in ten
seconds and must assume full rated load
in 30 seconds. In some cases,
application of the demonstrated NO,
control technique limits the
responsiveness of these engines in
emergency situations. Therefore, all
emergency standby engines are
exempted from standards of
performance.
Selection of Best System of Emission
Reduction
Four emission control techniques, or
combinations of these techniques, have
been identified as demonstrated NO,
emission reduction systems for
stationary large-bore 1C engines. These
techniques are: (1) Retarded ignition or
fuel injection, (2) air-to-fuel ratio
changes, (3) manifold air cooling, and (4)
derating power output (at constant
speed). In general, all four techniques
are applied by changing an engine
operating adjustment.
Fuel injection retard is the most
effective NO, control technique for
diesel engines. Similarly, air-to-fuel ratio
change is the most effective NO, control
technique for gas engines. Both retard
and air-to-fuel ratio changes are
effective in reducing ItfQ, emissions
from dual-fuel engines.
Other NO, emission control
techniques exist but are not considered
feasible alternatives. Of these other
techniques, catalytic reduction of NO,
emissions through the use of systems
similar to automobile catalyst systems is
probably the first to come to mind. Most
large stationary 1C engines operate at
air-to-fuel ratios that are typically much
greater than stoichiometric, and
consequently the engine exhaust is
characterized by high oxygen (O,)
concentrations. Existing automobile
catalytic converters, however, operate
near stoichiometric conditions (i.e., low
exhaust O, concentrations). These
automobile catalysts are not effective in
reducing NO, in the presence of high Ot
concentrations.
Consequently, entirely different
catalyst systems would be needed to
reduce NO, emissions from large
stationary 1C engines. Although such
catalyst systems are currently under
development and have been
demonstrated for one very narrow
application (i.e., fuel-rich naturally
aspirated gas engines), they have not
been demonstrated for the broad range
of 1C engines manufactured, such as
turbocharged engines, fuel-lean gas
engines, or diesel engines. For these
engines the reduction of NO, by
ammonia injection over a precious metal
(e.g., platinum) catalyst appears
promising with NO, reductions of
approximately 90 percent having been
reported; however, the cost of such a
system is high.
For a typical 1000 horsepower engine
approximately two cubic feet of
honeycomb catalyst (platinum based)
would be required to ensure proper
operation of the system. The cost of the
catalyst was estimated at Sl.500/cubic
foot (in 1973). Assuming that the engine
costs $150/hp and that the cost of the
catalyst accounts for about one-half the
cost of the whole system (container,
substrate, and catalyst), the capital
investment for this control system
represents approximately four percent
of the engine purchase price.
The amount of ammonia required for
an ammonia/catalyst NO, reduction
system will depend on the NO, emission
rate (g/hp-hr). Based on uncontrolled
NO, emission rates of 9 to 22 g/hp-hr,
and the cost of $150/ton for the
ammonia, the cost impact of injecting
ammonia is approximately 5 to 15
percent of the total annual operating
costs ($/hp-hr) for natural gas engines.
When this operating cost is combined
with the capital cost of the catalytic
system discussed above, the total cost
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increase is about 25 percent. Therefore,
in continuous service applications this
system is expensive compared to control
techniques such as retard or air-to-fuel
changes.
It is also important to note that the
consumption of ammonia can be
expressed as a quantity of fuel since
natural gas is generally used to produce
ammonia. Assuming a conservative NO,
emission rate of 20 g/hp-hr, and engine
heat rate of 7500 Btu/hp-hr, a heating
value of 21,800 Btu/lb for natural gas,
and a requirement for approximately 900
Ibs of gas per ton of ammonia produced,
then the ammonia necessary for the
catalytic reduction has the same effect
on the supply of natural gas as a two
percent increase in fuel consumption.
Additional fuel is required to operate
the plant which produces the ammonia.
Catalytic reduction, therefore, is
currently not a demonstrated NO,
emission control technique which could
be used by all 1C engines. Consequently,
although catalytic reduction of NO,
emissions could be used in a few
isolated cases to comply with standards
of performance, it could not be used as
the basis for developing standards of
performance which are applicable to all
1C engines.
The data and information presented in
the Standards Support and
Environmental Impact Statement clearly
indicate that the four demonstrated
control techniques mentioned above will
reduce NO, emissions from 1C engines.
Due to inherent differences in the
uncontrolled emission characteristics of
various engines, it is difficult to draw
conclusions from this data and
information concerning the ability of
these emission control techniques to
reduce NO, emissions from all 1C
engines to a specific level. In general,
engines with high uncontrolled NO,
emissions levels have relatively high
controlled NO, emissions levels and
engines with low uncontrolled NO,
emissions levels have relatively low
contolled NO, emissions levels. To
eliminate these inherent differences in
NO, emission characteristics among
various engines, the data were analyzed
in terms of the degree of reduction in
NO, emissions as a function of the
degree of application of each emission
control technique.
Ignition retard in excess of eight
degrees in diesel engines frequently
leads to unacceptably high exhaust
temperatures, resulting in exhaust value
and/or turbocharger turbine damage.
Similarly, changes in the air-to-fuel ratio
in excess of five percent in gas engines
frequently lead to excessive misfiring or
detonation which could lead to a serious
explosion in the exhaust manifold. Eight
degrees of ignition retard in diesel
engines and five percent change in air-
to-fuel ratios in gas engines yield about
a 40 percent reduction in NO, emissions.
Consequently, in light of these
limitations to the application of these
emission control techniques, it is
apparent that a 40 percent reduction in
NO, emissions is the most stringent
regulatory option which could be
selected as the basis for standards of
performance. An alternative of 20
percent NO, emission reduction was
also considered a viable regulatory
option which could serve as the basis
for standards of performance.
Environmental impacts.—Standards
of performance based on alternative I
(20 percent reduction) would reduce
national NO, emissions by 72,500
megagrams annually in the fifth year
after the standards went into effect. In
contrast, standards of performance
based on alternative II (40 percent
reduction) would reduce national NO,
emissions by about 145,000 megagrams
annually in the fifth year after the
standards went into effect. Thus,
standards of performance based on
alternative II would have a much greater
impact on national NO, emissions than
standards based on alternative I.
Standards of performance based on
either alternative would, with the
exception of naturally aspirated gas
engines, result in a small increase in
carbon monoxide (CO) and hydrocarbon
emissions (HC) from most engines. A
typical diesel engine with a sales-
weighted average uncontrolled CO
emission level of approximately 2.9 g/
hp-hr would experience an increase in
CO emissions of about 0.75 g?hp-hr to
comply with standards of performance
based on alternative I, and an increase
of about 1.5 g/hp-hr to comply with
standards of performance based on
alternative II. Total hydrocarbon
emissions would increase a sales-
weighted average uncontrolled emission
level of 0.3 g/hp-hr by about 0.06 g/hp-hr
to comply with standards based on
alternative I, and would increase by
about 0.1 g/hp-hr to comply with
standards of performance based on
alternative II.
Similarly, a typical dual-fuel engine
with a sales-weighted average
uncontrolled CO emission level of
approximately 2.7 g/hp-hr would
experience an increase in CO emissions
of about 1.2. g/hp-hr and about 2.7 g/hp-
hr to comply with standards of
performance based on alternatives I and
II, respectively. Total HC emissions,
however, would increase by about 0.3 g/
hp-hr from a sales-weighted average
uncontrolled level of approximately 2.8
g/hp-hr to comply with standards of
performance based on alternative I. To
comply with standards of performance
based on alternative II total
hydrocarbon emissions would decrease
by 0.6 g/hp-hr.
A typical turbocharged or blower
scavenged gas engine with a sales-
weighted average uncontolled CO
emission level of approximately 7.7 g/
hp-hr would experience an increase in
CO emissions of about 1.9 g/hp-hr to
comply with standards of performance
based on alternative I and about 3.8 g/
hp-hr to comply with standards of
performance based on alternative II.
Total hydrocarbon emissions would
increase a sales-weighted average
uncontrolled level of approximately 1.9
g/hp-hr by about 0.2 g/hp-hr to comply
with standards of performance based on
alternative I. To comply with standards
of performance based on alternative II
total hydrocarbon emissions would
increase by about 0.4 g/hp-hr.
A typical naturally aspirated gas
engine with a sales-weighted average
uncontrolled CO emission level of
approximately 7.7 g/hp-hr would
experience an increase in CO emissions
of about 3.9 g/hp-hr to comply with
standards of performance based on
alternative I and about 17 g/hp-hr to
comply with standards of perfomance
based on alternative II. Total
hydrocarbon emissions would increase
a sales-weighted average uncontrolled
level of approximately 1.8 g/hp-hr by
about 0.04 g/hp-hr to comply with
standards of performance based on
alternative I. To comply with standards
of performance based on alternative II
total hydrocarbon emissions would
increase by about 0.08 g/hp-hr
As noted earlier, the increase in
ambient air CO levels resulting from
compliance with NO, standards of
performance based on either alternative
would be insignificant compared to the
NAAQS of 10 mg/m3 for CO.
Additionally, CO emissions are a local
problem as CO readily reacts to form
CO* Additionally, most naturally
aspirated engines are operated in
remote or sparcely populated areas, CO
emissions will not present a problem.
Currently, national stationary CO
emissions are approximately 33 million
megagrams per year. Standards of
performance based on alternative I
would increase these emissions by
approximately 63,000 megagrams
annually in the fifth year after the
standards went into effect. In contrast,
standards of performance based on
alternative II would increase national
CO emissions by about 216,000
V-FF-7
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Federal Register / Vol. 34. Nc. 342 // iManday. July 23, 1979 / Proposed Rules
megqgrams annually,in the fifth year
after doe standards went into effect.
.'Standards of'performance based on
alternative 1 would 'increase national
total HC emissions by about .2,300
megagrams annually .in,the fifth year
after the standards went into effect
compared to an increase of f
approximately 216 megagrams .annually
associated .with alternative II.
Stationary 1C engines are sources .of
NO,, HC. and CO emissions, with .bath
NO. and HC contributing to oxidant
formation. With regard to regulation of
emissions from 1C engines, NO,
emissions are of more concern .than
.emissions of HC for two .reasons. First.
NO, .is emitted in greater quantities from
stationary 1C engines ihan HC. Second,
as mentioned earlier, aihigh priority JMS
been assigned 'to development of
standards of ;perfomance limiting "NO,
emissions. A study by-Axgonne National
Laboratory, "Priorities and Procedures
for development of Standards of
Perfomancelor New Stationary Sources
of Atmospheric Emissions," concluded
that national NO, emissions from
Stationary sources would increase by
more than 40 percent between IflTSand
1990 in the absence of additional
emission controls. The sJight increase in
HC emissions from 1C engines
associated with control of NO, can .be
offset in most cases from other sources
more easily than NQ, emissions can be
reduced from other sources. Therefore,
the adverse environmental impact of
increased HC emissions because of the
reduction in NO, emissions is
considered small.
There would be essentially no water
pollution, solid waste, or noise impact of
standards of performance based on
either .alternative I or alternative II.
Thus, as reflected in Table 1. the
environmental impacts of standards of
performance Abased on either alternative
are small and reasonable
V-FF-8
-------
Federal Register / Vol. 44. No. 142 / Monday. July 23.1979 / Proposed Rules
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V-FF-9
-------
Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
Energy impacts. The potential energy
impact of standards of performance
based on either alternative is small.
Standards of performance based on
alternative.I would increase the fuel
consumption of a typical blower-
scavenged or turbocharged gas engine
by approximately one percent, whereas
standards of performance based on
alternative II would increase the fuel
consumption by approximately two
percent.
Standards of performance based on
alternative I would increase the fuel
consumption of a typical dual-fuel
engine by about one percent. Standards
of performance based on alternative II,
however, would increase the fuel
consumption by three percent.
Standards of performance based on
alternative I would increase the fuel
consumption of a typical naturally
aspirated gas engine by approximately
six percent. Standards of performance
based on alternative II, however, would
increase the fuel consumption by
approximately eight percent.
Standards of performance based on
alternative I would increase the fuel
consumption of a typical diesel engine
by approximately three percent.
Standards of performance based on
alternative II, however, would increase
the fuel consumption by approximately
seven percent.
The potential energy impact in the
fifth year after the standards go into
effect, based on alternative I, would be
equivalent to an increase in fuel
consumption of approximately 1.03
million barrels of oil per year compared
to the uncontrolled fuel consumption of
1C engines affected by the standards of
31 million barrels per year. The potential
energy impact in the fifth year after the
standard goes into effect, based on
alternative II, would be equivalent to
approximately 1.5 million barrels of oil
per year.
It should be noled that the largest
increase represents only 0.02 percent of
the 1977 domestic consumption of crude
oil and natural gas. The largest increase
also represents only 0.03 percent of the
projected total oil imported to the U.S.
five years after the standards go into
effect.
Thus, the energy impacts of standard
of performance based on either
alternative are small and reasonable.
Economic impact of alternatives.
Manufacturers of stationary 1C engines
would incur additional costs due to-
standards of performance. These costs,
however, would be small. It is estimated
that the total cost to the manufacturers
for each engine model family, including
development, durability tests, and
retooling, would be approximately: (1)
$125,000 for retard and air-to-fuel
change; (2) $150,000 for manifold air
temperature reduction; and (3) $25,000
for derate. For each manufacturer
therefor, total costs would vary
depending on-(l) the number of engine
model families produced; (2) their
degree of advancement in emission
testing; (3) the uncontrolled emission
levels of their engines; (4) the
development and durability testing
required to produce engines that can
meet proposed standards of
performance; and (5) the emission
control technique selected for NO,
emission reduction.
The manufacturer's total capital
investment requirements for
developmental testing of engine models
is estimated to be about $4.5 million to
comply with standards of performance
based on alternative I and about $5
million to comply with standards of
performance based on alternative II.
These expenditures would be made over
a two year period. Analyses of the
financial statements and other public
financial information of engine
manufacturers or their parent companies
indicate that the manufacturer's
overhead budgets are sufficient to
support the development of these
controls without adverse impact on their
financial position.
Manufacturers would not experience
significant differential cost impacts
among competing engine model families.
Consequently, no significant sales
advantages or disadvantages would
develop among competing
manufacturers as a result of standards
of performance based on either
alternative. Based on "worst-case"
assumptions, the maximum intra-
industry sales losses would be about six
percent as a result of standards of
performance based on either alternative.
Thus, the intra-industry impacts would
be moderate and not cause any major
dislocations within the industry.
The total annualized cost penalities
imposed on 1C engines by standards of
performace would also have very little
impact with regard to increasing sales of
gas turbines. Standards of performance
based on alternative I would result in no
loss of sales to gas turbines whereas
standards of performance based on
alternative II could result in the possible
loss of sales for one diesel
manufacturer.
It should be noted that this conslusion
is based on limited data. It is quite
likely, however, that this manufacturer's
line of diesel engines, through minor
combustion modifications, could reduce
its NO, emissions as discussed in the
SSEIS to levels comparable to those of
other manufacturers. Further, due to
technical limitations, economic
considerations, and customer
preference, it is unlikely that 1C engine
users would switch to gas turbines.
Thus, the impact on sales would be
minimal.
Therefore, the economic impacts on
the manufacturers of standards of
performance based on either alternative
are considered small and reasonable.
The application of NO, controls will
also increase costs to the engine user.
The magnitude of this increase will
depend upon the amount and type of
emission control applied. Fuel penalties
are the major factor affecting this
increase.
The following four end uses represent
the major applications of diesel, dual-
fuel, and natural gas engines: (1) Diesel
engine, electrical generation; (2) dual-
fuel engine, electrical generation; (3) gas
engine, oil and gas transmission and (4)
gas engine, oil and gas production.
The manufacturers' capital budget
requirements to develop and test engine
NO, control techniques would be
regarded as an added expense and most
likely passed on to the engine users in
the form of higher prices. Therefore,
users of 1C engines would have to
expend additional capital to purchase
more expensive engines. This capital
cost penalty, however, is small. A two
percent increase in engine price would
be expected on the average as the result
of standards of performance based on
either alternative. Typical initial costs
for uncontrolled diesel and dual-fuel,
electrical generation engines, and
natural gas oil and gas transmission
engines are about $150/hp. Initial costs
for gas, gas production engines are
about $50/hp.
The total additional capital cost for all
users would equal about $9.6 million on
a cumulative basis over the first five
years to comply with standards of
performance based on either alternative.
As mentioned earlier, fuel penalties
are the major factor affecting the total
annualized cost of high usage engines.
The total annualized cost of a typical
uncontrolled diesel, electrical generation
engine is about 2.5C/hp-hr. As a result of
standards of performance based on
alternative I this total annualized cost
would increase by about 0.04
-------
Federal Register / Vol. 44, No. 142 / Monday. July 23, 1979 / Proposed Rules
base on alternative II this total
annualized cost would increase by
about 0.07
-------
Federal Register / Vol. 44. No. 142 / Monday. July 23,1979 / Proposed Rules
TA8LE II
ECONOMIC IMPACTS OF ALTERNATIVES
lapact
Uncontrolled
level of Cost
Alternative I
Alternative II
I»oact on Manufacturer
Capital budget requirements
Intra-industry competition
Competition froa gas turbines
Inpact on End-Use Applications
Total annualized costa
D'esel fuel, electrical
generation
Dual-fuel, electrical gen-
eration
Natural gas fuel, oil and
gas transaission
Natural gas fuel, oil and
gas production
Totals of all new engines
after 5 years
Capital Cast Penalty*
Diesel fuel, electrical
generation or dual fuel,
electrical generation or
natural gas fuel, oil and
gas transmission
Natural gas fuel, oil and
gas production
Totals etc.
laoact on "roquet Pr'ees and
users
Electricity prices
prices
2.5C/hp-hr
2.8C/hp-hr
2.2t/hp-hr
2.2?/hp-hr
$£80 nf11 ion
S150/hp
S SO/hp
$450 Billion
$4.5 Billion over two years;
•bit to generate Internally
froa profits.
Maximum sales loss unlikely to
exceed 62 of internal comous-
tion engine sales for any fin.
No losses.
Base increased by 0.04t/hp-hr
Increased by 0.07£/hp-nr
Increased by 0.02t/hp-hr
Increased by 0.144/hp-hr
Increased by S2S pillion
Increased by $3.00/hp
Increased by Sl.OO/hp
$9 S million on a emulative
basis over first 5 years after
jtanoarfls go into effect.
U.S. electric bill uo 0.025
after 5 years. U.S. electric
bill up 0.IS after full phasa-
in.
Delivered natural gas prices up
0.025 after 5 years. Delivered
natural gas prices up 0.15
after full phasetn.
Assumed typical 2000 horsepower engine operating 8000 hours per year in all cases
Full pnase-in implies replacement of a'l existing engines
S5 Billion over two years; able
to generate internally froa
profits.
6S Baximua loss for any fim
Possible sales loss for one
diesel Banufacturer.
Increased by 0. HC/hp-hr
Increased by O.C9
-------
Federal Register / Vol. 44. No. 142 / Monday, July 23. 1979 / Proposed Rules
Based on the assessment of the
impacts of each alternative, and since
ahernative I] achieves a greater degree
of NO, reduction, it is selected as the
best technological system of continuous
emission reduction of NO, from
stationary large-bore 1C engines,
considering the cost of achieving such
emission reduction, any nonair quality
health and environmental impact, and
energy requirements.
Selection of Format for the Proposed
Standards
A number of different formats could
be used to limit NO, emissions from
large stationary 1C engines. Standards
could be developed to limit emissions in
terms of: (1) Percent reduction; (2) mass
emissions per unit of energy (power]
output; or (3) concentration of emissions
in the exhaust gases discharged to the
atmosphere.
Analysis of the effectiveness of the
various NO, emission control techniques
clearly shows that the ability to achieve
a percent reduction in NO, emissions is
what has been demonstrated. However,
a percent reduction format is highly
impractical for two reasons. First, a
reference uncontrolled NO, emission
level would have to be established for
each manufacture's engine, a difficult
task since some manufacturers produce
as many as 25 models which are sold
with several ratings. Second, a reference
uncontrolled NO, emission level would
have to be established for any new
engines developed after promulgation of
the standard. This would be quite simple
for engines that employed NO, control
techniques such as ignition retard or air-
to-fuel ratio change to comply with
standards of performance. Emissions
could be measured without the use of
these techniques. For engines designed
to comply with the standards through
the use of combustion chamber
modifications, however, this would not
be possible Thus, new engines would
receive no credit for the NO, emission
reduction achieved by combustion
chamber redesign and this would
effectively preclude the use of this
approach to comply with the standards.
A mass-per-unit-of-energy-output
format, typically referred to as brake-
specific emissions (g/hp-hr), relates the
total mass of NO, emissions to the
engine's productivity. Although brake-
specific mass standards (g/hp-hr)
appear meaningful becasue they relate
directly to the quantity of emissions
discharged into the atmosphere, there
are disadvantages in that enforcement
of mass standards would be costly and
complicated in practice. Exhaust flow
and power output would have to be
determined in addition to NO,
concentration. Power output can be
determined from an engine
dynamometer in the laboratory, but
dynamometers cannot be u»ed in the
field. Power output could be determined
by; (1) Inferring the power from engine
operating parameters (fuel flow, rpm,
manifold pressure, etc.); or (2) inferring
engine power from the output of the
generator or compressor attached to the
engine. In practice, however, these
approaches are time consuming and are
less accurate than dynamometer
measurements.
Another possible format would be to
limit the concentration of NO, emissions
in the exhaust gases discharged to the
atmosphere. Concentrations would be
specified in terms of parts-per-million
volume (ppm) of NO». The major
advantage of this format is its simplicity
of enforcement. As compared to the
formats discussed previously, only a
minimum of data and calculations are
required, which decreases testing costs
and minimizes errors in determining
compliance with an emission standard
since measurements are direct.
The primary disadvantages associated
with concentration standards are: (1) A
standard could be circumvented by
dilution of exhaust gases discharged
into the atmosphere, which lowers the
concentration of pollutant emissions but
does not reduce the total pollutant mass
emitted; and (2) a concentration :
standard could penalize high efficiency
engines. Both these problems, however,
can be overcome through the use of
appropriate "correction" factors.
Since the percent reduction format is
impractical, and the problems
associated with the enforcement of mass
standards (mass-per-unit energy output)
appear to outweigh the benefits, the
concentration format was selected for
standards of performance for large
stationary 1C engines.
As mentioned above, because a
concentration standard can be
circumvented by dilution of the exhaust
gases, measured concentrations must be
expressed relative to some fixed dilution
level. For combustion processes, this
can be accomplished by correcting
measured concentrations to a reference
concentration of O2. The Oj
concentration in the exhaust gases is
related to the excess (or dilution) air.
Typical Oj concentrations in large-bore
1C engines can range from 8 to 16
percent but are normally about 15
percent. Thus, referencing the standard
to a typical level of 15 percent O2 would
prevent circumvention by dilution.
As also mentioned above, selection of
a concentration format could penalize
high efficiency 1C engines. These highly
efficient engines generally operate at
higher temperature and pressures and,
as a result, discharge gases with higher
NO, concentrations than less efficient
engines, although the brake-specific
mass emissions from both engines could
be the same. Thus, a concentration
standard based on low efficiency
engines could effectively require more
stringent controls for high efficiency
engines. Conversely, a concentration
standard based on high efficiency
engines could allow such high NOX
concentrations that less efficient engines
would require no controls.
Consequently, selecting a concentration
format for standards of performance
requires an efficiency adjustment factor
to permit higher NO, emissions from
more efficient engines.
The incentive for manufacturers to
increase engine efficiency is to lower
engine fuel consumption. Therefore, the
objective of an efficiency adjustment
factor should be to give an emissions
credit for the lower fuel consumption ol
more efficient 1C engines. Since the fuel
consumption of 1C engines varies
linearly with efficiency, a linear
adjustment factor is selected to permit
increased NO, emissions from highly
efficient 1C engines.
The efficiency adjustment factor
needs to be referenced to a baseline
efficiency. Most large existing stationary
1C engines fall in the range of 30 to 40
percent efficiency. Therefore, 35 percent
is selected as the baseline efficiency
The efficiency adjustment factor
included in the proposed standards
permits a linear increase in NO,
emissions for engine efficiencies above
35 percent. This adjustment would not
be used to adjust the emission limit
downward for 1C engines with
efficiencies of less than 35 percent. This
efficiency adjustment factor also applies
only to the 1C engine itself and not the
entire system of which the engine may
be a part. Since Section 111 of the Clean
Air Act requires the use of the besl
system of emission reduction in all
cases, this precludes the application of
the efficiency adjustment factor to an
entire system. For example, 1C engines
with waste heat recovery may have a
higher overall efficiency than the 1C
engine alone. Thus, the application of
the efficiency adjustment factor to the
entire system would permit greater NO,
emissions because of the system's
higher overall efficiency, and would not
necessarily require the use of the best
demonstrated system emission
reduction on the 1C engine.
V-FF-13
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Federal Register / Vol. 44, No. 142 / Monday. July 23. 1979 / Proposed Rules
Selection of Numerical Emission Limits
Overall approach.—As mentioned
earlier it is difficult to select a specific
NO, emission limit which all 1C engines
could meet primarily through the use of
ignition retard or air-to-fuel ratio
change. Because of inherent differences
among various 1C engines with regard to
uncontrolled NO, emission levels, there
exists a rather large variation within the
data and information included in the
Standards Support and Environmental
Impact Statement concerning controlled
NO, emission levels. Generally
speaking, engines with relatively low
uncontrolled NO, emissions levels
achieved low controlled NO, emissions
levels and engines with high
uncontrolled NO, emissions levels
achieved relatively high controlled NO,
emissions levels. Consequently, the
following alternatives were considered
for selecting the numerical
concentration emission limits based on
a 40 percent reduction in NO, emissions:
1. Apply the 40 percent reduction to
the highest observed uncontrolled NO,
emission level.
2. Apply the 40 percent reduction to a
sales-weighted average uncontrolled
NO, emission level.
3 Apply the 40 percent reduction to
this sales-weighted average
uncontrolled NO, emission level plus
one standard deviation.
The highest observed uncontrolled
NO, emission levels for gas, dual-fuel
and diesel engines are as follows: (1)
Gas. 29 g/hp-hr |2| dual-fuel, 15 g/hp-hr,
and 131 diesel. 19 g/hp-hr.
Sales-weighted uncontrolled NO,
emission levels were determined by
applying a sales weighting to each
manufacturer s average uncontrolled
NO, emissions for engines of each fuel
type The sales weighting, based on
horsepower sold gives more weight to
those engine models which have the
highest sales The sales-weighted
average uncontrolled NO, emission
level for each engine fuel type are as
follow 111 Gas 15 g/hp-hr. (2) dual-fuel,
8 g/hp-hr and 131 diesel. 11 g/hp-hr.
The third alternative incorporates a
"margin for engine variability" by
adding one standard deviation to the
sales-weighted average uncontrolled
NO, emission level and then applying
the 40 percent reduction. Standard
deviations were calculated from the
uncontrolled NO, emission data
included in the Standards Support and
Environmental Impact Statement,
assuming the data had normal
distribution. A subsequent statistical
evaluation of the data indicated that this
assumption was valid: The standard
deviations -for each engine fuel type are
as follows: (1) Gas. 4 g/hp-hr. (2) dual-
fuel, 3.2 g/hp-hr. and (3) diesel, 3.7 g/hp-
hr.
The standard deviation of the
uncontrolled NO, emission data base is
relatively large compared to the sales-
weighted average uncontrolled NO,
emission level for each engine type. This
indicates that the distribution of
uncontrolled NO, emissions levels is
quite broad. In addition, the standard
deviation is of the same magnitude as
the 40 percent reduction in NO,
emissions that can be achieved. Thus.
regardless of which atlernative
approach is followed to select the
numerical NO, concentration emission
limit, a significant portion of the 1C
engine population may have to achieve
more or less than a 40 percent reduction
in NO, emissions to comply with the
standards.
It is important to note that the 40
percent reduction in NO, emissions is
based on the application of a single
control technique, such as ignition
retard, or air-to-fuel ratio change. Other
emission control techniques, however,
such as manifold air cooling and engine
derate, exist, although they are generally
not as effective in reducing NO,
emissions. Since emission control
techniques are additive to some extent.
it is possible in a number of cases to
reduce NO, emissions by greater than 40
percent.
The following factors were examined
for each engine type to choose the
alternative for selecting the numerical
NO, concentration emission limit: (1)
The percentage of engines that would
have to reduce NO, emissions by 40
percent or less to meet the standards; (2)
the percentage of engines that would be
required to do nothing to meet the
standards; and (3) the percentage of
engines that would be required to
reduce NO, emissions by more than 40
percent to meet the standards. The
normal distribution curve presented in
Figure I illustrates the trade-offs among
the three alternatives for selecting the
numerical NO, concentration emission
limit.
The first alternative is to apply the 40
percent reduction to the highest
uncontrolled NO, emission level within
a fuel category. For example, 29 g/hp-hr
is the highest uncontrolled NO, emission
level for gas engines. The application of
a 40 percent reduction would lead to an
emission level of about 17 g/hp-hr. As
illustrated in Figure I, if this level were
selected as a standard of performance,
99 percent of production gas engines
could easily meet the emission limit by
reducing emissions by 40 percent or less.
However. 69 percent of production
engines would not have to reduce NO,
emissions at all. Only one percent of
production engines would have to
reduce NO, emissions by more than 40
percent.
V-FF-14
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Federal Register / Vol. 44. No. 142 / Monday, July 23,1979 / Proposed Rules
ALTERNATIVE I
ALTERNATIVE II
7%
STD
i
»~i
ALTERNATIVE III
<-.
-^
18%
STD
1
84%'
^-
50%
.16%.
FIGURE 1. Statistical effects of alternative emission limits on gas engines.
V-FF-15
-------
Federal Register / Vol. 44. No. 142 / Monday. July 23, 1979 / Proposed Rules
The second alternative is.to apply 40
percent reduction to the sales-weighted
average uncontrolled NO, emission
level. For example, the sales-weighted
avergage uncontrolled NO, level for gas
engines is 15 g/hp-hr. The application of
a 40 percent reduction would lead to a
NO. emission level of 9 g/hp-hr. As
illustrated in Figure I, if this level were
selected as a standard of performance,
SO percent of production gas engines
could meet the standard with 40 percent
or less reduction in NO, emissions.
However, 50 percent of production gas
engines would be required to reduce
NO, emissions by greater than 40
percent. Only seven percent of
production gas engines would not have
to reduce NO. emissions at all.
The third alternative is to base the
standards on a 40 percent reduction in
NO, emissions from the sales-weighted
average uncontrolled NO, emission
level plus one standard deviation. For
example, the sales-weighted average
uncontrolled NO, emission level for gas
production gas engines is 15 g/hp-hr and
the standard deviation of the production
gas engine data base is 4 g/hp-hr. Thus,
the application of a 40 percent reduction
to the sum of these two values would
lead to an emission level of 11 g/hp-hr.
As illustrated in Figure I, if this level
were selected as a standard of
performance, 84 percent of the
production gas engines could easily
meet the emission limit by reducing
emissions by 40 percent or less.
However, IB percent of the production
gas engines would not have to reduce
NO, emission at all. Only'16 percent of
the production gas engines would have
to reduce NO, emissions by more than
40 percent.
This same analysis applied to dual-
fuel and diesel engines leads to the
results summarized in Table III. If
standards of performance were based
on Alternative I, essentially all engines
could achieve the emission limit by
reducing NO, emissions 40 percent or
less. A significant reduction in NO,
emissions would not be achieved,
however, since 50 to 70 percent of the 1C
engines would not have to reduce NO,
emissions at all. If the standards of
performance were based on Alternatve
II. about 50 percent of the 1C engines (in
all categories) would have to reduce
NO, emissions by greater than 40
percent. Less than 10 percent would not
have to reduce NO, emissions at all.
Thus this alternative would achieve a
significant reduction in NO, emissions
from new sources. If standards of
performance were based on Alternative
III. the results would be similar to those
achieved with Alternative I. About 85
percent of engines could easily meet the
standards by reducing NO, emissions by
less than 40 percent. About 20 to 30
percent of 1C engines would not have to
reduce NO. emissions at all, and about
15 percent of 1C engines would have to
reduce NO. emissions by more than 40
percent.
In light of the high priority which has
been given to standards directed toward
reducing NO, emissions and the
significance of 1C engines in terms of
their contribution to NO, emissions from
stationary sources, the second
alternative was chosen for selecting the
NO, emission concentration limit. This
approach will achieve the greatest
reduction in NO. emissions from new 1C
engines.
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Federal Register / Vol. 44. No. 142 / Monday. July 23,1979 / Proposed Rules
TABLE III
SUMMARY Of STATISTICAL ANALYSES OF ALTERNATE EMISSION LIMITS
GAS ENGINES
Alternative
Standard
Percent required to apply
less than or equal to
40 percent control
Percent required to do
nothing
Percent required to apply
more than 40 percent con-
trol
I
17
99
69
1
II
9
50
7
50
III
11
84
18
16
DUAL-FUEL ENGINES
Alternative
Standard
Percent required to apply
less than or equal to
40 percent control
Percent required to do
nothing
Percent required to apply
acre than 40 percent con-
trol
I
9
98
62
2
II
5
54
18
4E
III
7
37
48
13
DIESEL ENGINES
Alternative
Standard
Percent required to apply
less than or equal to
40 percent control
Percent required to do
nothing
Percent required to apply
•ore than 40 percent con-
I
11
98
50
2
trol j
II
7
56
4
44
III
9
86
29
14
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Federal Register / Vol. 44. No. 142 / Monday, July 23. 1979 / Proposed Rules
Selection of limits.—A concentration
(ppm) format was selected for the
standards. Consequently, the brake-
specific NO, emission limits
corresponding to the second alternative
for selecting numerical emission limits
(i.e., gas - 9 g/hp-hr; dual-fuel - 5 £/hp-
hn diesel - 7 g/hp-hr) must be converted
to concentration limits (corrected to 15
percent O. on a dry basis). This may be
done by dividing the brake-specific
volume of NO, emissions by the brake-
specific total exhaust gas volume.
Determining the brake-specific volume
of NO, emissions is straight-forward.
Determining the brake-specific total
exhaust gas volume is more complex, in
that the brake-specific exhaust flow and
the exhaust gas molecular weight are
unknown. Knowing the fuel heating
value and composition, the brake-
specific fuel consumption, and assuming
15 percent excess air, however, defines
these unknowns. (The complete
derivation is explained in detail in the
Standards Support and Environmental
Impact Statement.) Combining these
factors leads to the following conversion
factor:
/16.6 + 3.29
\12.0 + 2
x (BSFC)
where:
NO, = NO, concentration (ppm) corrected to
15 percent Oi.
BSNO, = Brake-specific NO, emissions, g/
hp-hr.
BSFC = Brake-specific fuel consumption, g/
hp-hr.
Z = Hydrogen/Carbon ratio of the fuel.
For natural gas, a hydrogen-to-carbon
(H/C) ratio of 3.5 and a lower heat value
(LHV) of 20,000 Btu/lb was assumed.
Diesel ASTM-2 has a H/C ratio of 1.8
and a LHV of 18,320 Btu/lb.
Applying this conversion factor to the
brake-specific emission limits
associated with the second alternative
for selecting NO, emissions limits leads
to the NO, concentration emission limits
included in the proposed standards:
Engme NOB emission Hmit
Gas _ 700 ppm.
Duat-Hiel/Dtesel 600 ppm.
These emission limits have been
rounded upward to the nearest 100 ppm
to include a "margin" to allow for source
variability. The standard for diesel
engines has also been applied to dual-
fuel engines. If a separate emission limit
has been selected for dual-fuel engines,
the corresponding numerical NO,
concentration emission limit would be
400 ppm. Sales of dual-fuel engines,
however, have ranged from 17 to 95
units annually over the past five years,
with a general trend of decreasing sales.
Dual-fuel engines serve the same
applications as diesel engines, and new
dual-fuel engines will likely operate
primarily as diesel engines because of
increasingly limited natural gas
supplies. Thus, the combining of dual-
fuel engines with diesel engines for
standards of performance will have little
adverse impact and will simplify
enforcement of the standards of
performance.
The effect of ambient atmospheric
conditions on NO, emissions from large
stationary 1C engines can be significant.
Therefore, to enforce the standards
uniformly, NO, emissions must be
determined relative to a reference set of
ambient conditions. All existing ambient
correction factors were reviewed that
could potentially be applied to large
stationary 1C engines to correct NO,
emissions to standard conditions.
The correction factors that were
selected for both spark ignition (SI) and
compression ignition (CI) engines are
included in the proposed standards. For
the compression ignition engines (i.e.,
diesel and dual-fuel), a single correction
factor for both temperature and
humididty was selected. For spark
ignition engines (i.e., gas), separate
correction factors were selected for
humidity and temperature, and
measured NO, emissions are corrected
to reference ambient conditions by
multiplying these two factors together.
No correction factor was selected for
changes in ambient pressure because no
generalized relationship could be
determined from the very limited data
that are available. These correction
factors represent the general effects of
ambient temperature and relative
humidity on NO, emissions, and will be
used to adjust measured NO, emissions
during any performance test to
determine compliance with the
numerical emission limit.
Since the recommended factors may
not be applicable to certain engine
models, as an alternative to the use of
these correction factors, engine
manufacturers, owners, or operators
may elect to develop their own ambient
correction factors. All such correction
factors, however, must be substantiated
with data and then approved by EPA for
use in determining compliance with NO,
emission limits. The ambient correction
factor will be applied to all performance
tests, not only those in which the use of
such factors would reduce measured
emission levels.
As discussed in "Standards Support
and Environmental Impact Statement:
Proposed Standards of Performance for
Stationary Gas Turbines," EPA-450/2-
77-017a, the contribution to NO,
emissions by the conversion of fuel-
bound nitrogen in heavy fuel to NO, can
be significant for stationary gas
turbines. The organic NO, contribution
to total gas turbine NO, emissions is
complicated by the fact that the
percentage of fuel-bound nitrogen
converted to NO, decreases as the fuel-
bound nitrogen level increases. Below a
fuel-bound nitrogen level of about 0.05
percent, essentially 100 percent of the
fuel-bound nitrogen is converted to NO,
Above a fuel-bound nitrogen level of
about 0.4 percent, only about 40 percent
is converted to NO,.
As discussed in the Standards
Support and Environmental Impact
Statement, Volume I for Stationary Gas
Turbines, assuming a fuel with 0.25
percent weight fuel-bound nitrogen
(which allows approximately 50 percent
availablility of domestic heavy fuel oil),
controlled NO, emissions would
increase by about 50 ppm due to the
contribution to NO, emissions of fuel-
bound nitrogen. In gas turbines, this
contribution was significant when
compared to the proposed emission limit
of 75 ppm. However, for large 1C
engines, the contribution of fuel-bound
nitrogen to NO, emissions is likely to be
small (approximately 10 percent). Sales
of 1C engines firing heavy fuels is
insignificant and not expected to
increase in the near future. Given that
the emission limits have been rounded
upward to the nearest 100 ppm and the
potential contribution of fuel-bound
nitrogen to NO, emissions is very small,
no allowance has been included for the
fuel-bound nitrogen content of the fuel
in determining compliance with the
standards of performance.
Selection of Compliance Time Frame
Manufacturers of large-bore 1C
engines are generally committed to a
particular design approach and,
therefore, conduct extensive research,
development, and prototype testing
before releasing a new engine model for
sale. Consequently, these manufacturers
will require some period of time to alter
or reoptimize and test 1C engines to
meet standards of performance. The
estimated time span between the
decision by a manufacturer to control
NO, emissions from an engine model
and start of production of the first
controlled engine is about 15 months for
any of the four demonstrated emission
control techniques. With their present
facilities, however, testing can typically
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be conducted on only two to three
engine models at a time. Since most
manufacturers produce a number of
engine models, additional time is
required before standards of
performance become effective. In
addition, a number of manufacturers
produce their most popular engine
models at a fairly steady rate of
production and satisfy fluctuating
demands from inventory. Consequently,
additional time in necessary to allow
manufacturers to sell their current
inventory of uncontrolled 1C engines
before they must comply with standards
of performance.
It is estimated that about 30 months
delay in the applicability date of the
standard is appropriate to allow
manufacturers time to comply with the
proposed standards of performance. In
addition, in light of the stringency of the
standards (i.e., many engine models will
have to reduce NO, emissions by more
than 40 percent) this time period
provides the flexibility for
manufacturers to develop and use
combinations of the control techniques
upon which the standards are based or
other control techniques. Consequently,
30 months from today's date is selected
as the delay period for implementation
of these standards on large stationary 1C
engines.
Selection of Monitoring Requirements
To provide a means for enforcement
personnel to ensure that an emission
control system installed to comply with
standards of performance is properly
operated and maintained, monitoring
requirements are generally included in
standards of performance. For
stationary 1C engines, the most
straightforward means of ensuring
proper operation and maintenance
would be to monitor NO, emissions
released to the atmosphere.
Installed costs, however, for
continuous monitors are approximately
$25,000. Thus the cost of continuous NO,
emission monitoring is considered
unreasonable for 1C engines since most
large stationary 1C engines cost from
$50,000 to $3,000,000 (i.e., 1000 hp gas
production engine and 20,000 hp
electrical generation engine).
A more simple and less costly method
of monitoring is measuring various
engine operating parameters related to
NO, emissions. Consequently,
monitoring of exhaust gas temperature
was considered since this parameter
could be measured just after the
combustion process during which NO, is
formed. However, a thorough
investigation of this approach showed
no simple correlation between NO,
emission and exhaust gas temperature.
A qualitative estimate of NO,
emissions, however, can be developed
by measuring several engine operating
parameters simultaneously, such as
spark ignition or fuel injector timing,
engine speed, and a number of other
parameters. These parameters are
typically measured at most installations
and thus should not impose an
additional cost impact. For these
reasons, the emission monitoring
requirements included in the proposed
standards of performance require
monitoring various engine operating
parameters.
For diesel and dual-fuel engines, the
engine parameters to be monitored are:
(1) Intake manifold temperature; (2)
intake manifold pressure; (3) rack
position; (4) fuel injector timing; and (5)
engine speed. Gas engines would require
monitoring of (1) intake manifold
temperature; (2) intake manifold
pressure; (3) fuel header pressure; (4)
spark timing; and (5) engine speed.
Another parameter that could be
monitored for gas engines is the fuel
heat value, since it can affect NO,
emissions significantly. Because of the
high costs of a fuel heating value
monitor, and the fact that many facilities
can obtain the lower heating value
directly from the gas supplier,
monitoring of this parameter would not
be required.
The operating ranges for each
parameter over which the engine could
operate and in which the engine could
comply with the NO, emission limit
would be determined during the
performance test. Once established,
these parameters would be monitored to
ensure proper operation and
maintenance of the emission control
techniques employed to comply with the
standards of performance.
For facilities having an operator
present every day these operating
parameters would be recorded daily. For
remote facilities, where an operator is
not present every day, these operating
parameters would be recorded weekly.
The owner/operator would record the
parameters and, if these parameters
include values outside the operating
ranges determined during the
performance test, a report would be
submitted to the Administrator on a
quarterly basis identifying these periods
as excess emissions. Each excess
emission report would include the
operating ranges for each parameter as
determined during the performance test,
the monitored values for each
parameter, and the ambient air
conditions.
Selection of Performance Test Method
A performance test method is required
to determine whether an engine
complies with the standards of
performance. Reference Method 20,
"Determination of Nitrogen Oxides,
Sulfur Dioxide, and Oxygen emissions
from Stationary Gas Turbines," which
was proposed in the October 3,1977
Federal Register, is proposed as the
performance test method for 1C engines.
Reference Method 20 has been shown to
provide valid results. Consequently,
rather than developing a totally new
reference test method, Reference
Method 20 would be modified for use on
1C engines.
The changes and additions to
Reference Method 20 required to make it
applicable for testing of internal
combustion engines include (by section):
1. Principle and Applicability. Sulfur
dioxide measurements are not
applicable for internal combustion
engine testing.
6.1 Selection of a sampling site and
the minimum number of traverse points.
6.11 Select a sampling site located at
least five stack diameters downstream
of any turbocharger exhaust, crossover
junction, or recirculation take-offs and
upstream of an dilution air inlet. Locate
the sample site no closer than one meter
or three stack diameters (whichever is
less) upstream of the gas discharge to
the atmosphere.
6.1.2 A preliminary Oi traverse is not
necessary.
6.1.2.2 Cross-sectional layout and
location of traverse points use a
minimum of three sample points located
at positions of 16.7, 50 and 83.3 percent
of the stack diameter.
6.2.1 Record the data required on the
engine operation record on Figure 20.7 of
Reference Method 20. In addition, record
(a) the intake manifold pressure; (b) the
intake manifold temperature; (c) rack
position; (d) engine speed; and (e)
injector or spark fuming. (The water or
steam injection rate is not applicable to
internal combustion engines.)
NO, emissions measured by
Reference Method 20 will be affected by
ambient atmospheric conditions.
Consequently, measured NO, emissions
would be adjusted during any
performance test by the ambient
condition correction factors discussed
earlier, or by custom correction factors
approved for use by EPA.
The performance test may be
performed either by the manufacturer or
at the actual user operating site. If the
test is performed at the manufacturer's
facility, compliance with that
performance test will be sufficient proof
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
of compliance by the user as long as the
engine operating parameters are not
varied during user operation from the
settings under which testing was done.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
Section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statement should
be addressed to Mr. Jack R. Fanner (see
ADDRESSES Section).
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are (1) to allow
interested parties to identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review. The
docket requirement is discussed in
•ection 307(d) of the Clean Air Act.
Miscellaneous
As prescribed by Section 111 of the
Act, this proposal is accompanied by the
Administrator's determination that
emissions from stationary 1C engines
contribute to air pollution which causes
or contributes to the endangerment of
public health or welfare, and by
publication of this determination in this
issue of the Federal Register. In
accordance with section 117 of the Act,
publication of these standards was
preceded by consultation with
appropriate advisory committees,
independent experts, and federal
department and agencies. The
Administrator welcomes comments on
all aspects of the proposed regulations,
including the designation of stationary
1C engines as a significant contributor to
air pollution which causes or contributes
to the endangerment of public health or
welfare, economic and technological
issues, monitoring requirements and the
proposed test method.
Comments are specifically invited on
the severity of the economic and
environmental impact of the proposed
standards on stationary naturally
aspirated carbureted-gas 1C engines
since some parties have expressed
objection to applying the proposed
standards to these engines. Comments
are also invited on the selection of
rotary engines for control by standards
of performance. These engines were
included because they are expected to
be contributors to NO, emissions from
stationary sources and can be controlled
by demonstrated NO, emission control
techniques. Any comments submitted to
the Administrator on these issues,
however, should contain specific
information and data pertinent to an
evaluation of the magnitude of this
impact, its severity, and its
consequences.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Act reflect:
The degree of emission limitation and the
percentage reduction achievable through
application of the best technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated [section lll(a)(l)).
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be seclected as the basis of standards of
performance because of costs
associated with its use. Accordingly,
standards of performance should not be
viewed as the ultimate in achievable
emission control. In fact, the Act may
require the imposition of a more
stringent emission standard emission in
several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources located in nonattainment areas
(i.e., those areas where statutorily
mandated health and welfare standards
are being violated). In this respect,
section 173 of the Act requires'that new
or modified sources constructed In an
area which exceeds the National
Ambient Air Quality Standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3). The statute defines LAER
as that rate of emissions which reflects:
(A) 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
(B) The most stringent emission limitation
which is acheved in practice by such class or
category of source, whichever is more
stringent.
In no event can the emission rate exceed
any applicable new source performance
standard.
A similar situation may arise under
the prevention-of-significant-
deterioration-of-air-quality provisions of
the Act. These provisions require that
certain sources employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act. Best available
control technology must be determined
on a case-by-case basis, taking energy.
environmental and economic impacts,
and other costs into account. In no event
may the application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all cases, State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reduction than
those required by standards of
performance for new sources.
Finally, states are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly
new sources may in some cases be
subject to limitations more stringent
than standards of performance under
section ill, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
Under EPA's "new" sunset policy for
reporting requirements in regulations.
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless EPA takes affirmative action to
extend them.
EPA will review this regulation four
years from the date of promulgation
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emissions control technology.
An economic impact assessment has
been prepared as required under section
317 of the Act and is included in the
Standards Support and Environmental
Impact Statement.
V-FF-20
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Federal Register / Vol. 44, No. 142 / Monday. ]uly 23. 1979 / Proposed Rules
Dated: July 11.1979.
Douglas M. Costle.
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
1. By adding Subpart FF as follows:
Subpart FF—Standards of Performance for
Stationary Internal Combustion Engine*
Sec.
60.320 Applicability and designation of
affected facility.
60.321 Definitions.
60.322 Standards for nitrogen oxides.
60.323 Monitoring of operations.
60.324 Test methods and procedures.
Authority: Sees. Ill and 301(a) of the Clean
Air Act, as amended, (42 U.S.C. 1857c-7,
1857g(a)), and additional authority as noted
below.
Subpart FF—Standards of
Performance for Stationary Internal
Combustion Engines
$60.320 Applicability am) designation of
affected facility.
The provisions of this subpart are
applicable to the following affected
facilities which commence construction
beginning 30 months from today's date:
(a) All gas engines that are either
greater than 350 cubic inch displacement
per cylinder or equal to o,r greater than 8
cylinders and greater than 240 cubic
inch displacement per cylinder.
(b) All diesel or dual-fuel engines that
are greater than 560 cubic inch
displacement per cylinder.
(c) All rotary engines that are greater
than 1500 cubic inch displacement per
rotor.
$ 60.321 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act or in subpart A of
this part.
(a) "Stationary internal combustion
engine" means any internal combution
engine, except gas turbines, that is not
self propelled. It may, however, be
mounted on a vehicle for portability.
(b) "Emergency standby engine"
means any stationary internal
combustion engine which operates as a
mechanical or electrical power source
only when the primary power source for
a facility has been rendered inoperable
during an emergency situation.
(c) "Reference ambient conditions"
means standard air temperature (29.4°C,
or 85°F), humidity (17 grams H,O/kg dry
air, or 75 grains H»O/lb dry air), and
pressure (101.3 kilopascals, or 29.92 in.
Hg.).
(d) "Peak load" means operation at
100 percent of the manufacturer's design
capacity.
(e) "Diesel engine" means any
stationary internal combustion engine
burning a liquid fuel.
(f) "Gas enine" means any stationary
internal combustion engine burning a
gaseous fuel.
(g) "Dual-fuel engine" means any
stationary internal combustion engine
that is burning liquid and gaseous fuel
simultaneously.
(h) "Unmanned engine" means any
stationary internal combustion engine
installed and operating at a location
which does not have an operator
regularly present at the site for some
portion of a 24-hour day.
(i) "Non-remote operation" means any
engine installed and operating at a
loction which has an operator regularly
present at the site for some portion of a
24-hour day.
(j) "Brake-specific fuel consumption"
means fuel input heat rate, based on the
lower heating value of the fuel,
expressed on the basis of power output
(i.e., (kj/w-hr).
(k) "Weekly basis" means at seven
day intervals.
(1) "Daily basis" meahs at 24 hours
intervals.
(m) "Rotary engine" means any
Wankel type engine where energy from
the combustion of fuel is converted
directly to rotary motions instead of
reciprocating motion,
(n) "Displacement per rotor" means
the volume contained in the chamber of
a rotary engine between one flank of the
rotor and the housing at the instant the
inlet port is closed.
§ 60.322 Standards for nitrogen oxides.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere,
except as provided in paragraphs (b)
and (c) of this section—
(1) From any gas engine, with a brake-
specific fuel consumption at peak load
more than or equal to 10.2 kilojoules/
watt-hour any gases which contain
nitrogen oxides in excess of 700 parts
per million volume, corrected to 15
percent oxygen on a dry basis.
(2) From any diesel or dual-fuel engine
with a brake-specific fuel consumption
at peak load more than or equal to 10.2
kilojoules/watt-hour any gases which
contain nitrogen oxides in excess of 600
parts per million volume, corrected to 15
percent oxygen on a dry basis.
(3) From any stationary internal
combustion engine with a brake-specific
fuel consumption at peak load of less
than or equal to 10.2 kilojoules/watt-
hour any gases which contain nitrogen
oxides in excess of:
(i) STO = 700 Y- for any gas engine,
(11) STO = 600 i^2 for any diesel or
dual-fuel engine
where:
STD = allowable NO, emissions (parts-per-
million volume corrected to 15 percent
oxygen on a dry basis).
Y = manufacturer's,rated brake-specific fuel
consumption at peak load (kilojoules per
watt-hour) or owner/operator's brake-
specific fuel consumption at peak load a«
determined in the field.
{b) All one and two cylinder
reciprocating gas engines are exempt
from paragraph (a) of this section.
(c) Emergency standby engines are
exempt from paragraph (a) of this
section.
$60.323 Monitoring of operations.
(a) The owner or operator of any
stationary internal combustion engine,
subject to the provisions of this subpart
must, on a weekly basis for unmanned
engines and on a daily basis for manned
engines, monitor and record the
following parameters. All monitoring
systems shall be accurate to within five
percent and shall be approved by the
Administrator.
(1) For diesel and dual-fuel engines:
(i) Intake manifold temperature
(ii) Intake manifold pressure
(iii) Engine speed
(iv) Diesel rack position (fuel flow)
(v) Injector timing
(2) For gas engines:
(i) Intake manifold temperature
(ii) Intake manifold pressure
(iii) Fuel header pressure
(iv) Engine speed
(v) Spark ignition timing
(b) For the purpose of reports required
under § 60.7(c), periods of excess
emissions that shall be reported are
defined as any daily (for manned
engines) or weekly (for unmanned
engines) period during which any one of
the parameters specified under
paragraph (a) of this section falls
outside the range identified for that
parameter udner § 60.324(a)(3). Each
excess emission report shall include the
range identified for each operating
parameter under § 60.324(a)(4), the
monitored value for each operating
parameter specified under § 60.323(a),
V-FF-21
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
the ambient air conditions during the
period of excess emissions, and any
graphs and/or figures developed under
i 60.324{a)(4)
(Sec. 114 of the Clean Air Act. as amended
(42 U.S.C. 1857C-S))
} 60.324 Test methods and procedures.
The reference methods in Appendix A
to this part, except as provided in
{ 60.8(b), shall be used to determine
compliance with the standards
prescribed in $ 60.322 as follows:
(a) Reference Method 20 for the
concentration of nitrogen oxides and
oxygen. The span for the nitrogen oxides
analyzer used in this method shall be
1500 ppm.
(1) The following changes and
additions [by section] to Reference
Method procedures should be followed
when determining compliance with
$ 60.322:
1. Principle and Applicability. Sulfur
dioxide measurements are not
applicable for internal combustion
engine testing.
6.1 Selection of a sampling site and the
minimum number of traverse points.
6.11 Select a sampling site located at least
five stack diameters downstream of any
turbocharger exhaust, crossover junction, or
recirculation take-offs and upstream of any
dilution air inlet Locate the sample site no
closer than one meter or three stack
diameters (whichever is leas) upstream of the
gas discharge to the atmosphere.
6.1.2 a preliminary Ot traverse is not
necessary.
6.2 Cross-sectional layout and location of
traverse points. Use a minimum of three
sample points located at positions of 16.7,50
and 83.3 percent of the stack diameter.
6.2.1 Record the data required on the
engine operation record on Figure 20.7 of
Reference Method 20. In addition, record (a)
the intake manifold pressure; (b) the intake
manifold temperature; (c) rack position, fuel
header pressure or carburetor position; (d)
engine speed; and (e) injector or spark timing.
(The water or steam injection rate is not
applicable to internal combustion engines.)
(2) The nitrogen oxides emission level
measured by Reference Method 20 shall
be adjusted to reference ambient
conditions by the following ambient
condition correction factors:
NO, corrected = (K) NO. observed
where K is determined as follows:
Fuel
Diesel and
Dual-Fuel
Gas
Correction Factor
K = 1/{1 * 0.00235(H - 75) + 0.00220 (T - 85))
K =
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Federal Register / Vol. 44, No. 142 / Monday, July 23,1979 / Notices
[FRL 1099-6]
Air Pollution Prevention and Control;
Addition to the List of Categories of
Stationary Sources
Section 111 of the Clean Air Act (42
U.S.C. 1857c-6) directs the
Administrator of the Environmental
Protection Agency to publish, and from
time to time revise, a list of categories of
stationary sources which he determines
may contribute significantly to air
pollution which causes or contributes to
the endangerment of public health or
welfare. Within 120 days after the
inclusion of a category of stationary
sources in such list, the Administrator is
required to propose regulations
establishing standards of performance
for new and modified sources within
such category. At present standards of
performance for 27 categories of sources
have been promulgated.
The Administrator, after evaluating
available information, has determined
that stationary internal combustion
engines are an additional category of
stationary sources which meets the
above requirements. The basis for this
determination is discussed in the
preamble to the proposed regulation that
is published elsewhere in this issue of
the Federal Register. Evaluation of other
stationary source categories is in
progress, and the list will be revised
from time to time as the Administrator
deems appropriate. Stationary internal
combustion engines are included on the
proposed NSPS priority list (published
August 31, 1978) required by section
I1l(f)(l), but since the priority list is not
final, stationary internal combustion
engines are also being listed as
indicated below at this time. Once the
priority list is promulgated, all source
categories on the promulgaled list are
considered listed under section
lll(hj(l)(A), and separate listings such
HS this will not be made for those source
categories
Accordingly, notice is given that the
Administrator, pursuant to section
lll(b)(l)(A) of the Act. and after
consultation with appropriate advisory
committees, experts and Federal
departments and agencies in accordance
with section 117(0 of the Act. effective
July 23, 1979 amends the list of
categories of stationary sources to read
as follows:
List of Categories of Stationary Sources
and Corresponding Affected Facilities
Source Category
*~ * * * *
Affected Facilities
Internal combustion engines
Proposed standards of performance
applicable to the above source category
appear elsewhere in this issue of the
Federal Register.
Dated: July 11.1979.
Douglas M. Costle,
Administrator./
(FR Doc 7S-Z2225 Filed 7-20-79. 8 45 am|
Federal Register / Vol. 44, No. 182 / Tuesday, September 18, 1979
[40 CFR Part 60]
[FRL 1321-5]
Standards of Performance for New
Stationary Sources; Stationary Internal
Combustion Engines
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for stationary internal
combustion engines, which were
proposed on July 23,1979 (44 FR 43152),
is being extended from September 21,
1979, to October 22,1979.
DATES: Comments must be received on
or before October 22,1979.
ADDRESSES: Comments should be
submitted to Mr. David R. Patrick, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: On July
23, 1979 (44 FR 43152), the
Environmental Protection Agency
proposed standards of performance for
the control of emissions from stationary
internal combustion engines. The notice
of proposal requested public comments
on the standards by September 21,1978.
Due to a delay in the shipping of the
Standards Support Document, sufficient
copies of the document have not been
available to all interested parties in time
to allow their meaningful review and
comment by September 21,1979. EPA
has received a request from the industry
to extend the comment period by 30
days through October 22,1979. An
extension of this length is justified since
the shipping delay has resulted in
approximately a three-week delay in
processing requests for the document.
Additionally, page 9-75 of the
Standards Support Document was
inadvertently omitted. Persons wishing
to obtain copies of this page should
contact Mr. Doug Bell, Emission
Standards and Engineering Division,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5477.
Dated: September 12,1979.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation.
[FR Doc. Tt-Oea Filed «-17-7ft 6.45 imj
V-FF-23
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
SECONDARY LEAD SMELTERS
SUBPART L
-------
Federal Register / Vol. 45. No. 76 / Thursday. April 17. 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1415-3]
Standards of Performance for New
Stationary Sources: Secondary Lead
Smelters; Review of Standards
AGENCY: Environmental Protection
Agency.
ACTION: Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for secondary
lead smelters (40 CFR 60.120). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's plans to undertake a program
which will be designed, depending upon
its findings, to develop fugitive
particulate matter emission standards
and SO, standards applicable to
secondary lead smelters.
DATE: Comments must be received by
June 16,1980.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. A-79-20.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271. The document "A Review of
Standards of Performance for New
Stationary Sources—Secondary Lead
Smelters," EPA-450/3-79-015, is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:
Introduction
On June 11,1973, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate matter emissions
from secondary lead smelters. The
standard, promulgated on March 8,1974,
and amended on April 17 and October 6,
1975, applies to any secondary lead
smelter under construction,
modification, or reconstruction on or
after June 11,1973. The specific lead
smelter facilities subject to the standard
are reverberatory furnaces (stationary,
rotating, rocking, or tilting), blast
(cupola) furnaces and pot furnaces of
more than 550-lb charging capacity.
Furnaces for smelting lead alloy for
newspaper linotype are subject to the
standards if they meet the same size
requirement as applied to pot furnaces.
The Clean Air Act Amendments of
1977 require that the Administrator of
EPA review and, if appropriate, revise
established standards of performance
for new stationary sources at least every
4 years (Section lll(b)(l)(B)). Following
the adoption of the amendments, EPA
contracted with the MITRE Corporation
to undertake a survey of available
literature and information pertaining to
secondary lead processes, emissions
and control technologies, including
results from tests of new lead smelters
to assess the need for revision of the
standard. The survey involved visits to
each EPA Regional Office as well as
review of recent literature and study
results, but did not include visits to
plants. Based principally on this review,
EPA plans to begin a program to
develop standards which would limit
the emission of fugitive particulate
matter, and sulfur dioxide from
secondary lead smelters. This program
will include an extensive technical
investigation and assessment. Final
decisions pertaining to whether
standards should be adopted and the
level of any such standards will not be
made until after these investigations and
assessments are completed. The time
required to develop these standards for
proposal will be approximately 2 years.
Industry Review
Secondary lead produced by smelting
of scrap accounts for roughly half of all
lead produced in the United States.
After a record output of over 626,000
tons in 1976, secondary lead output
declined in 1977 to between 588,000 and
600,000 tons. However, production of
lead from both primary and secondary
sources is expected to grow at an annual
rate of slightly under 2 percent or by
about 50 percent between 1976 and 2000.
This compares with an average annual
increase in demand for lead from 1967 to
1976 of about 3 percent. It is expected
that the relative share of the market
held by secondary lead production will
remain near the 50 percent level.
It is estimated, based on an assumed
secondary smelter capacity of 50 ton/
day, that on the average, two new plants
and one to two modified smelters will
become subject to NSPS each year. This
estimate is consistent with the latest
Bureau of Mines data (1978) which show
six plants completed or scheduled for
completion in the 1977-1979 period
(including major expansions of existing
plants). Through 1978, six plants have
been identified which have come on line
subject to the standard.
The secondary lead market is
dominated by a few companies. In
addition, the trend is toward fewer and
larger plants as evidenced by the
decrease in the total number of smelters
from 160 in 1967 to about 115 in 1975.
Overall, the average annual output per
smelter is in the range of 5,700 to 6,000
tons. Geographically, the industry is
somewhat dispersed with secondary
lead smelters located in all of the ten
EPA regions.
Emissions and Control Technology
Process Particulate Emissions. The
present standard of performance limits
the emission of particulate matter from
blast or reverberatory furnaces to 50
mg/dscm (0.022 gr/dscf) and to less than
20 percent opacity. In addition, the
standard limits the opacity of emissions
from pot furnaces to less than 10 percent
opacity. For a typical reverberatory or
blast furnace with uncontolled
emissions of 147 Ibs/ton and 193 Ibs/ton
of feed material respectively, the
standard limits emissions to one and 2
Ibs/ton. This compares to an estimated
controlled emission level of 21 and 28
Ibs/ton in the absence of the new source
standard. In this review, results from
four compliance tests were obtained.
The results from reverberatory and blast
furnace tests were 0.015 gr/dscf and
0.0135 gr/dscf respectively.
Lead Emissions. The present standard
of performance does not specifically
limit the atmospheric emission of lead
from secondary lead furnaces. However,
lead is controlled by the same devices
employed to limit particulate matter
emissions. Reported lead emission data,
although variable, indicate uncontrolled
lead emissions to be approximately 23
percent of the total particulate matter
emissions. Controlled lead emissions
measured in six tests conducted on
emissions from seven furnaces were
found to range in concentration from
0.009 to 0.0846 Ib/ton with five of the six
below 0.04 Ib/ton. In another survey of
11 controlled secondary lead smelters in
the Chicago area, an emission rate of
0.002 Ibs lead/ton of product was
reported. Results of a further test at a
baghouse controlled reverberatory
furnace indicated particulate matter and
lead concentrations of 0.016 and 0.001
gr/dscf, respectively. The variability in
these data and the lack of other
simultaneous inlet and outlet data do
not allow a precise statement of relative
control effectiveness. However, the data
do consistently indicate that the ratio of
lead to particulate emissions from
controlled furnaces is not higher than
the ratio (i.e., 23 percent) for
uncontrolled furnaces.
Fugitive Emissions. In addition to the
material discharged through the stack of
a secondary lead furnace, particulate
V-L-2
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Federal Register / Vol. 45, No. 76 / Thursday, April 17,1980 / Proposed Rules
and gaseous matter may be emitted into
the atmosphere in and around a plant
from other operations. Some of these
fugitive emissions are process-related,
e.g., when materials escape from the
hoods provided around potential outlet
points of a furnace. Others result from
auxiliary operations. No fugitive
emission points, whether related to
processing or to auxiliary operations at
the site, are currently subject to specific
control under NSPS for secondary lead
smelters.
In some situations, fugitive emissions
may be high. For example, the high
concentration of lead, particularly in the
soil, close to two Toronto smelters was
ascribed by Canadian investigators to
"low-level, dust-producing operations
rather than * * * stack fumes." In
apparently extreme situations, fugitive
particulate emissions from processing
may amount to over 15 Ib/ton of charge
from reverberatory furnaces and as
much as 12 Ib/ton from blast furnaces.
These rates, although much lower than
uncontrolled emission rates from
furnace stacks, are substantially higher
than rates from stacks meeting the
NSPS.
Several techniques have been applied
to reduce fugitive emission rates and
recently significant improvements in the
technology for controlling fugitive
emissions from both process- and site-
related operations in secondary smelting
of lead have been reported in Denmark.
The methodology uses improved
furnaces that minimize the escape of
dusts during smelting and also enable
baghouse contents to be recharged as
collected, thereby eliminating the
accumulation of these fines in storage
piles where they are subject to transport
into the environment. Specialized waste
management and housekeeping
procedures are used in conjuction with
the furnaces to reduce the opportunity
for emissions from storage of raw
materials and other sources on the site.
The technology has been investigated by
the EPA Industrial Environmental
Research Laboratory in Cincinnati in
connection with the National Institute of
Occupational Safety and Health
(NIOSH). Testing of the furnaces has
been conducted under the joint auspices
of EPA and NIOSH at a plant in
Denmark. Initial reports indicate the
technology as having high potential for
application in reducing fugitive
emissions from secondary lead smelters
in the United States.
Sulfur Dioxide. The rate of
uncontrolled emissions of SO, from
secondary lead smelters is
approximately 76 Ib/ton of lead
produced for blast furnaces and of 114
Ib/ton for reverberatory furnaces. A
reverberatory furnace of 50 tons/day
(2.08 tons/hr) would emit about 2.8 tons
of SOj each day and a blast furnace of
the same capacity about 1.9 tons.
Assuming an equal mix between blast
and reverberatory furnace production,
the total secondary lead production in
1975 of 658,500 tons would have resulted
in about 31,000 tons of SOj. Currently,
no NSPS for SO» from secondary lead
smelters are in effect.
SO2 control is not normally practiced
at lead smelters. However, both
regenerative SOi control systems which
are used in the primary smelting
industry to control SOi and produce
sulfuric acid, and non-regenerative
scrubbing systems used to control SOj
emissions from steam generators are
potentially applicable to SO2 control at
secondary lead smelters. A more
detailed engineering assessment is
needed to further assess the
applicability of these technologies to
determine the best demonstrated control
technology and an appropriate level for
any standard. In addition, the cost of
SO2 control and the associated
economic impact require further study
as these may be the primary
consideration in analyzing the feasibility
of control.
Conclusions
EPA believes that the Information
obtained in this review of the secondary
lead industry does not provide a basis
for determining conclusively that the
standard should be revised nor at what
level any revised standard should be
set. However, the available data show
that a project should be undertaken to
further assess the need for and, as
appropriate to develop standards
limiting fugitive particulate matter
(including lead) and sulfur dioxide
emissions from secondary lead plants.
The available particulate matter
compliance test data obtained in this
review are consistent with the test data
used by EPA in establishing the present
standard and, although very limited,
these data, added to the data used in
developing the present standard support
the validity of the present standard.
Similarly, the data available on lead
emissions from furnace stacks suggest
that the particulate matter standard is
adequate to require installation of
control systems which represent best
available control technology for both
particulate matter and lead. Therefore, a
separate standard for lead is considered
unnecessary. EPA will welcome any
additional data pertaining to this
decision on the particulate matter
standard and on lead emissions. In
addition, EPA in the planned standards
development discussed below, will seek
to obtain additional recent compliance
test data and will assess this in terms of
the current standard.
The project to assess the need for and,
as appropriate, to develop fugitive'
particulate matter and sulfur dioxide
standards will be undertaken by EPA's
Emission Standards and Engineering
Division. This project is expected to
begin early in 1980 and will follow a
standardized approach which involves
detailed engineering and economic
assessments proceeding proposal of any
standards. Standards resulting from this
project would be proposed for comment
in early 1982.
Dated: April 9,1980.
Douglas M. Costie,
Administrator.
|FR Doc. 80-11666 Filed 4-16-60; 8.45 am)
BILLING CODE 6560-01-*!
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
ELECTRIC ARC FURNACES
(STEEL INDUSTRY)
SUBPART AA
-------
Federal Register / Vol. 45, No. 78 / Monday, April 2J, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION.
AGENCY
40 CFR Part 60
[FRL 1415-2]
Review of Standards of Performance
for New Stationary Sources; Electric
Arc Furnaces (Steel Industry)
AGENCY: Environmental Protection
Agency.
ACTION: Proposed Rule.
SUMMARY: EPA has reviewed its
standards of performance for electric
arc furnaces in the steel industry (40
CFR 60.270, Subpart AA) as required
under the Clean Air Act, as amended
August 1977. EPA intends to explore
revising the standards to reflect
demonstrated best available control
technology for electric arc furnaces and
would add argon-oxygen
decarbonization (ADD) furnaces to the
standard. Visible emission limitations
would be reduced to be consistent with
improved control technology.
DATES: Comments must be received by
June 20,1980.
ADDRESSES: Send comments to: Central
Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street, S.W., Washington, D.C. 20460,
Attention: Docket A-79-33. Comments
should be submitted in duplicate if
possible.
FOR FURTHER INFORMATION CONTACT:
Mr. Stanley T. Cuffe, Telephone: (919)
541-5295. The document "A Review of
Standards of Performance for Electric
Arc Furnaces in the Steel Industry" is
available upon request from Mr. Stanley
T. Cuffe, (MD-13), Chief, Industrial
Studies Branch, Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, N.C. 27711.
SUPPLEMENTARY INFORMATION:
Background
On October 21,1974, EPA proposed a
standard under Section 111 of the Clean
Air Act to control particulate matter
emissions from electric arc furnaces
(EAF) in the steel industry. The
standard, promulgated on September 23,
1975, applies to any facility constructed
or modified after October 21,1974. The
standard for particulate matter under
§ 60.272 limits the discharge to
atmosphere from an electric arc furnace
of any gases that:
1. Contain particulate matter in excess
of 12 mg/dscm (0.0052 gr/dscf).
2. Exhibit 3 percent opacity or greater
from a control device.
3. Exhibit greater than zero opacity
from a shop, due solely to operation of
any EAF(sj, except:
a. Shop opacity greater than zero
percent, but less than 20 percent, may
occur during charging periods.
b. Shop opacity greater than zero
percent, but less than 40 p_ercent, may
occur during tapping periods.
c. Zero opacity from a shop shall
apply only during periods when process
flow rates and pressures are being
monitored.
d. Where the capture system is
operated such that the roof of the shop
is closed during the charge and the tap,
and emissions to the atmosphere are
prevented until the roof is opened after
completion of the charge or tap, the shop
opacity standards shall apply when the
roof is opened and shall continue to
apply for the length of time defined by
the charging and/or tapping periods.
The standard for particulate matter
also limits the discharge to atmosphere
from dust handling equipment any gases
which exhibit 10 percent opacity or
greater.
The Clean Air Act Amendments of
1977 that require the Administrator of
EPA review, establish standards of
performance for new stationary sources
(NSPS) at least every 4 years, and revise
them as appropriate [Section
lll(b)(l)(B)]. EPA has completed such a
review of the standard of performance
for electric arc furnaces in the steel
industry and has decided to begin a
project to revise the standard. EPA
invites comments on this decision and
on the findings on which it is based.
Findings
Industry Statistics
In 1972, there were approximately 299
EAF's in the United States. In 1977, there
were approximately 303 EAF's being
operated in the United States. However,
about 30 EAF's were being installed
between 1974 and 1979, which indicates
that some older furnaces were probably
shutdown and replaced. Only five of the
new furnaces were subject to the
standards.
Information on planned new facilities
or modifications is limited by the
reluctance of industry to state future
plans because of current economic
uncertainties. Nevertheless, EAF
production should continue to increase.
An EAF is flexible, can operate wholly
on steel scrap, is adapted to ultrarapid
melting, can make specialty steels, and
can be quickly brought on line or taken
off production. In addition, an EAF is
relatively low in pollution potential, and
emission controls are well
demonstrated. These EAF advantages
are substantiated by industry statistics
showing that production in 1977 was
about 25.4 Mg (27.9 million tons) and 29
Mg (31.9 million tons) in 1978 versus 21.5
Mg (23.7 million tons) in 1972, when the
NSPS document was being developed.
Emissions and Control Technology
The current best demonstrated control
technology, the fabric filter, is the same
as that used when the standards were
promulgated. No major improvements in
this technology have occurred during the
intervening period; however, one
company has installed a proprietary wet
scrubber, which appears to be almost as
effective as a fabric filter and meets the
standards.
Although the fabric filter technology
has not changed, the effectiveness of
pickup systems for various process and
fugitive emissions has improved
significantly.
Some EAF shops are now operating
with closed roofs and a controlled
fugitive emission pickup system in the
roof to draw any indoor emissions into
the control device. This system may
utilize small openings in the ductwork to
draw emissions slowly out of the roof
area, or it may include dampers in the
openings that can be opened or closed
to remove these rooftop emissions. The
roof emissions include charging and
tapping emissions, and those that
escape the direct furnace evacuation
system and the canopy hoods above the
furnace. The closed-roof and fugitive
emission pickup system was designed to
meet some local agencies no-visible-
emission requirements from an EAF
shop.
Other recent technology includes total
enclosure of the furnace within the EAF
building. The system is designed to
capture all emissions of the furnace
operation cycle (meltdown, charging,
tapping, and slagging). Hoods are
strategically located for capture of the
charging, tapping, and slagging
emissions. Additionally, during the
charging operation, a curtain of air is
blown across the roof opening to direct
the emissions into the intake duct of the
control device. This system theoretically
prevents almost all emissions from
escaping the enclosure and building.
Another new concept for containing
emissions from the EAF is a partial
enclosure around the furnace. The
furnace itself may be equipped with the
conventional direct shell evacuation and
canopy hood system, but the partial
enclosure around the furnace acts as a
stack to direct fugitive furnace
emissions upward into the emission
capture system. Separate hoods are
used to capture emissions during the
tapping and slagging operation. The EAF
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Federal Register / Vol. 45, No. 78 / Monday, April 21, 1980 / Proposed Rules
shop roof is closed and the area above
the furnace and below the canopy hood
must be kept clear so that the furnace
can be charged normally by a crane. The
partial enclosure is large enough to
allow the furnace cover to be swung
over the tapping area, where it can
capture emissions from the ladle pouring
spout and tapping hoods. This total
system is reported to be virtually 100
percent effective in capturing all
emissions from the furnace shop during
normal operations.
Although about 30 furnaces were
reported to have started operation from
1974 to 1979, only 5 commenced
construction after the proposal of NSPS
and therefore were subject to regulation.
Only one of these five furnaces has been
tested for visible emissions because the
others have not completed their startup.
Although the latter met the NSPS for
visible emissions, the furnace shop did
create an enforcement issue. The
furnace shop has a closed roof;
however, some visible emissions from
charging or tapping operations drifted
out the material access doors of the
shop when they were open. Also, these
charging and tapping emissions became
intermingled and were emitted
simultaneously due to other furnaces
operating in the shop. The enforcement
issue arose when it became unclear how
to enforce NSPS when charging, tapping,
and other shop emissions became mixed
and escaped from the doors instead of
the roof. These problems are expected to
be recurring, as other new furnaces start
operation and the NSPS may require
further study to clarify the visible
emission standard to cover this
situation.
Four other recently constructed EAF's
were required by local agencies to at
least meet NSPS even though their
construction started before NSPS
proposal. One shop with two partially-
enclosed furnaces using canopy hoods
and sealed roof was tested for
particulate and visible emissions. The
local agency concluded that the system
would meet NSPS based on their source
tests. However, the control system uses
a pressure baghouse, and the testing
was conducted by company personnel in
the presence of local agency observers.
In tests of various compartments of the
baghouse with a Hi-Vol sampler, the
results show that the emissions ranged
from 0.0097 mg/dscm (0.0000042 gr/dscf)
to 0.08 mg/dscm (0.0000346 gr/dscf)
during twelve 4- to 5-hour tests.
However, this is not an official EPA
testing method and further investigation
by EPA will be necessary to
substantiate this data.
The current standard does not cover
several types of electric furnaces. The
unregulated electric furnaces are:
vaccum-arc remelting (VAR), vacuum
induction melting (VIM), electro-slag
remelting (ESR), and consumable
electrode melting (GEM) which are
primarily used to produce small
tonnages of specialty steels.
Investigation by EPA during this review
revealed that the VAR, VIM, CEM. and
ESR furnaces do not produce any
significant emissions; therefore, they
should not be considered for NSPS.
Furthermore, these low polluting
specialty furnaces are not capable of
being replacements for the much larger
conventional electric arc furnace which
has a higher pollution potential.
Argon-oxygen decarbonization
furnaces were found to be a highly
significant emitter of particulate and
visible emissions, and these furnaces
are becoming an integral part of EAF
shops that produce stainless steels.
AOD furnaces are economical and
flexible to operate; therefore, their use is
expected to increase. Because AOD
furnaces operate within an EAF shop,
produce significant amounts of
particulate and visible emissions, and
use similar air pollution control devices,
AOD furnaces should be included in the
NSPS study for the EAF. One AOD
furnace with canopy hood and baghouse
was tested for particulate emissions.
The average test result of 6.9 mg/dscm
(0.0030 gr/dscf) for the AOD furnace is
lower than the current EAF standard of
12 mg/dscm (0.0052 gr/dscf). Hence, the
NSPS review for EAF should include
AOD furnaces.
Conclusions
Based upon the review of the current
NSPS previously summarized, a program
to revise the standard is needed. This
program, which is expected to begin in
fiscal year 1980, will be directed toward:
1. Reviewing new particulate emission
data based on the capabilities of the
best available technology today. The
investigation will include analysis of
costs associated with this technology.
2. Reviewing new opacity data from
recently designed efficient exhaust
techniques, closed roofs for fugitive
emissions, and improved hood collection
for charging, tapping, arid slagging
emissions. These systems, where
installed, appear to significantly
reduced visible emissions from EAF
shops.
3. Consideration of including the AOD
furnace emissions in the revised EAF
standard, or development of a separate
standard for these furnaces. They are a
highly visible source of particulate
emissions.
All interested parties are invited to
comment on this review, the
conclusions, and EPA's planned course
of action.
Dated April 11.1980.
Douglas M. Costle,
Administrator.
(FR Doc. 80-11284 Filed 4-18-80: 8:45 am]
BILLING CODE 656O-01-M
V-AA-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
ORGANIC SOLVENT CLEANERS
SUBPART JJ
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
FRL 1375-3]
Standards of Performance for New
Stationary Sources Organic Solvent
Cleaners
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.
SUMMARY: The proposed standards
would limit emissionsof volatile organic
compounds (VOC) and trichloroethylene
1,1,1-trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane from new,
modified, and reconstructed organic
solvent cleaners (degreasers) in which
solvents are used to clean (degrease)
metal, plastic, fiberglass, or any other
type of material. The proposed
standards would specify several
equipment designs and work practices
for controlling emissions from cold
cleaners, open top vapor degreasers,
and conveyorized degreasers. When
carbon adsorber control systems are
used, a performance standard would
also apply. To determine the emissions
from carbon adsorbers, a new test
method, Reference Method 23, is
proposed to measure the concentration
of the above mentioned halogenated .
compounds, and Reference Method 25
which was proposed on October 5,1979
(44 FR 57792) would be used to measure
emissions of VOC.
The proposed standards implement
the Clean Air Act and are based on the
Administrator's determination that
organic solvent cleaners contribute
significantly to air pollution. The intent
is to require new, modified, and
reconstructed organic solvent cleaners
to use the best demonstrated system of
continuous emission reduction,
considering costs, nonair quality health,
and environmental and energy impacts.
It is also proposed that standards be
developed under section lll(d) of the
Clean Air Act, as amended, for the
control of emissions from existing
facilities of the five halogenated organic
solvents listed above. EPA is not
committed to developing section lll(d)
standards unless, after review of public
comments, standards for one or more of
these five solvents are promulgated for
new, modified, or reconstructed
facilities. If such standards were
promulgated, EPA would develop a
guideline document that would require
States to develop emission control
regulations for existing organic solvent
cleaners which use any of the five
halogenated solvents to which the
promulgated regulations would apply.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before August 25,1980.
Public Hearing. The public hearing
will be held on July 24,1980, beginning
at 9:00 a.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony should
contact EPA by July 17,1980.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. OAQPS-78-12.
Public Hearing, The public hearing
will be held at Research Triangle Park,
North Carolina, in the EPA
Environmental Research Center
auditorium (Room B-102). Persons
wishing to present oral testimony should
notify Deanna Tilley, Standards
Development Branch (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711. telephone number: (919) 541-5421.
Background Information Document.
The Background Information Document
(BID) for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number (919)
541-2777. Please refer to Organic
Solvent Cleaners—Background
Information for Proposed Standards
(EPA-450/2-78-045a).
Docket. Docket number OAQPS-78-
12, containing supporting information
used by EPA in development of the
proposed standards, is available for
public inspection between 8:00 a.m. and
4:00 p.m., Monday through Friday, at
EPA's Central Docket Section, Room
2903B, Waterside Mall, 401 M Street,
S.W., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. John D. Crenshaw, Standards
Development Branch, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5421.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards would limit
the emissions of organic solvents from
new, modified, and reconstructed
degreasers in which solvents are used to
clean and degrease metal, plastic,
fiberglass, or any other type of material.
Three types of degreasers would be
regulated: cold cleaners, open top vapor
degreasers, and conveyorized
degreasers. The proposed regulations
consist of a combination of design,
equipment, work practice, and
operational standards that allow for the
best emission control and enforceability.
Each type of degreaser would be
required to have specific features for
effectively reducing emissions. Pollution
control devices for degreasers would
include covers, raised freeboards,
refrigerated freeboard devices and
carbon adsorption systems. Work
practices and operational procedures
would also be required for each type of
degreaser. These practices and
proceduies would assure the maximum
effectiveness of a specific piece of
control equipment, and would require
use of techniques that reduce solvent
emissions.
An inspection and maintenance
program would also be required to
prevent and correct solvent losses from
leaks and equipment malfunctions. An
operator training program is a proposed
requirement because proper equipment
operation and work practices play a
significant role in effective control of
solvent emissions from degreasers.
Finally, owners and operators would be
required to keep records on the amount
and type of solvent purchased for a
period of two years.
Summary of Environmental, Economic,
and Energy Impacts
Environmental Impact. The proposed
standards would reduce emissions of
organic solvents (i.e., volatile organic
compounds, trichloroethylene, 1,1,1-
trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane) from all
degreasing units for which construction
was commenced after (date of proposal).
Affected facilities that come on-line
between 1980 and 1985 would emit an
estimated 332,000 megagrams (366,000
tons) of organic solvents in 1985, if the
degreaser units are uncontrolled. With
implementation of the proposed
regulations, controlled emissions from
these facilities would be 120,000
megagrams (132,000 tons) in 1985, which
constitutes a reduction of 64 percent.
The only potentially adverse impact
on water quality of the proposed
regulation would derive from the solvent
dissolved in the steam condensate from
regeneration (solvent desorption) of
carbon adsorbers. Because the solubility
of solvent in the condensate is very
small, the amount of dissolved solvent is
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slightly greater than one-tenth of one
percent (0.1%) of the amount which
would be discharged into the air if the
proposed controls were not
implemented. In a typical system, the
carbon adsorber has a solvent capacity
of 95 kilograms (210 pounds), and
requires 3 kilograms (6.6 pounds) of
steam to desorb each kilogram of
solvent. Although desorption generates
approximately 283 liters (10 cubic feet)
of steam condensate per cycle, most
solvent would be recovered by a water
separator. Only 74 grams (0.16 pound) of
solvent per day is expected to be lost in
the waste stream from a typical carbon
adsorber. The environmental impact of
the disposal of this small amount of
condensate is insignificant. Alternatives
are under consideration by EPA for
controlling the solvent in the effluent
from desorption of a carbon adsorber.
EPA may establish regulations
pertaining to these effluents in the
future.
The only solid waste impact due to
implementation of the proposed
standards would be disposal of the
spent carbon from the carbon adsorbers
used as air pollution control devices on
certain types of degreasers. With
replacement of spent carbon every 10
years, disposal of spent carbon from
carbon adsorbers on affected facilities
would amount to 243 megagrams (268
tons) nationwide starting in 1989 and
would increase to 271 megagrams (299
tons) in 1995. Therefore, the solid waste
impact from spent carbon would be
minimal.
Economic Impact. The costs of
compliance with the proposed standards
are based on control equipment
currently in use and commercially
available. Economic analysis indicates
that, under most conditions, the capital
and annualized costs for the control
equipment can be fully recovered by
credits for the recovered solvent.
Consequently, no adverse economic
impact is anticipated to result from
implementation of the proposed
standards. The economic impact, may,
in fact, be positive in the sense that net
credits lead to lower production costs in
most, if not all, industries. Methods to
reduce solvent consumption and save
money generally have not been
accomplished in the past since
degreasing costs generally average less
than four-tenths of one percent of
industry output.
Energy Impact. Energy consuming
emission control devices for degreasing
operations would include (1)
refreigerated freeboard devices, (2)
carbon adsorption systems, and (3)
distillation equipment. Operation of
these control devices in 1985 is
estimated to require about 0.27 million
kWh per day (equivalent to 440 barrels
of oil per day); however, the proposed
standards would result in the prevention
or capture of degreaser emissions. Based
upon the amount of energy that would
have been required to manufacture
replacement solvent, use of the required
control devices on new organic solvent
cleaners would conserve an estimated
3800 barrels of oil per day. Thus, the
proposed standards in 1985 would result
in a net conservation of energy
equivalent to an estimated 3350 barrels
of oil per day.
Rationale—Selection of Source for
Control
Organic solvent cleaners (degreasers)
have been identified as significant
sources of air pollutant emissions which
cause or contribute to the endangerment
of the public health or welfare.
Degreasing is not an industry but is an
integral part of many manufacturing,
repair, and maintenance operations.
Volatile organic compounds, as well as
1,1,1-trichloroethane,
trichlorotrifluoroethane, methylene
chloride, trichlorethylene, and
perchloroethylene constitute the
emissions from organic solvent cleaners.
There were an estimated 725,000
megagrams (800,000 tons) of organic
solvents emitted from organic solvent
cleaning operations in 1975. This
represents about 4 percent of the total
national volatile organic emissions from
stationary sources, making organic
solvent cleaners the fifth largest
stationary source category for organic
emissions. There are over 1,500,000
organic solvent cleaners currently in
operation. If the current growth rate of
4.1 percent per year continues as
expected, over 300,000 new organic
solvent cleaners would be subject to
these standards of performance by 1985.
Degreasing emissions include losses
due to evaporation from the solvent
bath, convection, carryout, leaks, and
waste solvent disposal. Thus, the
emissions from a degreaser are fugitive
in nature. Many of the degreasers
currently in use are operated without
proper control emissions to the
atmosphere. Emissions from degreasers
may be controlled by the use of various
equipment options (including a cover,
extended freeboard, refrigerated
freeboard device, and carbon adsorber)
and specific work practices (involving
parts handling, proper use and
maintenance of equipment, preventing
drafts, and controlling the rate of the
degreasing operation).
Based on the large number of sources
and their wide geographic distribution
across the United States, the current
sales and projected growth rate in the
"industry" and the possible reduction in
adverse environmental and health
impacts which can be achieved, organic
solvent cleaners have been selected for
control through the development of
standards of performance.
Selection of Affected Facilities
Organic solvent cleaning is not a
specific industry but is an integral part
of many manufacturing, repair, and
maintenance operations. Practically
every business that works metal or has
maintenance or repair operations does
some type of degreasing. Degreasing
operations are often concentrated in
urban areas where there are a large
number of manufacturing facilities.
The solvents used in degreasing
operations include halogenated
hydrocarbons, petroleum distillates,
ketones, ethers, and alcohols. These
solvents are emitted as fugitive
emissions from each of the three types
of degreasers which would be regulated:
(1) a cold cleaner, in which the article to
be cleaned is immersed, sprayed or
otherwise washed in a solvent at or
about room temperature; (2) an open top
vapor degreaser, in which the article is
suspended in solvent vapor over a pool
of boiling solvent and the solvent vapors
condense on the article and dissolve or
wash soil and grease from it; and (3) a
conveyorized degreaser, in which
articles are conveyed on a chain, belt or
other conveying system either through a'
spray or pool of cold solvent, or through
the vapor of a boiling solvent. In order
to achieve significant reduction in
volatile organic compound emissions
from degreasing operations, all types of
new, modified, or reconstructed
degreasers would subject to control.
The mode of disposal of waste solvent
can also contribute significantly to
solvent emissions. In the past, disposal
has generally been handled by the
owners of organic solvent cleaners. If
waste solvent disposal in 1985 were to
follow the pattern of waste solvent
disposal in 1974, about 43 percent of the
waste solvent from new sources would
be reclaimed, incinerated, landfilled and
the remaining 57 percent could be an
immediate source of air or water
emissions.
A number of alternatives for
regulating waste disposal have been
considered. These include requiring
incineration or reclamation, and
establishment of standards under the
Resource Conservation and Recovery
Act (RCRA). Because of the impact on
these small sources of requiring
reclamation or incineration, regulation
here is not now planned. Rather, the
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Administrator is deferring at this time
on waste disposal requirements and is
pursuing this matter under RCRA. The
section on waste disposal is being
reserved, however, pending completion
of the evaluation and resolution of the
issues.
Selection of Pollutants and Regulatory
Approach
Among the solvents used in
degreasing operations, approximately 40
percent are non-halogenated
hydrocarbons and 60 percent are
halogenated hydrocarbons. Most of
these solvents are also reactive volatile
organic compounds (VOC), defined by
this proposal as organic compounds
which participate in atmospheric
photochemical reactions or which may
be measured by the applicable reference
method specified under any subpart of
40 CFR Part 60. The proposed standards
of performance apply to reactive VOC
(ozone precursors) used as cleaning
solvents and to five halogenated
compounds for which there is a
reasonable anticipation of public health
endangerment.
Reactive Volatile Organic Compounds
(VOC).
The proposed standards require
control of any VOC demonstrated to be
precursors to the formation of ozone and
other photochemical oxidants in the
atmosphere. While not all compounds
are equally reactive, analysis of
available data indicates that very few
VOC are of such low photochemical
reactivity that they can be ignored in
oxidant control programs. EPA's
"Recommended Policy on Control of
Volatile Organic Compounds" (42 FR
35314; July 8,1977) affirmed that many
compounds which produced negligible
oxidant concentrations during initial
smog chamber tests were found to
contribute appreciably to ozone levels
when exposed to multiday irradiations
in urban atmospheres. In those
geographical areas where industrial and
automotive emissions are subjected to
long hours of sunlight, or where air
stagnation occurs frequently, such low
reactivity compounds may become
significant source of photochemical
oxidant.
EPA is developing standards of
performance under section lll(b) for a
number of categories of sources which
emit these volatile organic compounds,
which are ozone precursors. Ozone air
pollution endangers the public health
and welfare, as reflected in the
Administrator's promulgation of a
National Ambient Air Quality Standard
for ozone (44 FR 8202; February 8,1979).
Emissions of ozone precursors from
these source categories cause or
contribute significantly to ozone air
pollution. Trichloroethylene and, to a
lesser extent, perchloroethylene react to
form ozone and therefore would be
subject to new source performance
standards for reactive VOC.
The Administrator is also concerned
about certain other possible health
effects of perchloroethylene and
trichloroethylene, apart from their role
in ozone formation, and he believes that
regulation of existing emission sources
is necessary. Both substances have been
found to induce a high incidence of
hepatocellular carcinomas (liver tumors)
in mice and have shown positive results
in bacterial mutagencity assays (a
screening technique for potential
carcinogens). The Agency's initial
evaluation of this information is that it
presents "substantial evidence" (41 FR
21402; May 25,1976) that both
substances are human carcinogens.
Consistent with EPA's proposed rules
for regulating airborne carcinogens (44
FR 58642; October 10,1979), if these
initial evaluations are sustained after
consideration of comments by EPA's
Science Advisory Board, it is likely that
perchloroethylene and trichloroethylene
will be classified as high-probability
carcinogens and, in light of the
significant emissions of each, regulated
as hazardous air pollutants under
section 112 of the Act. This regulation
would include both new and existing
emission sources.
It is also possible that the
Administrator will ultimately conclude
that one or both of these chemicals is a
moderate-probability carcinogen rather
than a high-probability carcinogen. As
the proposed airborne carcinogen rules
explain, under the circumstances
presented here, EPA could then
"designate" the substance for regulation
of existing organic solvent cleaners by
the States under section lll(d) of the
Clean Air Act. The Act provides for the
designation of such substances for
regulation under section lll(d) if the
substances themselves have not been
listed previously under section 108 or
section 112. Because the evidence is
clearly sufficient for the Administrator
to conclude that both substances are at
least moderate-probability carcinogens
and that their emission by organic
solvent cleaners causes air pollution
which endangers public health and
welfare, he is proposing designation of
these two substances under section
lll(d) at this time. Although a final
determination by the Agency of the
evidence of carcinogenicity would
normally precede the selection of a
regulatory alternative, the Administrator
is proposing designation of
perchloroethylene and trichloroethylene
today for two reasons. First, this will put
existing sources within the industry on
notice that perchloroethylene and
trichloroethylene would not be
unregulated substitutes for the other
three solvents for which designation is
proposed today. Second, in the event
that the Administrator ultimately
concludes that perchloroethylene and
trichloroethylene are moderate-
probability rather than high-probability
carcinogens, it will enable the section
lll(d) process to proceed without delay
as part of a coordinated regulatory
program for the organic solvent cleaning
industrj. The Administrator intends to
make a final carcinogenicity assessment
for these two chemicals before
promulgating today's proposals.
Negligibly Reactive Halogenated
Compounds.
In addition to reactive halogenated
compounds, the proposed new source
regulations would apply to three
additional halogenated solvents: 1,1,1-
trichlorethane, methylene chloride, and
trichlorotrifluoroethane. Since these
chemicals are acknowledged by EPA to
be negligibly reactive, they are not
ozone precursors and must be
designated under section lll(d) of the
Act. As described above, the
designation for the purpose of obtaining
coverage under new source standards
also requires the development under
section lll(d) of standards for existing
sources.
Both raethylene chloride and 1,1,1-
trichlorethane have scored positive as
well as negative results in short-term
mutagenicity and cell transformation
tests. The weight of evidence has led the
EPA Carcinogen Assessing Assessment
Group to conclude in preliminary
assessments that both chemicals exhibit
suggestive evidence of human
carcinogenicity. Under EPA's proposed
airborne carcinogen policy, this finding
would establish 1,1,1-trichlorethane and
methylene chloride as candidates for
regulation under section 111 as air
pollutants "reasonably anticipated to
endanger public: health or welfare." In
addition, trichlorotrifluoroethane and
1,1,1-trichlorethane have been
implicated in the depletion of the
stratospheric ozone layer, a region of the
upper atmosphere which shields the
earth from harmful wavelengths of
ultraviolet radiation that increase skin
cancer risks in humans.
The judgments of whether and to
what extent 1,1,1-trichlorethane and
methylene chloride are human
carcinogens, and 1,1,1-trichlorethane
and trichlorotrifluoroethane deplete the
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ozone layer, are issues of considerable
debate. While the scientific literature
has been previously reviewed and
summarized in the docket prepared for
this rulemaking, more detailed health
assessments are currently in preparation
by EPA's Office of Research and
Development. These assessments will
be completed and submitted for external
review, including review by the Science
Advisory Board, prior to the
piomalgation of the regulations and the
proposal of EPA guidance to States in
developing existing source control
measures. The extent to which the
preliminary findings are affirmed by the
review process may affect the final
rulemaking for new as well as existing
sources.
While the measure of concern is less
for these latter three solvents than for
perchloroethylene and trichloroethylene,
the Administrator has chosen to proceed
with the designation of 1,1,1-
trichlorethane, methylene chloride, the
trichlorotrifluoroethane at this time
because emissions from these sources
and the associated health risks can be
reduced at a very low cost. This
decision reflects EPA's concern that
continued growth in uncontrolled
emissions of 1,1,1-trichlorethane,
methylene chloride, and
trichlorotrifluoroethane from solvent
cleaners may endanger public health,
and is reinforced by projections that,
were these chemicals exempted from
regulation, the resulting substitution of
exempt for non-exempt solvents could
result in large increases in the emissions
of these pollutants.
The designation of 1,1,1-
trichlorethane, methylene chloride, and
trichlorotrifluoroethane incorporates
these chemicals under today's proposed
new source standards and invokes
section lll(d) which requires States to
develop controls for existing sources. As
described in detail below, the new
source standards do not place
unreasonable economic costs on the
industry. While the impact of similar
controls on existing sources could be
more significant due to the technological
problems associated with retrofit, this
factor would be an important
consideration in determining the
appropriate control level for existing
sources. In view of the substantial
reduction in emissions which can be
achieved at low cost, and the potential
for substitution between these five
compounds, the Administrator is
persuaded that the present approach
represents a prudent policy to protect
public health. It should be emphasized
that the health assessments discussed
here are not final. The Administrator is
aware of other relevant information that
may become available. All applicable
information will be carefully evaluated
prior to making the final regulatory
decision.
Summaries of the health basis for
designating perchloroethylene,
trichloroethylene, 1,1,1-trichloroethane,
methylene chloride, and
trichlorotrifluorethane are available in
the public rulemaking docket described
at the beginning of this notice.
Selection of Format for the Proposed
Standards
Under the Clean Air Act, as amended,
there are two regulatory alternatives
available for establishing standards of
performance for new stationary sources.
Section lll(b) provides for establishing
emission limitations or percentage
reductions in emissions. However, when
such standards are not feasible to
prescribe or enforce, section lll(h) of
the Clean Air Act provides that EPA
may instead promulgate a design,
equipment, work practice, or operational
standard, or combination thereof. In
either event, the standards prescribed
would require new, modified, and
reconstructed organic solvent cleaners
to use the best demonstrated system of
continuous emission reduction
considering costs, nonair quality health
and environmental impacts, and energy
impacts. The emissions from organic
solvent cleaners are unconfined
(fugitive). Although techniques have
been developed to measure the solvent
lost from degreasing equipment (such as
mounting entire organic solvent cleaners
on scales), these methods are
impractical for enforcement of
regulations due to the length of time
needed to accurately determine the
solvent losses and because of the
disruption this would cause in degreaser
operations. For this reason, an
equipment and work practice standard
has been selected since it is not feasible
to enforce emission limitations or
percentage reductions in emissions for
organic solvent cleaning operations.
Selection of the Best System of Emission
Reduction
Emissions of volatile organic
compounds from degreasers would be
reduced significantly by the use of
various pollution control devices, singly
or in combination, as would \>e
appropriate for each method of
degreasing. These controls would
include: cover, drain rack, raised
freeboard, refrigerated freeboard device,
downtime port covers, hanging flaps,
and drying tunnel or lip exhaust in
conjunction with a carbon adsorber.
Degreaser emissions would be reduced
further through the implementation of
prescribed work practices. These work
practices would include: closing the
cover when work is not being lowered
into or removed from the degreaser,
storing solvent in covered containers,
not exposing open degreasers to steady
drafts with velocities exceeding 40m/
min (131 ft/min), and not overloading
the degreaser.
The best system of emission'control
for each type of degreaser was selected
on the basis of EPA tests of the
effectiveness of various controls used on
degreasers operating under different
conditions and using different solvents.
These are described as follows:
Cold Cleaners.—The emission control
system selected for cold cleaners (CC)
would consist of both control equipment
and a series of work practices. These
controls used in combination would
reduce solvent emissions from cold
cleaners by about 80 percent. The
equipment requirements would include a
cover, a drain rack, and a visible fill
line. The cover would be designed to be
readily opened and closed at any time.
External drain racks would lead the
drainage back to the tank. If the CC is
equipped with a parts basket, internal
hooks to permit suspension of the
basket above the solvent could be
substituted for the drain rack. One of the
work practices would require that the
solvent level not exceed the visible
internal maximum fill line. The proposed
standards would require that the
freeboard ratio for CC would be at least
0.7 if the solvent vapor pressure is
greater than 4.3 kPa (33 mm Hg or 0.6
psi) measured at 38° C (100' F). The
purpose for this is to prevent excessive
volatilization, i.e. vaporization. Higher
freeboard ratios impede excess
vaporization of highly volatile solvents
under normal operating conditions.
However, many solvents used in cold
cleaning operations do not volatilize as
rapidly as others. For solvents with a
vapor pressure of less than or equal to
4.3 kPa measured at 38° C (100° F), the
proposed standards would require a
freeboard ratio of 0.5.
The economic analysis for this
emission control system for cold
cleaners was based on a typical unit.
The uncontrolled cold cleaner was
assumed to be uncovered all the time,
whereas the controlled unit had a cover
that was used all but 2 hours per
working day (20 loads cleaned per day).
Based on these assumptions, the cover
would reduce emissions by 349
kilograms (769 pounds) per year at a
savings of $69.80. The drain rack would
reduce emissions by 36 kilograms (79
pounds) per year with a savings of $7.92.
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Remote Reservoir Cold Cleaner.—The
emission control system selected for
remote reservoir cold cleaners (RRCC) is
less stringent than that proposed for
conventional cold cleaners. During non-
use periods, the solvent is enclosed in a
reservoir and not subject to evaporation
loss to the atmosphere. While parts are
being cleaned, solvent is pumpted
through a sink-like work area which
drains back-into the enclosed contaier.
Because the reservoir is remote from the
work area, this type of organic solvent
cleaner is not subject to the evaporation
losses suffered by conventional cold
cleaners. Therefore, the proposed
standards for remote reservoir cold
cleaners would not require closable
covers, provided the solvent used has a
vapor pressure of less than or equal to
4.3 kPa (33 mm Hg or 0.6 psi) measured
at 38° C (100° F), but would require
covers if the solvent volatility was
greater than 4.3 kPa.
Open Top Vapor Degreaser,—The
emission control systems would be
required for all new, modified, or
reconstructed open top vapor degreasers
(OTVD) consists of covers, raised
freebacks, and refrigerated freeboard
devices or carbon adsorption systems.
EPA and industry tests have shown that
covers are the most effective control
device in reducing solvent emissions
during nonoperating conditions. Raised
freeboards have also been show to be
effective at reducing these emissions. By
raising the freeboard ratio from 0.5 to
0.75, solvent emissions are generally
reduced 25-30 percent during idling
conditions. Emission reductions are less
during actual operating conditions due
to the transference of loads through
vapor/air interface. Freeboard ratios
larger than 0.75 may yield greater
emission reductions, however, higher
freeboards tend to icrease the difficulty
of transferring loads into and out of the
degreaser. The demonstrated ability of
covers and raised freeboards to reduce
•olvent emissions, and the minimal cost
of these two control devices have been
the primary reasons for requiring the use
of covers during nonoperating periods
and freeboards ratios of at least 0.75 for
all new, modified, and reconstructed
open top vapor degreasers.
Emission tests have also shown that
refrigerated freeboard devices and lip
exhausts connected to carbon adsorbers
are more effective at reducing solvent
emissions than raised freeboards.
During operating conditions, emission
reductions as high as 65 percent have
been demonstrated with the use of
carbon adsorbers, while refrigerated
freeboard devices have been
demonstrated to reduce solvent
emissions by at least 40 percent. A
raised freeboard ratio of 1.0 has also
shown promise (55 percent reduction),
but its effectiveness under cross-draft
conditions has not been adequately
evaluated. It is expected that the cold
air blanket produced by a refrigerated
freeboard device would provide greater
control of cross-draft induced vapor
losses. For these reasons, all new,
modified, and reconstructed OTVD with
vapor/air interface areas greater than
one square meter would be required to
use refrigerated freeboard devices, or
have lip exhausts connected to carbon
adsorbers.
Reference Method 23, "Determination
of Halogenated Organics from
Stationary Sources," would be the
required test method to measure
emissions of the regulated halogenated
compounds from carbon adsorbers. The
principle of the method is an integrated
bag sample of stack gas that is subjected
to gas chromatographic analysis, using
flame ionization detection. The range of
this method is 0.1 to 200 ppm. The
emission limitation proposed by these
standards of performance would be 25
ppm of any regulated halogenated
organic compound measured over the
length of the carbon adsorber cycle, or
for three hours, whichever is less. The
Administrator specifically requests
comments on this proposed test method
and emission limitation.
A cut-off size of one square meter was
determined to be the most effective for
OTVD, taking into consideration the
absolute reduction in solvent emissions
and economic analyses. Although the
capital expenditures for refrigerated
freeboard devices are greater than for
raised freeboards, solvent savings
would completely offset the added
capital expenditures, provided the
degreasers were operated properly.
However, for small OTVD (less than 1
m2in open top area), refrigerated
freeboard devices would not be a cost-
effective alternative. Taking into
consideration the small reduction in
solvent emissions and economics, small
open top vapor degreasers would not be
required to have refrigerated freeboard
devices.
EPA realizes that refrigerated
freeboard devices with sub-zero (0°C)
refrigerant temperatures are patented. If
any degreaser manufacturer is unable to
demonstrate alternative methods of
control, and certifies that the licensing
terms for sub-zero refrigerated
freeboard devices are unreasonable,
relief under section 308 of the Clean Air
Act, as amended can be sought.
Although the proposed standards
require specific control technologies,
they do not preclude the use of other
control options which are demonstrated
to be equally effective in reducing
solvent emissions. After proposal of
these regulations, any person may
request an equivalency determination.
EPA expects to approve other methods
of continuous emission reduction when
they have been demonstrated to be as
effective in reducing emissions as
refrigerated freeboard devices. The
Administrator will also welcome any
additional data and information
concerning the control efficiencies of
raised freeboards and refrigerated
freeboard devices. Tests are currently
being conducted to investigate the
effectiveness of refrigerated freeboard
devices and increased freeboard ratios
under cross-draft conditions.
Preliminary results of these tests have
shown varying test results for different
solvents. Because of possible variation
in test outcomes, additional tests are
planned. Tests are also being conducted
to evaluate the effectiveness of
automated covers which close after the
workload enters the degreaser. These
test results and any additional
information and data submitted to EPA
during the public comment period will
be used to further evaluate the
appropriateness of the proposed
emission control options. Expansion or
deletion of these options will be
evaluated prior to promulgation. All
information obtained during the course
of this investigation and received during
the public comment period would be
placed in the docket for public review
and considered by EPA before taking
final action to promulgate standards for
new, modified, and reconstructed
degreasers.
Conveyorized Degreasers.—There are
two major types of conveyorized
degreasers: conveyorized vapor
degreaser (CVD) and conveyorized cold
cleaners (CCC). Conveyorized vapor
degreasers use the vapors of boiling
solvent to clean and degrease surfaces,
while conveyorized cold cleaners use
non-boiling solvent in the liquid phase
to clean surfaces. The emission control
system selected for conveyorized
degreasers consists of both control
equipment and a series of work
practices. Using these controls in
combination will reduce solvent
emissions from conveyorized degreasers
by 60 percent.
The two major emission control
requirements for CVD are carbon
adsorbers or refrigerated freeboard
devices, provided the CVD is greater
than 2 square.meters (21.6 ft2) in vapor/
air interface area. This cutoff size was
determined to be the most effective,
taking into consideration the absolute
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reduction in solvent emission and
economic analyses. For larger crossrod
and monorail CVD, carbon adsorbers
produce greater emission reductions at
higher savings than do refrigerated
freeboard devices. For owners or
operators of small crossrod and
monorail degreasers, the capital costs of
a carbon adsorber could be prohibitive.
Because of this, a refrigerated freeboard
device may be used instead of a carbon
adsorber. As with OTVD, the type of
conveyorized vapor degreaser, the type
of work being processed, and ambient
conditions would determine which
emission control system should be used.
For conveyorized cold cleaners, the
major emission control requirement
would be a carbon adsorber, provided
the CCC is greater than 2 square meters
(21.6 ft2) in solvent/air interface area.
Like CVD, this cutoff was determined to
be the most effective, taking into
consideration the absolute reduction in
solvent emissions and economic
analyses. Refrigerated freeboard devices
would not be an option for CCC since
they are only effective in reducing
emissions of warm solvent vapors.
Equivalent Systems of Emission
Reduction
These standards of performance do
not preclude the use of other degreaser
emission control equipment or
procedures of operation which can be
demonstrated to be equivalent, in terms
of reducing solvent emissions, to those
prescribed in the proposed regulation.
For determination of equivalency, any
person may write the Administrator of
EPA and request approval of a test plan
for demonstrating equivalency. The test
plan must propose the use of specific
equipment, test procedures, a date, and
a U.S. location at which the person
making the request wishes to
demonstrate equivalency. In order to
determine equivalency, the
Administrator must find a substantial
likelihood that the control technology
used in normal operations would
produce equivalent emission reductions
as the standards would require, at
approximately the same or less
economic, energy, or environmental
cost. An alternate equipment design
would not be considered equivalent to
the proposed requirements if it placed a
greater burden upon the personnel
operating the degreaser to manually
operate the emission capture device
(e.g., use of an automated cover could
potentially be found equivalent to use of
refrigerated freeboard devices, but a
manually operated cover would not
qualify). Automated operation of the
emission control system is required
because manual operation would be
burdensome due to the frequency with
which work enters and exits open top
vapor degreasers (cycle times of only 8
minutes are not unusual) and because
enforcement of these standards would
primarily depend upon equipment
certifications. Although work practices
could not be substituted for equipment
design requirements, alternatives to the
work practices contained in the
proposed standards could also be
included in an equivalency
determination.
Selection of Enforcement Methods
More than 325,000 new degreasers are
expected to be in operation by 1985. The
large number of degreasers precludes
the inspection of all units on a periodic
basis. Therefore, enforcement must be
achieved through a combination of
degreaser manufacturer certifications
and EPA random inspections. Because
EPA cannot inspect all degreasers that
will be in operation, adherence to the
work practices will basically depend
upon voluntary compliance. Although
the work practices are important, the
equipment design requirements will be
the primary mechanism for ensuring the
control of organic solvent emissions
from degreasing operations. A random
inspection program would be designed
to inspect all degreaser design types
produced, but would cover only a
sample of shops using degreasing
equipment. To facilitate this program,
the primary reporting burden would be
place upon the manufacturers of
degreasing equipment
Under section lll(a)(5) of the Clean
Air Act, as amended, manufacturers of
degreasers would be considered owners
until the degreasers are sold. Thus, the
original manufacturer of a newly
constructed degreaser would be
responsible for making the proposed
reports. Section 114(a)(l) of die Act
specifies that the Administrator can
require owners or operators to report
information to EPA as may be
reasonably required. Manufacturers of
cold cleaners, remote reservoir cold
cleaners, open top vapor degreasers,
and conveyorized degreasers would be
required to notify the Administrator of
the date construction began on a new
degreaser, certain equipment features,
and the name, date and location to
whom the ownership of the degreaser
was transferred. This information would
be reported once for each degreaser
constructed, modified, or reconstructed
and the reports would be submitted
each quarter. If any manufacturer or
other owner or operator feels that the
information to be submitted is
proprietary in nature, a request for
confidential treatment can be submitted
with the report. On September 1,1976,
EPA promulgated regulations (40 CFR
part 2) which govern the treatment of
confidential business information,
including that obtained under section
114 of the Clean Air Act.
Under certain circumstances, the
operator of the degreaser rather than the
original manufacturer would be
responsible for making the report. This
would occur when a modification or
reconstruction to an existing degreaser
was made by any person other than the
original manufacturer or when any
affected degreaser is resold.
Certification would be supplemented
by an EPA inspection program of
representative types of models of
degreasers from owners and operators
selected at random. This program would
determine compliance with the design
requirements for all new degreasing
equipment, and would determine
compliance with the work practice and
operational requirements by a random
sample of degreasing operations.
Inspection would include a visual check
of the operation and an examination of
the methods of waste solvent disposal.
This method of enforcement has been
selected as the best option considering
the savings in time and money for
effective enforcement. As mentioned
previously, the large number of new
sources expected within the next five
years prohibits inspection of each unit
Effort has been made to reduce the
proposed reporting and recordkeeping
burdens to the minimum needed to
administer an effective enforcement
program. EPA also considered requiring
each degreaser operator to report
directly to EPA upon installation of a
new degreaser and to periodically report
work practice methods in use. However,
the reporting requirements would have
caused an excessive burden to be
placed on each degreaser operator and
would have caused the generation of a
large number of reports. For these
reasons, the proposed reporting
requirements are minimized to include a
one-time report per degreaser of a few
basic items. In addition, spot checks of
representative types and models of
degreasers in operation were selected as
the best available option. Operators of
degreasing equipment would only be
required to keep records of solvent
usage and disposition and would not be
required to make written reports. These
records can be discarded after a two
year period. To further reduce the
impact of these requirements, operators
of small cold cleaners (less than 1 m2),
such as are commonly used in gasoline
service stations, would be exempt from
any recordkeeping or reporting except
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for maintaining a simple record of the
disposition of waste solvent.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
Section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Central Docket
Section (A-130), U.S. Environmental
Protection Agency, 401 M Street, SW.,
Washington, D.C. 20460, Attention:
Docket No. OAQPS-78-12.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section, Room 2903B, Waterside
Mall, 401 M Street, SW., Washington,
D.C. 20460.
Docket
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
EPA in the development of this proposed
rulemaking. The principal purposes of
the docket are: (1) to allow interested
parties to readily identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record in case of judicial review
(section 307(d)(7)].
Miscellaneous
As prescribed by section 111 of the
Clean Air Act, as amended,
establishment of standards of
performance for organic solvent
cleaners was preceded by the
Administrator's determination (40 CFR
60.16, 44 FR 49222, dated August 21.
1979) that these sources contribute
significantly to air pollution which may
reasonably be anticipated to endanger
public health or welfare. In accordance
with section 117 of the Act, publication
of this proposal was preceded by
consultation with appropriate advisory
committees, independent experts, and
Federal departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation, including economic and
technological issues on the proposed
test methods.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Aqt reflect:
... application of the best technological
system of contunuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated [section lll(a)(l)].
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas,
i.e., those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the National
Ambient Air Quality Standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3) for such category of
source. The statute defines LAER as that
rate of emissions based on the
following, whichever is more stringent:
(A) 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
(B) the most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act. Best available
control technology must be determined
on a case-by-case basis, taking energy,
environmental and economic impacts
and other costs into account. In no event
may the application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose SIP's must in some cases
require greater emission reduction than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than standards of performance under
section 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
In order to prevent duplicative
regulatory reuirements, and in order to
avoid conflicts in standard setting, EPA
has been in contact with representatives
of the Interagency Regulatory Liaison
Group (1RLG). This group, composed of
members from EPA, the Occupational
Safety and Health Administration
(OSHA), the Food and Drug
Administration (FDA), and the
Consumer Product Safety Commission
(CPSC) was formed in August, 1977, to
ensure that the agencies work closely
together in areas of common interest
and responsibility. In particular, EPA
has been in contact with OSHA to
ensure that the requirements for the
proposed standard do not conflict with
OSHA's requirements for ventilation of
open surface tank operations (29 CFR
1910.94).
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless EPA takes affirmative action to
extend them. To accomplish this, a
provision automatically terminating the
reporting requirements at that time will
be included in the text of the final
regulations.
EPA will review this regulation four
years from the date of promulgation as
required by the Clean Air Act. This
review will include an assessment of
such factors as the need for integration
with other programs, the existence of
alternative methods, enforceability, and
improvements in emission control
technology.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
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economic impact assessment for any
new source standard of performance
promulgated under section lll(b) of the
Act. An economic impact assessment
was prepared for the proposed
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the proposed standards
to insure that the proposed standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the Background Information
Document.
Dated: April 17,198D.
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
1. By adding alphabetically a
definition of the term "volatile organic
compound" to § 60.2 of Subpart A—
General Provisions as follows:
§ 60.2 Definitions
*****
"Volatile organic compound" means
any organic compound which
participates in atmospheric
photochemical reactions or is measured
by the applicable reference methods
specified under any subpart.
2. By adding Subpart JJ as follows:
Subpart JJ—Standards of Performance for
Organic Solvent Cleaners
Sec.
60.360 Application and designation of
affected facility.
60.361 Definitions.
60.362 Standards for volatile organic
compounds, trichloroethylene, 1,1,1-
trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane.
60.363 Equivalent method of control.
60.364 Reporting and Recordkeeping.
60.365 Waste disposal, (reserved).
60.366 Test method.
Authority: Sec. Ill, 301(a) of the Clean Air
Act as amended [42 U.S.C. 7411, 7601(a)], and
additional authority as noted below.
Subpart JJ—Standards of
Performance for Organic Solvent
Cleaners
§ 60.360 Applicability and designation of
affected facility.
The provisions of this subpart are
applicable to all organic solvent
cleaners for which construction was
commenced after (date of proposal)
which are used for organic solvent
cleaning (degreasing) of any materials.
§ 60.361 Definitions.
All terms used in this subpart, but not
specifically defined in this Section shall
have the meaning given them in the Act
and in Subpart A of this part.
"Adsorption cycle" means a solvent
recovery process which begins when
solvent laden air is directed through an
activated carbon bed, resulting in the
capture of solvent vapors. An
adsorption cycle shall be considered
complete when the activated carbon bed
becomes saturated with solvent,
resulting in breakthrough of solvent
vapors.
"Carbon adsorber" means a device in
which an organic compound is brought
into contact with activated carbon and
is retained.
"Certification" means a written
statement signed by the owner or
operator of the affected facility.
"Cold cleaner" means any device or
piece of equipment which contains and
uses an organic solvent in the liquid
phase to clean surfaces.
"Conveyorized cold cleaner" means
any conveyorizer degreaser which uses
an organic solvent in the liquid phase to
clean surfaces.
"Conveyorized degreaser" means any
device which uses an integral,
continuous, mechanical system for
moving materials or parts to be cleaned
into and out of an organic solvent liquid
or vapor cleaning zone.
"Conveyorized vapor degreaser"
means any conveyorizer degreaser
which uses an organic solvent in the
vapor phase to clean surfaces.
"Drain rack" means any basket, tray,
or sink located in, on, or exterior to a
degreaser, which permits excess or
condensed solvent to drain from the
parts after degreasing and to return to
the solvent bath.
"Drying tunnel" means an enclosed
extension of the exit from a
Conveyorized degreaser.
"Equivalent method of control" means
any method that can be demonstrated to
the Administrator to provide at least the
same degree of emission control as the
specified control.
"Extended freeboard" means an
addition to the sides of a degreaser to
increase the freeboard height.
"Fill line" means a permanent mark in
a degreaser tank that indicates the
maximum operating liquid level
recommended by the manufacturer.
"Freeboard height" means, for a cold
cleaner, the distance from the liquid
solvent level in the degreaser tank to the
lip of the tank. For an open top vapor
degreaser it is the distance from the
solvent vapor level in the tank during
idling to the lip of the tank. For a
Conveyorized cold cleaner it is the
distance from the liquid solvent level to
the bottom of the entrance or exit
opening, whichever is lower. For a
Conveyorized vapor degreaser, it is the
distance from the vapor level to the
bottom of the entrance or exit opening,
whichever is lower.
"Freeboard ratio" means a ratio of the
freeboard height to the smaller interior
dimension (length, width, or diameter) of
the degreaser.
"Lip exhaust" means a device
installed around the lip of a degreaser
that draws in air and solvent vapor
emissions and ducts them away from
the degreaser area.
"Open top vapor degreaser" means
any open top device or piece of
equipment that contains and uses an
organic solvent, at the boiling point of
the solvent, and solvent vapor to clean
equipment surfaces.
"Organic solvent" means any liquid
substance which contains carbon and
has the power to dissolve, causing
solution.
"Organic solvent cleaner" or
"degreaser" means any cold cleaner,
remote reservoir cold cleaner, open top
vapor degreaser, and Conveyorized
degreaser equipment and their ancillary
components.
"Organic solvent cleaning" or
"degreasing" means those processes
using organic solvents to clean and
remove soils from the surfaces of
materials being processed.
"Refrigerated freeboard device"
means a device which is mounted above
the water jacket and the primary
condenser coils, consisting of secondary
coils which carry a refrigerant to
provide a chilled air blanket above the
solvent vapor to reduce emissions from
the degreaser bath. The chilled air
blanket temperature, measured at the
centroid of the degreaser at the coldest
point, shall be no greater than 30 percent
of the solvent's boiling point (°F).
"Remote reservoir cold cleaner"
means any device in which liquid
solvent is pumped through a sink-like
work area which drains back into an
enclosed container while parts are being
cleaned and in which the solvent in the
enclosed container is not subject to
evaporation losses to the atmosphere
during non-use periods.
§ 60.362 Standards for volatile organic
compounds, trichloroethylene, 1,1,1-
trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane.
(a) Except as provided in paragraph
(d) of this section, an owner or operator
shall operate a cold cleaner, or a remote
reservoir cold cleaner only if it has a
cover that may be readily opened and
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closed. A fusible link shall not interfere
with cover operation.
(b) An owner or operator shall
operate a cold cleaner only if it
conforms to the following design
requirements:
(1) A drain rack. If an external drain
rack is used, it must allow the drained
solvent to return to the solvent bath in
the cold cleaner. If the cold cleaner is
equipped with a parts basket, internal
hooks to permit suspension of the
basket above the solvent may be
substituted for the drain rack.
(2) A freeboard ratio of at least 0.5. If
the solvent used has a volatility greater
than 4.3 kPa (33 mm Hg or 0.8 psi),
measured at 38°C (100°F), the freeboard
ration shall be at least 0.7.
(3) A visible fill line.
(c) Except as provided in paragraph
(d) of this section, an owner or operator
shall not operate a cold cleaner without
meeting the following work and
operational practices:
(1) The solvent level shall not exceed
the fill line.
(2) When a flexible hose or flushing
device is used, the pressure of solvent
delivered by the pump may not exceed
69 kPa (10 psi), measured at the pump
outlet, and the pumped solvent shall be
delivered in a continuous stream and
not a droplet spray. Flushing shall be
performed only within the confines of
the cold cleaner.
(3) When an air- or pump-agitated
solvent bath is used, the agitator shall
be operated so as to produce a rolling
motion of the solvent but not observable
splashing against tank walls or parts
being cleaned.
(4) The cover shall be closed when the
cold cleaner is not in use and when
parts are being cleaned by solvent
agitation.
(5) When the cover is open, the cold
cleaner may not be exposed to drafts
greater than 40 m/min (131 ft/min), as
measured between 1 and 2 meters
upwind and at the same elevation as the
tank lip.
(6) Solvent cleaned parts shall be
drained for 15 seconds or until dripping
has stopped, whichever is longer. Parts
having cavities or blind holes shall be
tipped or rotated while draining.
(7) Waste solvent, still, and sump
bottoms shall be collected and stored in
closed containers. The closed containers
may contain a device that would allow
pressure relief, but would not allow
liquid solvent to drain from the
container prior to disposal.
(8) Each owner shall provide a
permanent label for each cold cleaner
which states the required work and
operating practices. If the freeboard
ratio on a cold cleaner is less than 0.7,
the label shall state the types of solvents
which may be used in the cold cleaner.
Such solvents include xylenes, mineral
spirits, stoddard solvents, or other
solvents with a volatility less than or
equal to 4.3 kPa. The label shall be
placed near the front of the degreaser in
full view of the degreaser operator and
written in English, and any other
language that may be necessary for
comprehension by personnel operating
the degreaser. The label must be kept
visible and legible at all times. The plant
owner or operator shall ensure that each
person who operates a cold cleaner
understands the instructions on the
label.
(9) Spills during solvent transfer shall
be wiped up immediately. The wipe rags
shall be stored in covered containers.
(d)(l) An owner or operator who
operates a remote reservoir cold cleaner
which uses solvent with a volatility of
less than or equal to 4.3 kPa (0.6 psi or
33 mm Hg] measured at 38°C (100'F),
and which has a drain area less than 100
cm2 (15.5 in2) shall be subject to the
provisions of paragraph (c)(2), (c)(5),
(c)(6), (c)(7), (c)(8), and (c)(9).
(2) An owner or operator who
operates a remote reservoir cold cleaner
which uses solvent with a volatility
greater than 4.3 kPa (0.6 psi or 33 mm
Hg) measured at 38° C (100° F), or has a
drain area greater than or equal to 100
cm2 (15.5 in2) shall be subject to the
provisions of paragraphs (d)(l), (c)(4),
and (a).
(e) An owner or operator shall operate
an open top vapor degreaser only if it
conforms to the following design
requirements:
(1) Each open top vapor degreaser
shall be equipped with a cover that may
be readily opened or closed. If the open
top vapor degreaser is equipped with a
lip exhaust, the cover shall be located
below the lip exhaust.
(2) Each open top vapor degreaser
shall have a freeboard ratio of at least
0.75.
(3) Each open top vapor degreaser
shall be equipped with the following
devices:
(i) A device which shuts off sump heat
if sump liquid solvent level drops down
to the height of sump heater coils, and
(ii) A vapor level control device which
shuts off sump heat if the vapor level
rises above the height of the primary
condenser.
(4) Each open top vapor degreaser
greater than 1.0 square meter (10.8 ft2)
shall be equipped with one or more of
the following equipment controls:
(i) A refrigerated freeboard device, or
(ii) A lip exhaust connected to a
carbon adsorber. The concentration of
organic solvent in the exhaust from this
device shall not exceed 25 ppm of any
regulated halogenated organic
compound as measured by Method 23
for the length of the carbon adsorber
cycle or three hours, whichever is less. If
other volatile organic compounds are
used, then the emissions shall not
exceed an average of 25 ppm as carbon,
measured by Method 25 for the length of
the carbon adsorber cycle or three
hours, whichever is less.
(f) An owner or operator shall not
operate an open top vapor degreaser
without meeting the following required
work and operational practices:
(1) The cover shall be closed when
parts are not being degreased.
(2) When the cover is open, the open
top vapor degreaser shall not be
exposed to drafts greater than 40 m/min
(131 ft/min), as measured between 1 and
2 meters upwind and at the same
elevation as the tank lip.
(3) For any open top vapor degreaser
equipped with a lip exhaust, the exhaust
shall be turned off when the degreaser is
covered.
(4) Parts being degreased shall not
occupy more than 50 percent of the
vapor-air interface area.
(5) The vertical speed of a powered
hoist, if one is used, shall not be more
than 3.3 m/min (10.8 ft/min) when
lowering and raising the parts.
(6) Spraying operations shall be done
within the vapor layer.
(7) Work shall not be lifted from the
vapor layer until condensation or
dripping has stopped. Parts having
cavities or blind holes shall be tipped or
rotated before being raised from the
vapor layer.
(8) During start up, the primary
condenser and the refrigerated
freeboard device, if one is used, shall be
turned on before the sump heater.
During shutdown, the sump heater shall
be turned off, and the solvent vapor
layer allowed to collapse before the
condenser water and refrigerated
freeboard device are turned off.
(9) Porous or absorbent material shall
not be degreased in an open top vapor
degreaser.
(10) A routine inspection and
maintenance program shall be
implemented to reduce or prevent
solvent losses from dripping drain taps,
cracked gaskets and malfunctioning
equipment. Leaks must be repaired as
soon as they are discovered.
(11) Waste solvent, still, and sump
bottoms shall be collected and stored in
closed containers. The closed containers
may contain a device that would allow
pressure relief, but would not allow
liquid solvent to drain from the
container prior to disposal.
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(12) Each owner shall provide a
permanent label for each open top vapor
degreaser which states the required
work and operating practices. The label
shall be placed near the front of the
degreaser in full view of the degreaser
operator and written in English, and in
any other language that may be
necessary for comprehension by
personnel operating the degreaser. The
label must be kept visible and legible at
all times. The plant owner or operator
shall ensure that each person who
operates a degreaser understands the
instructions on the label.
(13) When sumps are drained, solvent
shall be transferred using threaded or
other leakproof couplings.
(14) The carbon absorber bed shall
not be bypassed during desorption.
(g) An owner or operator subject to
the provisions of this subpart shall
operate a conveyorized degreaser only if
it conforms to the following design
requirements:
(1) Each conveyorized degreaser shall
have a freeboard ratio of at least 0.75.
(2) Each conveyorized degreaser shall
be equipped with a drying tunnel, a
rotating (tumbling) basked, hanging
flaps, or other device to prevent cleaned
parts from carrying out solvent liquid or
vapor. When a drying tunnel is used, the
air which moves through the tunnel to
enhance drying shall be exhausted to a
carbon adsorber. The concentration of
organic solvent in the exhaust from this
device may not exceed 25 ppm of any
regulated halogenated organic
compound as measured by Method 23
for the length of the carbon adsorber
cycle or three hours, whichever is less. If
other volatile organic compounds are
used, then the emissions shall not
exceed an average of 25 ppm as carbon,
measured by Method 25 for the length of
the carbon adsorber cycle or three
hours, whichever is less.
(3) Each conveyorized degreaser shall
be equipped with downtime port covers
at the entrance and exit openings.
(4) Each conveyorized cold cleaner
with a solvent-air interface area of 2.0m*
(21.6 ftj) or greater shall be equipped
with a carbon adsorber. The
concentration of organic solvent in the
exhaust from this device may not
exceed 25 ppm of any regulated
halogenated organic compound as
measured by Method 23 for the length of
the carbon adsorber cycle or three
hours, whichever is less. If other volatile
organic compounds are used, then the
emissions shall not exceed an average
of 25 ppm as carbon, measured by
Method 25 for the length of the carbon
adsorber cycle or three hours,
whichever is less.
(5) Each conveyorized vapor
degreaser with a solvent-air interface of
2.0m2 (21.6 ft2) or greater shall be
equipped with one or more of the
following equipment controls:
(i) A refrigerated freeboard device, or
(ii) A carbon adsorber. The
concentration of organic solvent in the
exhaust from this device shall not
exceed 25 ppm of any regulated
halogenated organic compound as
measured by Method 23 for the length of
the carbon adsorber cycle or three
hours, whichever is less. If other volatile
organic compounds are used, then the
emissions shall not exceed an average
of 25 ppm as carbon, measured by
Method 25 for the length of the carbon
adsorber cycle or three hours,
whichever is less.
(6) Each conveyorized vapor
degreaser shall be equipped with the
following devices:
(i) A device which shuts off sump heat
if sump liquid level drops down to the
height of sump heater coils, and
(ii) A vapor level control device which
shuts off sump heat if the vapor level
rises above the height of the primary
condenser coils.
(7) Each owner shall provide a
permanent label for each conveyorized
degreaser which states the required
work and operating practices. The label
shall be placed near the front of the
degreaser in full view of the degreaser
operator and written in English and in
any other language that may be
necessary for comprehension by
personnel operating the degreaser. The
label must be kept visible and legible at
all times. The plant owner or operator
shall ensure that each person who
operates a degreaser understands the
instructions on the label.
(8) Waste solvent, still, and sump
bottoms shall be collected and stored in
closed containers. The closed containers
may contain a device that would allow
pressure relief, but would not allow
liquid solvent to drain from the
container prior to disposal.
(9) The carbon adsorber bed shall not
be bypassed during desorption.
§ 60.363 Equivalent methods of control.
Upon written application, the
Administrator may approve the use of
equipment or procedures after they have
been demonstrated to his satisfaction to
be equivalent, in terms of reducing
solvent emissions to the atmosphere, to
those prescribed for compliance within
a specified paragraph of this subpart.
The application must contain a complete
description of the proposed testing
procedure and the date, time, and
location scheduled for the equivalency
demonstration.
§ 60.364 Reporting and recordkeeplng.
(a) The owner or operator of any
degreaser affected by this subpart shall
furnish the Administrator with a single
report for each degreaser. These reports
shall be submitted each quarter for all
degreasers which were newly
constructed, modified, or reconstructed
and which were placed in operation or
for which ownership was transferred in
the previous quarter. Each report shall
contain written notification
(certification) of the following:
(1) Date construction, modification, or
reconstruction of each degreaser was
commenced.
(2) Make and model of degreaser
(including the serial number if
applicable).
(3) Name, date, and location to whom
the ownership of the degreaser was
transferred.
(4) Dimensions of the solvent-air
interface area and the freeboard ratio.
(5) Specify whether a refrigerated
freeboard device or carbon adsorber has
been installed (if applicable) and certify
that the required controls (design
parameters), under section 60.362, are
part of the degreaser for which this
notification is required.
(6) The name, title, and signature of
the individual making the certification.
(b) Each owner or operator of an
affected facility subject to the provisions
of this subpart, except as provided in
paragraph (c) of this section, shall
maintain records for a period of 2 years
of the following:
(1) The amount and date of each
purchase of new solvent.
(2) The name and/or type of solvent
purchased.
(3) The amount, date, and method of
disposal for spent solvent, sump
bottoms, and/or still bottoms, as
applicable.
(c) Each owner or operator of a cold
cleaner with a solvent-air interface area
of less than 1.0 m* (10.8 ft2) is not
subject to the requirements of paragraph
(b) of this section, but is required to
maintain for a period of 2 years a record
of the method of waste solvent disposal.
(d) The reporting and recordkeeping
requirements under this section will
automatically expire 5 years from the
date of promulgation of this regulation
unless affirmative action to extend them
is taken by EPA. (Section 114 of the
Clean Air Act as amended (42 U.S.C.
7414))
§60.365 Waste disposal [Reserved]
§60.366 Test method.
(a) Reference Method 23 or 25 of
Appendix A, as applicable, shall be
used to determine compliance with the
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requirements under § 60.382 when
carbon adsorbers are used. The results
shall be reported as ppm of organics
(Method 23) or ppm or carbon {Method
25). Each performance test shall consist
of 3 separate samples, and the
arithmetic mean of the 3 samples shall
be used to determine compliance.
(Section 114 of the Clean Air Act as amended
(U.S.C. 7414))
3. Appendix A to part 60 is amended
by adding reference method 23 as
follows:
Appendix A—Reference Methods
* * * * *
Method 23. Determination of Halogenated
Organics From Stationary Sources
Introduction
Performance of this method should not be
attempted by persons unfamiliar with the
operation of a gas chromatograph. nor by
those who are unfamiliar with source
sampling because knowledge beyond the
scope of this presentation is required. Care
must be exercised to prevent exposure of
sampling personnel to hazardous emissions.
1. Applicability and Principle
1.1 Applicability. This method applies to
the measurement of halogenated organics
such as carbon tetracholoride, ethylene
dichloride, perchloroethylene,
trichloroethylene, Methylene chloride, 1,1,1-
trichloroethane, and trichlorotrifluoroethane
in stack gases from sources as specifiedd in
the regulations. It does not apply when the
halogenated organics are contained in
particulate matter.
1.2 Principle. An integrated bag sample of
stack gas containing one or more halogenated
organics is subjected to gas chromatographic
(CC) analysis, using a flame ionization
detector (FID).
2. Range and Sensitivity. The range of this
method is 0.1 to 200 ppm. The upper limit may
be extended by extending the calibration
range or by diluting the sample.
3. Interferences. The chromatograph
column with the corresponding operating
parameters herein described normally
provides an adequate resolution of
halogenated organics; however, resolution
interferences may be encountered in some
sources. Therefore, the chromatograph
operator shall select the column best suited
to his particular analysis problem, subject to
the approval of the Administrator. Approval
is automatic provided that confirming data
are produced through an adequate
supplemental analytical technique, e.g.
analysis with a different column or GC/mass
'spectroscopy. This confirming data must be
available for review by the Administrator.
4. Apparatus.
4.1 Sampling (see Figure 23-1). The
sampling train consists of the following
components:
4.1.1 Probe. Stainless steel, Pyrex* glass.
or Teflon* tubing (as stack temperature
•Mention of trade names or specific products
does not constitute endorsement by the
Environmental Protection Agency
permits), each equipped with a glass wool
plug to remove particulate matter.
4.1.2 Sample Line. Teflon,' 6.4-mm outside
diameter, of sufficient length to connect
probe to bag. Use a new unused piece for
each series of bag samples that constitutes an
emission test, and discard upon completion of
the test.
4.1.3 Quick Connects, Stainless steel,
male (2) and female (2), with ball checks (one
pair without), located as shown in Figure 23-
1.
4.1.4 Tedlar or Aluminized Mylar Bags.
100-liter capacity, to contain sample.
4.1.5 Bag Containers. Rigid leakproof
containers for sample bags, with covering to
protect contents from sunlight.
4.1.6 Needle Valve. To adjust sample flow
rate.
4.1.7 Pump. Leak-free, with minimum of 2-
liters/min capacity.
4.1.8 Charcoal Tube. To prevent
admission of halogenated organics to the
atmosphere in the vicinity of samplers.
4.1.9 Flow Meter. For observing sample
flow rate; capable of measuring a flow range
from 0.10 to 1.00 liter/mm.
4.1.10 Connecting Tubing. Teflon. 6.4-mm
outside diameter, to assemble sampling train
(Figure 23-1).
4.2 Sample Recovery. Teflon tubing, 6.4-
mm outside diameter, to connect bag to gas
chromatograph sample loop is required for
sample recovery. Use a new unused piece for
each series of bag samples that constitutes an
emission test and discard upon conclusion of
analysis of those bags.
4.3. Analysis. The following equipment is
needed:
4.3.1 Gas Chromatograph. With FID,
potentiometric strip chart recorder, and 1.0-
to 2.0-mI sampling loop in automatic sample
valve. The chromatographic system shall be
capable of producing a response to 0.1 ppm of
the halogenated organic compound that is at
least as great as the average noise level.
(Response is measured from the average
value of the baseline to the maximum of the
waveform, while standard operating
conditions are in use.)
4.3.2 Chromatographic Column. Stainless
steel, 3.05 m by 3.2 mm, containing 20 percent
SP-2100/0.1 percent Carbowax 1500 on 100/
120 Supelcoport. The analyst may use other
columns provided that the precision and
accuracy of the analysis of standards are not
impaired and he has available for review
information conforming that there is
adequate resolution of the halogenated
organic compound peak. (Adequate
resolution is defined as an area overlap of
not more than 10 percent of the halogenated
organic compound peak by an interferent
peak. Calculation of area overlap is
explained in Appendix E, Supplement A:
"Determination of Adequate
Chromatographic Peak Resolution."
4.3.3 Flow Meters (2). Rotameter type. 0-
to-100-ml/min capacity.
4.3.4 Gas Regulators. For required gas
cylinders.
4.3.5 Thermometer. Accurate to 1°C. to
measure temperature of heated sample loop
at time of sample injection.
4.3.6 Barometer. Accurate to 5 mm Hg, to
measure atmospheric pressure around gas
chromatograph during sample analysis.
4.3.7 Pump. Leak-free, with a minimum of
100-ml/min capacity.
4.3.8 Recorder. Strip chart type, optionally
equipped with either disc or electronic
integrator.
4.3.9 Planimeter. Optional, in place of disc
or electronic integrator (4.3.8). to measure
chromatograph peak areas.
4.4 Calibration. Sections 4.4.2 through
4.4.6 are for the optional procedure in Section
7.1.
4.4.1 Tubing. Teflon, 6.4-mm outside
diameter, separate pieces marked for each
calibration concentration.
4.4.2 Tedlar or Aluminized Mylar Bags.
50-liter capacity, with valve; separate bag
marked for each calibration concentration.
4.4.3 Syringe. 25-pl, gas tight, individually
calibrated, to dispense liquid halogenated
organic solvent.
4.4.4 Syringe. 50-fil, gas tight, individually
calibrated to dispense liquid halogenated
organic solvent.
4 4.5 Dry Gas Meter, with Temperature
and Pressure Gauges. Accurate to ±2
percent, to meter nitrogen in preparation of
standard gas mixtures, calibrated at the flow
rate used to prepare standards.
4.4.6 Midget Impinger/Hot Plate
Assembly. To vaporize solvent.
5. Reagents. It is necessary that all
reagents be of chromatographic grade.
5.1 Analysis. The following are needed
for analysis:
5.1.1 Helium Gas or Nitrogen Gas. Zero
grade, for chromatographic carrier gas.
5.1.2 Hydrogen Gas. Zero grade.
5.1.3 Oxygen Gas or Air. Zero grade, as
required by the detector.
5.2 Calibration. Use one of the following
options: either 5.2.1 and 5.2.2, or 5.2.3.
5.2.1 Halogenated Organic Compound, 99
Mol Percent Pure. Certified by the
manufacturer to contain a minimum of 99 Mol
percent of the particular halogenated organic
compound; for use in the preparation of
standard gas mixtures as described in
Section 7.1.
5.2.2 Nitrogen Gas. Zero grade, for
preparation of standard gas mixtures as
described in Section 7.1.
5.2.3 Cylinder Standards (3). Gas mixture
standards (200,100, and 50 ppm of the
halogenated organic compound of interest, in
nitrogen) The tester may use these cylinder
standards to directly prepare a
chromatograph calibration curve as
described in Section 7.2.2, if the following
conditions are met: (a) The manufacturer
certifies the gas composition with an
accuracy of ±3 percent or better (see Section
5.2.3.1). (b) The manufacturer recommends a
maximum shelf life over which the gas
concentration does not change by greater
than ±5 percent from the certified value, (c)
The manufacturer affixes the date of gas
cylinder preparation, certified concentration
of the halogenated organic compound, and
recommended maximum shelf life to the
cylinder before shipment from the gas
manufacturer to the buyer.
5.2.3.1 Cylinder Standards Certification.
The manufacturer shall certify the
concentration of the halogenated organic
compound in nitrogen in each cylinder by (a)
directly analyzing each cylinder and (b)
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
calibrating his analytical procedure on the
day of cylinder analysis. To calibrate his
analytical procedure, the manufacturer shall
use, as a minimum, a three-point calibration
curve. It is recommended that the
manufacturer maintain (1) a high-
concentration calibration standard (between
200 and 400 ppm) to prepare his calibration
curve by an appropriate dilution technique
and (2) a low-concentration calibration
standard (between 50 and 100 ppm) to verify
the dilution technique used. If the difference
between the apparent concentration read
from the calibration curve and the true
concentration assigned to the low-
concentration calibration standard exceeds 5
percent of the true concentration, the
manufacturer shall determine the source of
error and correct it, then repeat the three-
point calibration.
5.2.3.2 Verification of Manufacturer's
Calibration Standards. Before using, the
manufacturer shall verify each calibration
standard by (a) comparing it to gas mixtures
prepared (with 99 Mol percent of the
halogenated organic compounds) in
accordance with the procedure described in
Section 7.1 or by (b) having it analyzed by the
National Bureau of Standards, if such
analysis is available. The agreement belween
the initially determined concentration value
and the verification concentration value must
be within ±5 percent. The manufacturer must
reverify all calibration standards on a time
interval consistent with the shelf life of the
cylinder standards sold.
5.2.4 Audit Cylinder Standards (2). Gas
mixture standards with concentrations
known only to the person supervising the
analysis samples. The audit cylinder
standards shall be identically prepared as
those in Section 5.2.3 (the halogenated
organic compounds of interest, in nitrogen).
The concentrations of the audit cylinders
should be: one low-concentration cylinder in
the range of 25 to 50 ppm, and one high-
concentration cylinder in the range of 200 to
300 ppm. When available, the tester may
obtain audit cylinders by contacting:
Environmental Protection Agency,
Environmental Monitoring and Support
Laboratory, Quality Assurance Branch (MD-
77), Research Triangle Park, North Carolina
27711. If audit cylinders are not available at
the Environmental Protection Agency, the
tester must secure an alternative source.
6. Procedure
6.1 Sampling. Assemble the sampling
train as shown in Figure 23-1. Perform a bag
leak check according to Section 7.3.2. Join the
quick connects as illustrated, and determine
that all connections between the bag and the
probe are tight. Place the end of the probe at
the centroid of the stack and start the pump
with the needle valve adjusted to yield a flow
that will more than half fill the bag in the
specified sample period. After allowing
sufficient time to purge the line several times,
connect the vacuum line to the bag and
evacuate the bag until the rotameter indicates
no flow At all times, direct the gas exiting
the rotameter away from sampling personnel.
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Stack Wall
Filter
(Glass Wool)
Teflon
Sample Line
Vacuum Line
Quick
Connects
Female
Rigid Leak-Proof
Container
Figure 23-1. Integrated-bag sampling train. (Mention
of trade names or specific products does not con-
stitute endorsement by the Environmental Protection
Agency.)
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Then reposition the sample and vacuum
lines and begin the actual sampling, keeping
the rate constant. At the end of the sample
period, shut off the pump, disconnect the
sample line from the bag, and disconnect the
vacuum line from the bag container. Protect
bag container from sunlight.
6.2 Sample Storage. Keep the sample bags
out of direct sunlight and protect from heat.
Perform the analysis within 1 day of sample
collection for methylene chloride, ethylene
dichloride, and trichlorotrifluoroethane, and
within 2 days for perchloroethylene,
trichloroethylene, 1,1,1-trichloroethane, and
carbon tetrachloride.
6.3 Sample Recovery. With a new piece of
Teflon tubing identified for that bag, connect
a bag inlet valve to the gas chromalograph
sample valve. Switch the valve to receive gas
from the bag through the sample loop.
Arrange the equipment so the sample gas
passes from the sample valve to a O-to-100-
ml/min rotameter with flow control valve
followed by a charcoal tube and a 0-tol-in.
HjO pressure gauge. The tester may maintain
the sample flow either by a vacuum pump or
container pressurization if the collection bag
remains in the rigid container. After sample
loop purging is ceased, allow the pressure
guage to return to zero before activating the
gas sampling valve.
6.4 Analysis. Set the colum temperature
to 100"C and the detector temperature to
225°C. When optimum hydrogen and oxygen
flow rates have been determined, verify and
maintain these flow rates during all
chromatograph operations. Using zero helium
or nitrogen as the carrier gas, establish a flow
rate in the range consistent with the
manufacturer's requirements for satisfactory
detector operation. A flow rate of
approximately 20 ml/min should produce
adequate separations. Observe the base line
periodically and determine that the noise
level has stabilized and that base-line drift
has ceased. Purge the sample loop for 30 sec
at the rate of 100 ml/min, then activate the
sample valve. Record the injection time (the
position of the pen on the chart at the time of
sample injection), the sample number, the
sample loop temperature, the column
temperature, carrier gas flow rate, chart
speed, and the attenuator setting. Record the
barometric pressure. From the chart, note the
peak having the retention time corresponding
to the halogenated organic compound, as
determined in Section 7.2.1. Measure the
halogenated organic compound peak area,
Am, by use of a disc integrator, electronic
integrator, or a planimeter. Record Am and
the retention time. Repeat the injection at
least two times or until two consective values
for the total area of the peak do not vary
more than 5 percent. Use the average value
for these two total areas to compute the bag
concentration.
6.5 Determination of Bag Water Vapor
Content. Measure the ambient temperature
and barometric pressure near the bag. From a
water saturation vapor pressure table.
determine and record the water vapor
content of the bag as a decimal figure.
(Assume the relative humidity to be 100
percent unless a lesser value is known.)
7. Preparation of Standard Cos Mixtures,
Calibration, and Quality Assurance.
7.1 Preparation of Standard Gas Mixtures.
(Optional procedure—delete if cylinder
standards are used.) Assemble the apparatus
shown in Figure 23-2. Check that all fittings
are tight. Evacuate a 50-liter Tedlar or
aluminized Mylar bag that has passed a leak
check (described in Section 7.3.2) and meter
in about 50 liters of nitrogen. Measure the
barometric pressure, the relative pressure at
the dry gas meter, and the temperature at the
dry gas meter. Refer to Table 23-1. While the
bag is filling, use the 50-jil syringe to inject
through the septum on top of the impinger,
the quantity required to yield a concentration
of 200 ppm. In a like manner, use the 25-/il
syringe to prepare bags having approximately
100- and 50-ppm concentrations. To calculate
the specific concentrations, refer to Section
8.1. (Tedlar bag gas mixture standards or
methylene chloride, ethylene dichloride, and
trichlorotrifluoroethane may be used for 1
day, trichloroethylene and 1,1,1-
trichloroethane for 2 days, and
perchloroethylene and carbon tetrachloride
for 10 days from the date of preparation.
(Caution: If the new gas mixture standard is a
lower concentration than the previous gas
mixture standard, contamination may be a
problem when a bag is reused.)
BILLING CODE 8560-01-M
V-JJ-15
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
Syringe
Nitrogen Cylinder
Dry Gas Meter
Boiling
Water
Bath
Tedlar Bag
Capacity
50 Liters
Figure 23-2. Preparation of Standards.
(optional)
V-JJ-16
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
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V-JJ-17
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
7 2 Calibration.
7.2.1 Determination of Halogenated
Organic Compound Retention Time. (This
section can be performed simultaneously
with Section 7.2.2.) Establish chromatograph
conditions identical with those in Section 6.4.
above. Determine proper attenuator position.
Flush the sampling loop with zero helium or
nitrogen and activate the sample valve.
Record the injection time, the sample loop
temperature, the column temperature, the
carrier gas flow rate, the chart speed, and the
attenuator setting. Record peaks and detector
responses that occur in the absence of the
halogenated organic. Maintain conditions
(with the equipment plumbing arranged
identically to Section 6.3), flush the sample
loop for 30 sec. at the rate of 100 ml/min with
one of the halogenated organic compound
calibration mixtures, and activate the sample
valve. Record the injection time. Select the
peak that corresponds to the halogenated
organic compound. Measure the distance on
the chart from the injection time to the time
at which the peak maximum occurs. This
distance divided by the chart speed is
defined as the halogenated organic
compound peak retention time. Since it is
possible that there will be other organics
present in the sample, it is very important
that positive identification of the
Halogenated organic compound peak be
made.
7.2.2 Preparation of Chromatograph
Calibration Curve. Make a gas
chromatographic measurement of each
Standard gas mixture (described in Section
5.2.3 or 7.1) using conditions identical with
those listed in Sections 6.3 and 6.4. Flush the
sampling loop for 30 sec at the rate of 100 ml/
min with one of the standard gas mixtures
and activate the sample valve. Record Cc, the
concentration of halogenated organic
injected, the attenuator setting, chart speed,
peak area, sample loop temperature, column
temperature, carrier gas flow rate, and
retention time. Record the laboratory
pressure. Calculate A., the peak area
multipled by the attenuator setting. Repeat
until two consecutive injection areas are
within 5 percent, then plot the average of
those two values versus Cc. When the other
standard gas mixtures have been similarly
analyzed and plotted, draw a straight line
through the points derived by the least
squares method. Perform calibration daily, or
before and after each set of bag samples.
whichever is more frequent.
7.3 Quality Assurance.
7.3.1 Analysis Audit. Immediately after
the preparation of the calibration curve and
prior to the sample analyses, perform the
analysis audit described in Appendix E,
Supplement B: "Procedure for Field Auditing
GC Analysis."
7.3.2 Bag Leak Checks. While
performance of this section is required
subsequent to bag use, it is also advised that
it be performed prior to bag use. After each
use, make sure a bag did not develop leaks
by connecting a water manometer and
pressurizing the bag to 5 to 10 cm HaO (2 to 4
in. HiO). Allow to stand for 10 min. Any
displacement in the water manometer
indicates a leak. Also, check the rigid
container for leaks in this manner. (Note: An
alternative leak check method is to pressurize
the bag to 5 to 10 cm HjO (2 to 4 in, HjO) and
allow to stand overnight. A deflated bag
indicates a leak.) For each sample bag in its
rigid container, place a rotameter in line
between the bag and the pump inlet.
Evacuate the bag. Failure of the rotameter to
register zero flow when the bag appears to be
empty indicates a leak.
8. Ca/cu/ations.
8.1 Optional Procedure Standards
Concentrations. Calculate each halogenated
organic standard concentration (Ce inppm)
prepared in accordance with Section 7.1 as
follows-
BILLING CODE C560-01-M
V-JJ-18
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
P. (24.055 x 103) . BD
c = * = 6.240 x 10*
c p w'"u * 1W M Vm Y Pm
u v 293 JL m
m ' Tm 760
Eq. 23-1
Where:
8 = Volume of halogenated organic injected, pi.
D = Density of compound at 293°K, g/ml.
M = Molecular weight of compound, g/g-mole.
V = Gas volume measured by dry gas meter, liters.
Y = Dry gas meter calibration factor, dimensionless.
'P = Absolute pressure of dry gas meter, mm Hg.
T = Absolute temperature of dry gas meter, °K.
24.055 = Ideal gas molal volume at 293° K and 760 mm Hg,
liters/g-mole.
10 = Conversion factor. [(ppm)(ml)]/yl.
8.2 Sample Concentrations. From the calibration curve
described in Section 7.2.2 above, select the value of C that
corresponds to A . Calculate C , the concentration of
halogenated organic in the sample (in ppm), as follows:
cc * D~T—TiT?—T Eq. 23-2
Where:
C = Concentration of the halogenated organic
indicated by the gas chromatograph, ppm.
P = Reference pressure, the laboratory pressure
recorded during calibration, mm Hg.
T. s Sample loop temperature at the time of
analysis, °K.
P. » Laboratory pressure at time of analysis, mm Hg.
T a Reference temperature, the sample loop temperature
recorded during calibration, °K.
Swb •= Water vapor content of the bag sample, volume fraction.
V-JJ-19
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
9. References.
\. Feairheller, W. K, A M. Kemmer. B J
Warner, and D. Q. Douglas. Measurement of
Caseous Organic Compound Emissions by
Gas Chromatography EPA Contract No 68-
02-1404, Task 33 and 68-02-2818. Work
Assignment 3. January 1978. Revised by EPA
August 1978.
2. Supelico, Inc. Separation of
Hydrocarbons. Bulletin 747 Belleforte.
Pennsylvania. 1974.
3. Communication from Joseph E. Knoll
Percholoroethylene Analysis by Gas
Chromatography. March 8,1978.
4. Communication from Joseph E. Knoll
Test Method for Halogenated Hydrocarbons
December 20.1978.
*****
(Sections lll(b), lll(d), 114, and 301(a) of the
Clean Air Act as amended (42 U.S.C 7411
7414. and 7601(a)J)
|FR Out 80-130>H Piled 6-10-00. 845 ..m|
V-JJ-20
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
LEAD-ACID BATTERY MANUFACTURE
SUBPART KK
-------
Federal Register / Vol. 45, No. 9 / Monday, January 14, 1930 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1315-4]
Standards of Performance for New
Stationary Sources; Lead-Acid Battery
Manufacture
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.
SUMMARY: The proposed standards of
performance would limit atmospheric
emissions of lead from new, modified,
and reconstructed facilities at lead-acid
battery plants. This source was listed
August 21,1979 (44 FR 49222) in
accordance wilh section li:i(b)(l)(A) of
the Clean Air Act as contributing
significantly to air pollution, which may
reasonably be anticipated to endanger
public health or welfare. The intended
effect of this proposal is to require new,
modified, and reconstructed lead-acid
battery manufacturing facilities to
control lead emissions within the
specified limits, which can be achieved
through the use of the best demonstrated
system of continuous emission
reduction. A new reference method for
determining compliance with lead
standards is also proposed.
DATES: Comments—Comments must be
received on or before March 14,1980.
Public Hearing—The public hearing will
be held on Wednesday, February 13,
1980 beginning at 9:30 a.m. Request to
Speak at Hearing—Persons wishing to
present oral testimony must contact EPA
by February 7,1980.
ADDRESSES: Comments—Comments
should be submitted (in duplicate if
possible) to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency. 401 M Street S.W., Washington,
D.C. 20460, Attention: Docket No.
OAQPS-79-1. Public Hearing—The
public hearing will be held at EPA
Environmental Research Center
Auditorium, Rm B102, Research Triangle
Park, N.C. 27711. Persons wishing to
present oral testimony should notify
Shirley Tabler, Emission Standards and
Engineering Division (MD-13).
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5421.
Background Information Document—
The background information document
for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number (919)
541-2777. Specify "Lead-Acid Battery
Manufacture, Background Information
for Proposed Emission Standards" (EPA
450/3-79-02Ga). Docket—The docket
number OAQPS-79-1, is available for
public inspsction and copying between
8:00 a.m. arid 4:00 p.m. at EPA's Central
Docket Section, Room 2903B, Waterside
Mall. 401 M Street S.W., Washington,
D.C. 20460.
F03 FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
Ths proposed standards would limit
atmospheric lead emissions from new,
modified, or reconstructed facilities at
any lead-acid battery manufacturing
plant which has a production capacity
equal to or greater than 500 batteries per
day (bpd). The facilities which would be
affected by the standards, and the
proposed emission limits for these
facilities are listed below:
Facdity
Lead omde production.. 5 0 mg/kg (0 010 Ib/ton)
Gnd casfcng .. 005 mg/m1(0? x 10~*gr/dscf).
Paste rpixing 1.00 mg/m' (4 4 x 10 4gr/(Sscf)
Three-process . ... 1 00 mo,'m'(< 4 x 10 'B"'db-0
Lead reda/natiorc 2 00 i^g/m5 (8 8 x 10'' g//aicf)
Otner tea3 ftmittmg 1.00 mg/rrr (44x10 * y1 dscf)
operations.
The emission limit for lead oxide
manufacture is expressed in terms of
lead emissions per kilogram of lead
processed, while those for other
facilities are expressed in terms of lead
concentrations in exhaust air.
A standard of 0 percent opacity is
proposed for emissions from any of
these facilities. The proposed standards
would also require continuous
monitoring of the pressure drop across
the control system for any affected
facility, to help insure proper operation
of the system. Performance tests would
be required to determine compliance
with the proposed standards. A new
reference method, Method 12, would be
used to measure the amount of lead in
exhaost gases, and Method 9 would be
used to measure opacity. Process
monitoring would be required during all
tests.
Summary of Environmental, Energy, and
Economic Impacts
There are approximately 190 lead-acid
battery manufacturing plants in the
United States, of which about 100 have
been estimated to have capacities
greater than or equal to 500 batteries per
day (bpd). These plants are scattered
throughout the country and are generally
located in urban areas near the market
for their batteries. Projections of the
growth rate of the lead-acid battery
manufacturing industry range from 3 to 5
percent per year over the next 5 years.
Most of the projected increase in
manufacturing capacity is expected to
take place by the expansion of large
plants (producing over 2000 batteries per
day).
New, modified, and reconstructed
facilities coming on-line over the next 5
years will emit about 95 Mg (104 tons) of
lead to the atmosphere in the fifth year,
if their emissions are controlled only to
the extent required by current State
paniculate regulations. At some existing
plants, emissions are controlled to a
greater extent than State particulate
regulations require. This practice might
be continued at new plants in the
absence of the proposed standards of
performance. The proposed standards
would reduce potential lead emissions
from facilities coming on-line during the
next 5 years to about 2.8 Mg (3.1 tons) in
the fifth year. This is approximately 97
percent lower than the emission level
which would be allowed under State
particu'.ate regulations. The proposed
standards would also result in
decreased nonlead particulate emissions
from new plants, since equipment
installed for the purpose of controlling
lead-btaring particulate emissions
would also control nonlead bearing
particulate emissions.
The results of dispersion modeling
calculations indicate that the ambient
impact of lead emissions from a new
plant complying with the proposed
standards would be less than the
national ambient air quality standard
for lead of 1.5/xg/m3 (averaged over
calendar quarter). This is an important
consideration, since most lead-acid
battery plants ore located in urban
areas. Results of EPA dispersion
modeling calculations indicate that the
ambient lead standard will not be met in
the vicinities of plants controlling
emissions only to the extent required by
existing State regulations.
The impact of the proposed standards
on the wastewater and solid waste
emissions of a lead-acid battery plant
would depend on the technique used by
that plant to comply with the proposed
standards. The best demonstrated
system for reduction of lead emissions is
the use of fabric filters. High energy
impingement scrubbers could also be
used, but would have higher energy
requirements and operating costs than
fabric filters. At plants using
impingement scrubbing to control
emissions, lead-bearing wastewater
would be generated. This would be
V-KK-2
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
treated along with other plant
wastewater prior to being disposed from
the plant. The fractional increase in the
lead content of wastewater discharged
from a plant using impingement
scrubbing to control atmospheric lead
emissions would be about 0.5 to 4.5
percent. At plants using fabric filtration
to comply with the proposed standards,
the captured pollutant would be
reclaimed, and there would be no
increase in wastewater or solid waste
emissions due to the proposed
standards.
The energy needed to operate control
equipment required to meet the
proposed standards at a new plant
would be approximately 2 percent of the
total energy needed to run the plant. The
incremental energy demand resulting
from the application of the proposed
standards to the battery manufacturing
facilities expected to come on-line over
the next five years would be about 2.8
Gigawatt hours of electricity in the fifth
year. Approximately 4.8 thousand
barrels of oil would be required to
generate this electricity.
The capital cost of the installed
emission control equipment necessary to
meet the proposed standards on all new
facilities coming on-line nationwide
during the first five years of the
standards would be approximately $8.6
million. The total annualized cost of
operating this equipment in the fifth
year of the proposed standards would
be about $4 million.
These costs and energy and
environmental impacts are considered
reasonable, and are not expected to
prevent or hinder expansion of the lead-
acid battery manufacturing industry.
Economic analysis indicates that, for
plants with capacities larger than or
equal to 500 bpd, the costs attributable
to the proposed standards could be
passed on with little effect on sales. The
average incremental cost associated
with the proposed standard would be
about 30< per battery. This is about 1.6
percent of the wholesale price of a
battery.
Modification and Reconstruction of
Existing Sources
In accordance with provisions
applicable to all standards of
performance, the proposed standards for
the lead-acid battery manufacturing
industry would apply to modified and
reconstructed facilities, as well as to
new facilities.
Under the modification provisions of
40 CFR 60.14, except in certain cases, an
existing facility would be affected by
the proposed standards if some physical
or operational change is made to that
facility which results in an increase in
atmospheric lead emissions from that
facility. Actions which would not be
considered modifications, and thus
would not cause an existing facility to
become subject to the standards,
regardless of any emission increase are:
1. Routine maintenance, repair, and
replacement of components.
2. An increase in the production rate
of a facility which is accomplished with
an expenditure on the source containing
the facility of less than 5.5 percent of the
value of the facility. (This is the Internal
Revenue Service annual asset guideline
repair allowance for a facility at a lead-
acid battery plant.)
3. An increase in the number of
operating hours of a facility.
4. The use of an alternative raw
material if the facility was designed to
accommodate such material prior to this
proposal.
5. The addition or use of any system
or device whose primary function is the
reduction of air pollutants, except when
an emission control system is removed
or is replaced by a system which the
Administrator determines to be less
environmentally beneficial.
6. The relocation or change in
ownership of an existing facility.
Under the reconstruction provisions
applicable to all standards of
performance (40 CFR 60.15), an existing
facility might become subject to the
standards if its components were
replaced to such an extent that the fixed
capital cost of the new components
exceeded 50 percent of the fixed capital
cost that would be required to construct
a comparable new facility. The
standards would not apply, however, if
the Administrator determined that it
would not be technologically or
economically feasible to meet the
standards. Such determinations would
be made on a case-by-case basis.
Rationale for the Proposed Standards—
Selection of Source and Pollutant for
Control
The manufacture of lead-acid
batteries begins with the casting of lead
grids and the production of lead oxide
powder. The lead oxide powder is
mixed with water and sulfuric acid to
form a stiff paste, which is then pressed
onto the lead grids. The pasted grids
(plates) are cured, stacked, and
connected (burned) into groups that
form the individual elements of a lead-
acid battery. The battery plates are
converted to active electrodes by the
formation process. In this process, the
battery elements are immersed in dilute
sulfuric acid, and direct current is
passed between the plates to form
active electrodes. Formation can take
place either in an open acid bath (dry
formation), or after the battery elements
have been assembled into battery cases
(wet formation). At some plants, scrap
lead is recycled in a lead reclamation
process.
Most of the operations discussed
above are independent of one another.
For instance, most small plants do not
have lead oxide production or lead
reclamation facilities, and some large
companies sell lead oxide. However,
stacking and burning of battery plates
and assembly of elements into battery
cases are generally accomplished in a
single operation, called the three-
process operation.
Most lead-acid battery plants are
located near residential or urban areas.
These plants emit lead-bearing
particulate matter to the atmosphere.
Sources of atmospheric lead emissions
at lead-acid battery plants include lead
oxide production, grid casting, paste
mixing, three-process operation, and
lead reclamation facilities. A National
Ambient Air Quality Standard has been
established for lead. The health and
welfare effects of lead are presented in
the document, "Air Quality Criteria for
Lead" (EPA-600/8-77-017). Based on the
results of EPA emission tests and the
current required level of control, it is
estimated that emissions from lead-acid
battery plants could result in ambient
lead concentrations which exceed the
National Ambient Air Quality Standard,
These emissions may reasonably be
anticipated to endanger public health or
welfare. Therefore, standards are
proposed for lead emissions from lead-
acid battery plants. Standards are not
proposed for nonlead particulate
emissions because such emissions are
slight when compared with particulate
emissions from other sources. Also,
control of lead emissions would result in
the reduction of other particulate
emissions as well.
In addition to lead-bearing particulate
matter, plants using dry formation
techniques emit sulfuric acid mist. This
mist results from the entrainment of
sulfuric acid in hydrogen bubbles which
are generated during the formation
process. Wet formation usually takes
place in covered battery cases.
Therefore, acid mist emissions from wet
formation are small.
Sulfuric acid mist has been previously
determined to be a health related
pollutant for the purposes of section
lll(d) of the Clean Air Act. Therefore.
the Administrator considered proposing
standards for the lead-acid battery
manufacturing industry which would
limit acid mist emissions from the dry
formation process. The setting of
standards requiring control of acid mist
emissions from new, modified, and
V-KK-3
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1880 / Proposed Rules
reconstructed formation facilities would
require States to limit acid mi^t
emissions from existing plants as well,
under section lll(d).
EPA tests on dry formation at one
plant indicate that the uncontrolled
sulfuric acid mist emission rate from this
facility is low (1.1 kg/1000 batteries).
Dispersion modeling studies based on
this emission rate indicate that the
maximum ambient impact of sulfuric
acid mist emissions from the dry
formation process at a plant as large as
6500 batteries per day would be less
than 1 fig/ms on an annual basis.
Therefore, standards for acid mist are
not being proposed at this time.
In contrast, two literature sources
indicate that the acid mist emission rate
from dry formation may be much higher
(up to 19 k/1000 batteries) than the rate
measured by EPA. However, EPA is
unable to determine the reliability of the
data contained in these sources because
neither the test methods used nor the
process operating conditions during
testing are known. Therefore, although
these sources indicate that acid mist
emissions from the formation process
may be significant, they do not provide
a sufficient basis for an acid mist
standard for the formation process.
It is of concern to the Administrator
that the decision not to regulate acid
mist emissions from formation is based
on the results of tests at only one plant
The public is specifically invited to
submit comments with supporting data
on the issue of acid mist control. Based
on the information received, EPA may
take action regarding control of acid
mist emissions from the formation
process.
Applicability
The proposed standards of
performance would apply to new,
modified, or reconstructed facilities at
any lead-acid battery plant that has the
capacity to produce 500 or more
batteries in a day (24 hours). Plnnts with
capacities less than 500 bpd are
exempted from the proposed standards
for several reasons. First, projections of
the economic impact of standards on
existing small plants (100 and 250 bpd)
undergoing reconstruction or
modification indicated that standards
would have a severe negative impact on
such plants. Also, although almost 50
percent of the lead-acid battery plants in
the United States produce fewer than
500 bpd, these plants account for only
about 2 percent of tolal lead-acid
battery production. Finally, industry
representatives do not forecast
construction or expansion of small
plants. In fact there has been a trend in
recent years of small plants closing due
to unprofitability. Increased demand for
batteries in the future is expected to be
accommodated by expansion of existing
p'.ants producing over 2000 bpd.
Selection of Affected Faciliiies
Lead emitting process operations
selected as affected facilities are lead
oxide production, grid casting, paste
mixing, three-process operation, lead
reclamation, and other lead emitting
operations. These process operations
often consist of several machines or
production lines which perform the
same function and which are located in
the same area and ducted to the same
control device. Therefore, for each of the
process operations mentioned above,
the affected facility is the entire
operation. For example, at a plant with
more than one three-process line, all of
the lines together would be the affected
facility.
Lead Oxide Manufacturing—In the
lead-acid battery industry, lead oxide is
produced either by the ball mill process,
or by the Barton process. In the ball mill
process, which is used more frequently,
lead pigs or balls are tumbled in a mill,
and the frictional heat generated by the
tumbling action causes the formation of
lead oxide. The lead oxide is removed
from the mill by an air stream. In the
Barton process, molten lead is atomized
to form small droplets in an air stream.
These droplets arc then oxidized by the
air nround them.
Thus, in both the Barton process and
the ball mill process, lead oxide product
must be recovered from an air stream. In
both processes, fabric filtration is used
to accomplish this separation. It is
estimated that lead emissions from a
typical lead oxide manufacturing facility
including product recovery are about
0 05 kg (0.116 Ib) per 1,000 batteries, or
about 10 g/Mg (0.02 Ib/ton) of lead
processed, Although these lead
emissions are low, source tests have
indicated that a well controlled lead
oxide manufacturing facility would emit
only about half as much lead as one
designed only for economical recovery
of lead oxide. Therefore, the lead oxide
production process is designated an
affected facility.
Grid Casting—Although lead
emissions from grid casting are
generally low, most grid casting work
areas would be ventilated to comply
with the in-plant OSHA lead
concentration stanard of 50 fig/m8. EPA
tests detected an uncontrolled lead
emission rate of 0.4 kg (0.9 Ib) per 1,000
batteries (4.37 mg/m3 or 19.1 X 10"4gr/
dscf of exhaust air), which was about 3.2
percent of the overall plant uncontrolled
lead emission rate. Therefore, grid
casting is designated an affected facility.
The gr.d casting facility is defined to
include both the grid casting machines,
and the lead melting pots associated
with these machines.
Paste Mixing—Paste mixing is
generally a batch operation consisting of
two phases: a charging phase, in which
lead oxide is fed to the paste mixer, and
a mixing phase, in which the lead oxide
is mixed with water and sulfuric acid.
Most emissions from paste mixing occur
during the charging phase. However,
lead emissions are also ducted from the
paste mixer during the mixing phase.
Uncontrolled lead emissions from paste
mixing have been determined to be
approximately 5.1 kg (11.2 Ib) per 1,000
batteries (77.4 mg/m3 or 338 X 10~4gr/
dscf of exhaust). This is about 40
percent of the total estimated
uncontrolled lead emission rate for a
lead-acid battery plant. The paste
mixing facility is, therefore, selected as
an affected facility.
Three-process Operation—The Three-
process operation facility is defined to
include all processes involved with plate
stacking, burning, and assembly of
elements into battery cases. Average
uncontrolled lead emissions from three-
process operations tested by EPA were
6.7 kg (14.7 Ib) per 1,000 batteries (26
mg/m3 or 115 X 10~4gr/dscf of exhaust
air). This is over 50 percent of the
estimated lead erri-ssions from a lead-
acid battery plar.t. Therfore, the three-
process operation is designated an
affected facility.
Lead Reclamation—Lead reclamation
is often a sporadic operation, on stream
only when larga quantities of defective
small parts, grids, and plates are
available. EPA measured lead emissions
from this process to be 0.35 kg (0.77 Ib)
per 1000 batteries, 3.0 kg/Nig (5.9 Ib/ton)
of lead charged, or 227 mg/m3 (990X10^
gr/dscf) of exhaust air. Lead emissions
can be very high duiing operation. For
example, a 4000-bpd plant at which the
lead reclamation facility is run for an 8-
hour shift every 2 weeks would etnit
approximately 1.7 kg/hr (3,8 Ib/hr)
during operation. This is comparable
with the lead emission rate from the
three-process operation at the same
plant. Therefore, the Adniinistrator
designates lead reclamation as an
affected facility. Reverberatory
furnances which are used for lead
reclamation but which are affected by
standards of performance for secondary
lead smelters (40 CFR 60.120), would not
be affected under the proposed
standards.
Other Lead-Emitting Opercitions—
Any lead-acid battery plant facility from
which lead emissions are collected and
ducted to the atmosphere but which is
not considered part of the lead oxide
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pniductv.in grid casting, paste mixing,
three-process operation, or lead
reclamation facilities is considered an
"other lead emitting operation." An
example is slitting, a process whereby
lead grids, cast in doublets, are slit (with
an enclosed saw) into separate plates.
The Administrator has selected other
If .id emitting operations as affected
facilities to ensure the control of lead
emissions from these processes.
Selection of the Best System of
Emissions Reduction Considering Costs
Section 111 of the Clean Air Act
requires that standards of performance
reject the degree of emission control
achievable through application of the
bt!it de-ncji&'rated technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact, and energy requirements) has
been adequately demonstrated. The
proposed standards were developed
based on information derived from (1)
a\ arable technical literature on the
lead-acid battery manufacturing
industry and applicable emission control
technology, (2) technical studies
performed for EPA by independent
research organizations, (3) information
obtained from the industry during visits
to lead battery plants and meetings with
various representatives of the industry,
(4) comments and suggestions solicited
from experts, and (5) results of emission
measurements conducted by EPA.
Techniques currently used to control
atmospheric lead emissions from
facilities at lead-acid battery plants
include fabric filtration and
impingement scrubbing of exhaust
gases. Low energy scubbers are
currently used to control emissions
entrained in hot gases, or in gases
containing moisture or possible spark
hazards. Fabric filters can be used to
control all atmospheric lead emissions
from lead-acid battery manufacturing,
provided that proper maintenance
procedures are followed and that
necessary precautions are taken to
prevent condensation or sparks when
necessary. They are commonly used in
other industries to control emissions
from sources having similar moisure
problems and spark problems.
Several emission control alternatives
were studied in the development of the
proposed standards. One of these
alternatives consists of fabric filter
control for all affected facilities. The
others consist of fabric filler control for
Rome affected facilities and low energy
impingement scrubber control for other
affected facilities. The alternative which
would achieve the best degree of
emission control is fabric filter control
of atmospheric lead emissions from all
affected facilities. The other alternatives
make use of low energy scrubbers to
varying extents, and represent varying
degrees of emission reduction. Economic
analysis has shown that, for plants with
capacities greater than or equal to 500
batteries per day, none of the control
alternatives which were studied would
impose an unreasonable cost. Also, the
cost of any alternative is not viewed as
being detrimental to industry expansion.
The proposed standards are based on
the control of all lead emissions from
lewd-acid battery plants by fabric
filtration. This basis was chosen
because fabric filters can achieve a
better degree of emission reduction than
low energy scrubbers at a reasonable
cost.
The use of control techniques other
than fabric filtration would not be
precluded by the proposed standards.
High energy impingement scrubbers
could be used to meet the emission
limits. However, these would have
higher operating costs and energy
requirements than fabric filters.
Sciubbers would also generate lead
contaminated water, which would
probably require treatment prior to
disposal.
Selection of the Format for the Proposed
Standard
In general, lead-acid battery
manufacturing facilities may be
considered independent of one another
in that there is no continuous flow of
materials. Lead oxide production
operations, grid casting operations,
paste mixing operations, lead
reclamation operations, and three-
process operations are independent.
Also, not all plants have lead
reclamation and lead oxide production
operations, and some plants sell lead
oxide.
Because of the independent nature of
the facilities, two different forms were
chosen for the proposed standards. The
format of the proposed standards
applicable to grid casting, paste mixing.
three-process operation, lead
reclamation, and other lead-emitting
operations, is a concentration standard.
The format of the standard for lead
oxide manufacturing is mass per unit of
lead input.
A concentration standard is proposed
for three-process facilities because
emissions from these facilities depend
more on number of plates processed and
the method of burning than on the
weight of material processed. Since
emissions from grid casting, paste
mixing, and lead reclamation are often
controlled by the control device which
controls three process operation
emissions, concentration standards are
also proposed for these facilities, A
mass per unit lead input standard is
proposed for lead oxide production
facilities because these facilities
generally have different emission
control devices from three-process
operation facilities and because
emissions fiom lead oxide production
are generally proportional to lead input.
Selection of Emission Limits
The proposed limits for lead emissions
from lead oxide production, grid casting,
paste mixing, three-process operation,
lead reclamation, and other lead
emitting facilities are based on
emissions levels attainable using fabric
filtration. In the development of
background data for the proposed
standards, atmospheric lead emissions
from facilities at four lead-acid battery
plants were measured using the
proposed Method 12. In a previous
study, lead emissions from facilities at
two lead-acid battery manufacturing
plants and one lead oxide
manufacturing plant were measured
using a similar test method.
The emission limits for three-process
operation facilities, lead oxide
production facilities, and other lead
emitting facilities are based on lead
levels measured in exhausts from fabric
filters controlling emissions from such
facilities. Fabric filters are not currently
used in the lead-acid battery industry to
control emissions from grid casting or
lead reclamation and are not generally
used to control emissions from the
mixing phase of paste mixing. The
emission limits for grid casting, paste
mixing, and lead reclamation are,
therefore, based on lead levels found in
uncontrolled emissions from such
facilities, and on the demonstrated
emission reduction capabilities of fabric
filters.
Tests of controlled and uncontrolled
emissions from three-process facilities
controlled by fabric filters indicated ,
fabric filter lead collection efficiencies
of about 99 percent. This control
efficiency is consistent with efficiencies
achieved by well maintained fabric
filters in other applications. Because
paniculate emissions from all lead
emitting facilities at battery plants are
similar in composition and particle size.
the Administrator has determined that
comparable collection efficiencies can
be achieved for emissions from grid
casting, paste mixing, and lead
reclamation.
Lead Oxide Manufacturing—The
proposed standard for lead oxide
production is 5 milligrams of lead per
kilogram of lead processed (10 Ib/ton).
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rales
This limit is based on results of tests of
emissions from a ball mill lead oxide
production facility with a fabric filter
control system. The tests showed an
average controlled emission rate of 4.2
mg/Kg (8.4 Ib/ton) for this facility. EPA
has not conducted tests of emissions
from a well controlled Barton process.
However, in both the ball mill process
and the Barton process, lead oxide
product must be removed from an air
stream. Also, EPA tests on a Barton
process indicated that Barton and ball
mill processes have similar air flow
rates per unit production rate. Therefore,
it has been determined that a similar
level of emission control could be
achieved for a Barton process as has
been demonstrated for the ball mill
process.
Grid Casting—Impingement
scrubbing, rather than fabric filtration, is
currently used in the lead-acid battery
manufacturing industry to control
emissions from grid casting. Emissions
from grid casting facilities were
measured at two plants. At one of these
plants, grid casting emissions were
controlled by an impingement scrubber.
At the other, grid casting'emissions were
not controlled. The average lead
concentration in exhaust from the
uncontrolled facility was 4.37 mg/m3
(19.1 X10"4 gr/dscf). Average
uncontrolled and controlled lead
emissions from the scrubber controlled
facility were 2.65 mg/m3 (11.6xiO"4gr/
dscf) and 0.32 mg/m' (1.4Xl(T4gr/dscf),
respectively. Thus the lead collection
efficiency of the scrubber was about 90
percent.
Fabric filtration can be used to control
these emissions if spark arresters are
used and the exhaust gas is kept above
the dew point. The lead standard for
grid casting, 0.05 mg/m3(0.2XlO~4gr/
dscf), is based on the exhaust
concentration achievable using a fabric
filter with about 99 percent collection
efficiency to control emissions.
Paste Mixing—Lead emissions from a
paste mixing facility equipped with an
impingement scrubber were measured.
Average uncontrolled and controlled
lead concentrations from this facility
were 77.4 mg/m3(338X10~4gr/dscf) and
10.8 mg/m3 (47.0xlO-4gr/dscf),
respectively.
Fabric filtration is not generally used
to control emissions from the entire
paste mixing cycle because of the high
moisture content of paste mixer exhaust
during the mixing cycle. However, fabric
filtration can be used to control
emissions from the entire cycle if the
exhaust gas is kept above the dew point.
The proposed lead emission standard
for paste mixing, 1 mg/m3 {4.4X!0~4gr/
dscf), is based on the level achievable
using a fabric filter with about 99
percent collection efficiency for the
entire cycle.
In developing data for the proposed
standards, EPA conducted tests at a
plant where paste mixing emissions
were controlled by two separate
systems. At this plant, paste mixing
required a total of 21 to 24 minutes per
batch. During the first 14 to 16 minutes
of a cycle (the charging phase), exhaust
from the paste mixer was ducted to a
fabric filter which also controlled
emissions from the grid slitting
(separating) operation. During the
remainder of the cycle (mixing), paste
mixer exhaust was ducted to an
impingement scrubber which also
controlled emissions from the grid
casting operation. Uncontrolled or
controlled emissions for the paste mixer
alone were not tested. The average
concentration of lead in emissions from
the fabric filtration system used to
control charging emissions was 1.3 mg/
m3 (5.5X10~4 gr/dscf). The average lead
content of exhaust from the scrubber
used to control mixing emissions was
0.25 mg/m3 (1.1 X ID'4 gr/dscf). The
average lead concentration in controlled
emissions from this facility was about
0.95 mg/m3 (4.2 X10~4 gr/dscf) which is
slightly below the proposed emission
limit of 1 mg/m3 (4.4 x 10" 4gr/dscf). A
lower average emission concentration
could be achieved by using fabric
filtration to control emissions from all
phases of paste mixing.
Three-Process Operation—The
proposed lead concentration limit for
three-process operation emissions is 1
mg/m3 (4.4 X10"4 gr/dscf). This limit is
based on the results of EPA tests
conducted at four plants where fabric
filtration was used to control three-
process operation emissions. All of
these tests showed lead concentration
below the proposed limit in controlled
emissions from the three-process
operation facilities.
Lead Reclamation—Lead emissions
from a lead reclamation facility where
emissions are controlled by an
impingement scrubber were measured.
The average lead concentrations in the
inlet and outlet streams of the scrubber
were 227 mg/m3 (990 X10~4 gr/dscf} and
3.7 mg/m3 (16 x 10"4 gr/dscf),
respectively. The collection efficiency of
the scrubber was, therefore, about 98
percent.
Fabric filtration is not currently used
to control emissions from lead
reclamation facilities because of the
high temperature of lead reclamation
exhaust. However, fabric filters have
been applied to hot exhaust systems at
secondary lead smelters and in other
industries. Therefore, the proposed
standard for lead reclamation facilities
of 2 mg/m3 (8.8 X10"4 gr/dscf), is based
on the emission level attainable using a
fabric filter with a collection efficiency
of about 99 percent.
Other Lead Emitting Operations—
Emissions from other lead emitting
operations are generally collected and
ducted to minimize worker exposure.
These emissions are similar in
composition and concentration to
emissions from non-automated three-
process operations. The proposed
standard for other lead emitting
operations is 1 mg/m3 (4.4 X10~4 gr/dscf)
because lead emissions from those
operations can be controlled to the same
extent as lead emissions three-process
operation facilities.
EPA measured emissions from a
slitting facility, which would be
classified as an "other lead emitting
operation," controlled by a fabric filter.
The controlled emissions from the
facility had an average lead content of
0.938 mg/m3 (4.1 X10~4 gr/dscf), which is
below the proposed concentration limit
for other lead emitting operations.
Opacity Standards
A standard of 0 percent opacity is
proposed for emissions from all affected
facilities. Grid casting, paste mixing,
three-process operation, and lead oxide
manufacturing facilities were observed
by EPA to have emissions with 0 percent
opacity during observation periods of 7
hours and 16 minutes, 1 hour and 30
minutes, 3 hours and 51 minutes, and 3
hours and 19 minutes, respectively.
Emissions ranging from 5 to 20 percent
opacity were observed for a total of 11
minutes and 15 seconds during 3 hours
and 22 minutes of observation at the
lead reclamation operation source
tested by EPA, which was controlled by
a low-energy scrubber. However, the
proposed standard is based on control
of this process by a fabric filter, similar
to three-process operations and paste
mixers for which emissions with 0
percent opacity have been observed. A
standard of 0 percent opacity is,
therefore, also proposed for emissions
from lead reclamation furnaces.
Under the proposed standards,
opacity would be determined by taking
the average opacity over a 6-minule
period using EPA Test Method 9, and
rounding the average to the nearest
whole percentage. The rounding
procedure is specified in the proposed
standards in order to allow occasional
brief emissions with opacities greater
than 0 percent. When a fabric filter is
used to control emissions, the outlet
concentration from the filter may
increase immediately after a component
filter bag is cleaned. In the case of a
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
lead-acid battery plant, filter cleaning
may result in occasional emissions with
opacities greater than 0 percent. If the
roundir.g off procedure were not
specified, any reading of greater than 0
percent opacity during a 6-minute period
could be considered as indicative of a
vio'.iaon of the proposed 0 percent
opacity standard. However, the
Administrator does not intend for
occasional emissions greater than 0
percent opacity occurring during filter
cleaning to be considered violations of
the proposed standards. Therefore, the
standards would specify that the
average opacity bt rounded to the
nearest whole percentage. With this
specification, 6-minut8 average opacities
less than 0.5 percent would not be
considered violations of the proposed
standards. Emissions which result in 6-
minute average opacities of 0.5 percent
or g'ca'.rr are expected to be indicative
of fabric filter malfunctions rather than
filter cleaning emissions.
Testing and Recordkceping
Performance tests would be required
to determine compliance with the
proposed standards. A new Reference
Method 12 would be used to measure
lead emissions. In addition, the
following methods would be used to
determine the necessary emission data:
Mtthod 1 for sample and velocity
traverses, Method 2 for velocity and
volumetric flow rate, Method 4 for stack
gas moisture and Method 9 for stack
opacity.
A measurement of the mass rate of
feed would also be required during
performance tests for lead oxide
inariifacturing because the units of the
standards for this facility are milligrams
of lead per kilogram of lead feed. Lead
ingnts of constant weight can be
counted as they are fed to the lead oxide
manufacturing process. The mass rate of
feed measurements must be accurate
uithin ±5 percent.
To determine compliance when two or
mort facilities at the same plant are
ducted to a common control device, the
exhaust rate from each source and the
controlled lead concentrations must be
measured. An equivalent standard for
the applicable facilities is calculated by
multiplying each applicable standard by
the fractional exhaust flow rate of that
facility and adding the numbers. This
equivalent standard can then be
compared with the measured
concentration to determine compliance.
The proposed standards would
require continuous monitoring of the
pressure drop across the fabric filter or
scrubber as applicable. A decrease in
p-esp'.ire drop of about 50 percent could
indicate a decrease in lead removal
efficiency because of either a fabric
filter bag failure or a decrease in liquid-
to-gas ratio.
EPA Reference Method 12 was
developed to determine inorganic lead
emissions from stationary sources.
Particulate and gaseous lead emissions
are withdrawn isokinetically from the
source. The collected samples are then
digested in acid solution and analyzed
by atomic absorption spectrometry
using an air acetylene flame. For a
minimum analysis accuracy of ±10
percent, a minimum lead mass of lOpg
should be collected. The typical
sensitivities for a 1 percent change in
absorption (0.0044 absorbance units) are
0.2 and 0.5 fjg Pb/ml for the 217.0 and
2P3 3 nm lines, respectively.
The laboratory precision for Method
12, as measured by the coefficient of
variation, was determined at a gray iron
foundry, a lead battery manufacturing
plant, a secondary lead smelter, and a
lead recovery furnace at an alkyl lead
manufacturing plant. The concentrations
encountered during these tests ranged
from 0.61 to 123.3 jig/Pb/m s. The
coefficient of variation for each run,
which is the standard deviation of the
run expressed as a percentage of the run
mean concentration, ranged from 0.2 to
9.5 percent.
High copper concentrations may
interfere with the analysis of lead at
217.0 nm. This interference can be
avoided by analyzing the samples for
lead using the 283.3 nm lead line. This
problem should not occur, however,
when analyzing samples from lead-acid
battery facilities.
Records of performance tests and
continuous monitoring system
measurements would have to be
retained for at least 2 years following
the date of the measurements by owners
and operators subject to this subpart.
This requirement is included under
§ 60.7(d) of the general provisions of
Pert 60.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
Section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing Written statements should
be addressed to the Central Docket
Section (A-130), U.S. Environmental
Protection Agency, 401 M Street, S.W.,
Washington, D.C. 20450, Attention:
Docket No. OAQPS-79-1.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section, Room 2903B, Waterside
Mall, 401 M Street, S.W., Washington,
D.C. 20460.
Docket
The docket, containing all supporting
information used by EPA to date, is
available for inspection and copying
between 8:00 a.m. and 4:00 p.m., Monday
through Friday, at EPA's Central Docket
Section, room 2903B, Waterside Mall,
401 M Street, S.W., Washington, D.C.
20460.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
EPA in the development of the
rulemaking. The docket is a dynamic
file, since material is added throughout
the rulemaking development.
The docketing system is intended to
aiiow members of the public and
industries involved to readily identify
and locate documents so that they can
intelligently and effectively participate
in the rulemaking process. On judicial
review, the record will consist of all
materials in the docket except for
certain interagency review materials
(section 307(d)(7)(A) of the Act).
Miscellaneous
In accordance with section 117 of the
Act, publication of these proposed
standards was preceded by consultation
with appropriate advisory committees,
independent experts, and Federal
departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation, including economic and
technological issues, and on the
proposed test method.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Act reflect:
* * * application of the best adequately
demonstrated technological system of
continuous emission reduction which (taking
into consideration the cost of achieving such
emission reduction, any nonair quality health
and environmental impact, and energy
requirements) the Administrator determines
has been adequately demonstrated (section
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance because of costs
associated with its use. Accordingly,
standards of performance should not be
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viewed as the ultimate in achievable
emission control. In fact, the Act
requires (or has the potential for
requiring) the imposition of a more
stringent emission standard in several
situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emissions rate" for new or modified
sources located in nonattainment areas,
i.e., those areas where statutorily
mandated health and welfare standards
are being violated.
In this respect, section 173 of the Act
requires that a new or modified source
constructed in an area that exceeds the
National Ambient Air Quality Standards
(NAAQS) must reduce emissions to the
level which reflects the "lowest
achievable emission rate" (LAER), as
defined in section 171(3), for such
category of source. The statute defines
LAER as that rate of emissions based on
the following, whichever is more
stringent:
(A) 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
(B) the most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" [as defined in
section 163(3)] for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants that will exceed the emissions
allowed by any applicable standard
established pursuant to section 111 (or
112) of the Act.
In all events, State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
required greater emission reductions
than those require by standards of
performance of new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
EPA will review this regulation 4
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for any
new source standard of performance
promulgated under section lll(b) of the
Act. An economic impact assessment
was prepared for the proposed
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the proposed standards
to insure that the proposed standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the background information
document.
Dated: December 19,1979.
Douglas M. Costle,
Administrator.
It is proposed that 40 CFR Part 60 be
amended by adding a new Subpart KK
and by adding a new reference method
to Appendix A as follows:
1. A new subpart KK is added as
follows:
Subpart KK—Standards of
Performance for Lead-Acid Battery
Manufacturing Plants
Sec.
60.370 Applicability and designation of
affected facility.
60 371 Definitions.
60.372 Standards for lead.
60.373 Monitoring of emissions and
operations.
60.374 Test methods and procedures.
Authority: Sec. Ill, 301(a), Clean Air Act
as amended [42 U.S.C. 7411, 7601(a)], and
additional authority as noted below.
Subpart KK—Standards of
Performance for Lead-Acid Battery
Manufacturing Plants
§ 60.370 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the affected facilities listed
in paragraph (b) of this section at any
lead-acid battery manufacturing plant
that has the capacity to produce 500 or
more batteries per day (24 hours).
(b) The provisions of this subpart are
applicable to the following affected
facilities used in the manufacture of
lead-acid storage batteries:
(1) Grid casting facility
(2) Paste mixing facility
(3) Three-process operation facility
(4) Lead oxide manufacturing facility
(5) Lead reclamation facility
(6] Other lead-emitting operations
§ 6Q.371 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Grid casting facility" means the
facility which includes both lead melting
pots and machines used for casting the
grids used in battery manufacturing.
(b) "Lead-add battery manufacturing
plant" means any plant that produces a
storage battery using lead and lead
compounds for the plates and sulfuric
acid for the electrolyte.
(c) "Lead oxide manufacturing
facility" means the facility that produces
lead oxide from lead, including product
recovery.
(d) "Lead reclamation facility" means
the facility that remelts lead scrap and
casts it into lead ingots for use in the
battery manufacturing process, and
which is not a furnace affected under
Subpart L of this part.
(e) "Other lead-emitting operation"
means any lead-acid battery
manufacturing plant operation from
which lead emissions are collected and
ducted to the atmosphere and which is
not part of a grid casting, lead oxide
manufacturing, lead reclamation, paste
mixing, or three-process operation
facility, or a furnace affected under
Subpart L of this part.
(f) "Paste mixing facility" mesns the
facility including charging and blending
of the ingredients to produce a lead
oxide paste.
(g) "Three-process operation facility"
means the facility including those
processes involved with plate stacking,
burning or strap casting, and assembly
of elements into the battery case.
§ 60.372 Standards for lead.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any grid casting facility any
gases that contain lead in excess of 0.05
milligram of lead per dry standard cubic
meter of exhaust (0.00002 gr/dscf)-
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Federal Register / Vol. 45. No. 9 / Monday, January 14, 1980 / Proposed Rules
(2) From any paste mixing facility any
g-isrs that contain in excess of 1.00
nv.lligiam of lead per dry standard cubic
meter of exhaust (0.00044 gr/dscf).
(3) From any three-process operation
facility any gases that contain in excess
of 1.00 milligram of lead per dry
standard cubic meter of exhaust (0.00044
gr/dscf).
(4) From any lead oxide
manufacturing facility any gases that
contain in excess of 5.0 milligrams of
lead per kilogram of lead feed (0.010 lb/
ton).
(5) From any lead reclamation facility
any gases that contain in excess of 2.00
milligrams of lead per dry standard
cubic meter of exhaust {0.00088 gr/dscf).
(6) From any other lead-emitting
operation any gases that contain in
excess of 1.00 milligram per dry
standard cubic meter of exhaust (0.00044
gr/dscf).
(7) From any affected facility any
gases with greater than 0 percent
opacity (measured according to Method
9 and rounded to the nearest whole
percentage).
(b) When two or more facilities at the
same plant (except the lead oxide
manufacturing facility) are ducted to a
common control device, and equivalent
standard for the total exhaust from the
commonly controlled facilities shall be
determined as follows:
S, =
Where:
Se is the equivalent standard for the total
exhaust stream.
S, 18 the actual standard for each exhaust
stream ducted to the control device.
N is the total number of exhaust streams
ducted to the control device.
Qsd|) is t!:e dry standard volumetric flow rate
of the e'f.uent gas stream from each
facility ducted to the control device.
Qhdr is the total dry standard volumetric flow
rate of all effluent gas streams dueled to
the control device.
§ 60.373 Monitoring of emissions and
operations.
The owner or operator of any lead-
acid battery manufacturing plant subject
to the provisions of this subpart shall
install, calibrate, maintain, and operate
a monitoring device(s) that continuously
measures and premanently records the
toted pressure drop across the process
emissions control system. The
monitoring device shall have an
r is the lead emission concentration for
the entire facility.
N is the number of control devices to which
separate operations in the facility are
ducted.
C|.b is the emission concentration from each
conlroi device.
QKlt(i is the dry standard volumetric flow rate
of tf.e effluent gas stream trom each
control device.
Qsdl is the total dry standard volumetric flow
rate from all of the control devices.
(e] For lead oxide manufacturing
facilities, the average lead feed rate to a
facility, expressed in kilograms per hour,
shall be determined for each test run as
follows:
(1) Calculate the total amount of lead
charged to the facility during the run by
multiplying the number of lead pigs
(ingots) charged during the run by the
average mass of a pig in kilograms or by
another suitable method.
(2) Divide the total amount of lead
charged to the facility during the run by
the duration of the run in hours.
(f) Lead emissions from lead oxide
manufacturing facilities, expressed in
milligrams per kilogram of lead charged.
shall be determined using the following
equation:
£„ = CwCVF
Where:
£,.„ is the lead emission rate from the facility
in milligrams per kilogram of lead
charged.
Cn is the concentration of lead in the exhaust
stream in milligrams per dry standard
cubic meter as determined according to
paragraph (a)(l) of this section.
Qsd is the dry standard volumetric flow rate
in dry standard cubic meters per hour as
determined according to paragraph (a)(3)
of this section.
F is the lead feed rate to the facility in
kilograms per hours as determined
according to paragraph (e) of this section.
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 7414))
2. Appendix A to Part 60 is amended
by adding new Reference Method 12 as
follows:
Appendix A—Reference Methods
*****
Method 12. Determination of Inorganic Lead
Emissions from Stationary Sources
1. Applicability and Principle
11 Applicability. This method applies to
the determination of inorganic lead (Pb)
emissions from specified stationary sources
only.
1.2 Principle. Particulate and gaseous Pb
emissions are withdrawn isokinetically from
the source and coliected on a filter and in
dilute nitric acid. The collected samples are
digested in acid solution and analyzed by
atomic absorption spectrometry using an air
acetylene flame.
2 Range. Sensitivity, Precision, and
interferences
2.1 Flange. For a minimum analytical
accuracy of ±10 percent, the lower limit of
the range is 100 ng. The upper limit can be
considerably extended by dilution.
2.2 Analytical Sensitivity. Typical
sensitivities for a 1-percent change in
absorption (0.0044 absorbance units) are 0.2
and 0.5 fig Pb/ml for the 217.0 and 283.3 nm
lines, respectively.
2.3 Precision. The within-laboratory
precision, as measured by the coefficient of
variation ranges from 0.2 to 9.5 percent
relative to a run-mean concentration. These
values were based on tests condufed at a
gray iron foundry, a lead storage b.'.'u-ry
manufacturing plant, a secondary k;,d
smelter, and a lead rivoxerv furnace of an
alk\l lead manufacturing pl:.n! Iht:
concentrations encountered during these
tests ranged from 0.61 to 123.3 mg Pli/ms.
2.4 Interferences. Sample matrix effects
may interfere with the analysis for Pb by
flume atomic absorption. If this interference
is suspected, the analjst may confirm the
presence of these matrix effects and
frequently eliminate the interference by using
the Method of Standard Additions.
High concentrations of copper may
interfere with the analysis of Pb at 217.0 nm.
This interference can be avoided by
analyzing the samples at 2B3.3 nm.
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3. Appoiatus
3.1 Sampling Train. A schematic of the
sampling tram is shown in Figure 12-1; it is
similar to the Method 5 train. The sampling
train consists of the following components:
3.1.1 Probe Nozzle, Probe Liner, Pilot
Tube, Differential Pressure Gauge, Filter
Holder, Filter Heating System, Metering
System, Barometer, and Gas Density
Determination Equipment. Same as Method
5, Sections 2.1.1 to 2.1.6 and 2.1,8 to 2.1.10,
respectively.
3.1.2 Jmpingers. Four impingers connected
in series with leak-free ground glass fittings
or any similar leak-free noncontaminating
fittings. For the first, third, and fourth
impingers, use the Greenburg-Smith design,
modified by replacing the tip with a 1.3 cm
('/s in.) ID ghss tube extending to about 1.3
cm ('/a in.) from the bottom of the flask. For
the second impinger, use the Greenburg-
Smith design with the standard tip. Place a
thermometer, capable of measuring
temperature to within 1'C (2°F) at the outlet
of the fourth impinger for monitoring
purposes.
TEMPERATURE SENSOR
PROBE
TEMPERATURE
SENSOR
PROBE /\
HEATED AREA THERMOMETER
THERMOMETER
PITOTTUBE
REVERSE TYPE j
PITOTTUBE I
IMPINGERS ICE BATH
BY-PASS VALVE
CHECK
VALVE
VACUUM
LINE
PITOT MANOMETER
ORIFICE
VACUUM
GAUGE
THERMOMETERS
MAIN VALVE
DRY GAS METER
AIRTIGHT
PUMP
Figure 12-1. Inorganic lead sampling train.
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3.2 Sample Recovery. The following items
are needed:
3.2.1 Probe-Liner and Probe-Nozzle
Brushes, Petri Dishes, Plastic Storage
Containers, and Funnel and Rubber
Policeman. Same 88 Method 5, Sections 2.2.1,
2.2.4, 2.2.6, and 2.2.7, respectively.
3.2.2 Wash Bottles. Glass (2).
3.2.3 Sample Storage Container.
Chemically resistant, borosilicate glass
bottles, for 0.1 N nitric acid (HNO9) impinger
and probe solutions and washes, 1000-ml.
Use screw-cap liners that are either rubber-
backed Teflon ' or leak-free and resistant to
chemical attack by 0.1 N HNO.. (Narrow
mouth glass bottles have been found to be
less prone to leakage.)
3.2.4 Graduated Cylinder and/or Balance.
To measure condensed water to within 2 ml
or 1 g. Use a graduated cylinder that has a
minimum capacity of 500 ml, and
subdivisions no greater than 5 ml. (Most
laboratory balances are capable of weighing
to the nearest 0.5 g or less.)
3.2.5 Funnel. Glass, to aid in sample
recovery.
3.3 Analysis, The following equipment is
needed:
3.3.1 Atomic Absorption
Spectrophotometer. With lead hollow
cathode lamp and burner for air/acetylene
flame.
3.3.2 Hot Plate.
3.3.3 Erlenmeyer Flasks. 1 25-ml, 24/40 $.
3.3.4 Membrane Filters. Millipore SCWPO
4700 or equivalent.
3.3.5 Filtration Apparatus. Millipore
vacuum filtration unit, or equivalent, for use
with the above membrane filter.
3.3.6 Vomumetric Flasks. 100-ml, 250-ml,
and 1000-ml.
4. Reagents
4.1 Sampling. The reagents used in
sampling are as follows:
4.1.1 Filter. Gelman Spectro Grade, Reeve
Angel 934 AH, MSA 1106 BH, all with lot
assay for Pb, or other high-purity glass fiber
filters, without organic binder, exhibiting at
least 99.95 percent efficiency (<0.05 percent
penetration) on 0.3 micron dioctyl phthalate
smoke particles. Conduct the filter efficiency
test using ASTM Standard Method D 2986-71
or use lo?t data from the supplier's quality
control program.
4.1.2 Silica Gel, Crushed Ice, and
Stopcock Grease. Same as Method 5, Section
3.1.2, 3.1.4, and 3.1.5, respectively.
4.1.3 Water. Deionized distilled, to
conform to ASTM Specification D1193-74,
Type 3. If high concentrations of organic
matter are not expected to be present, the
analyst may delete the potassium
permanganate test for oxidizable organic
matter.
4.1.4 Nitric Acid, 0.1 N. Dilute 6.5 ml of
concentrated HNO, to liter 1 with deionized
distilled water. (It may be desirable to run
blanks before field use to eliminate a high
blank on test samples.)
4.2 Pretest preparation. 6 HNOS is
needed. Dilute 390 ml of concentrated HNO,
to 1 liter with deionized distilled water.
1I.isntion of trade names or specific products
does not constitute endorsement by the U.S.
Environmental Protection Agency.
4.3 Sample Recovery. 0.1 N HNOi (same
as 4.1.4 above) is needed for sample recovery.
4.4 Analysis. The following reagents are
needed for analysis (use ACS reagent grade
chemicals or equivalent, unless otherwise
specified):
4.4.1 Water. Same as 4.1.3 above.
4.4.2 Nitric Acid. Concentrated.
4.4.3 Nitric Acid, 50 percent (V/V). Dilute
500 ml of concentrated HNO, to 1 liter with
deionized distilled water.
4.4.4 Stock Lead Standard Solution, 1000
tig Pb/ml. Dissolve 0.1598 g of lead nitrate
[Pb(NO,)»] in about 60 ml of dionized distilled
water, add 2 ml concentrated HNOs, and
dilute to 100 ml with deionized distilled
water.
4.4.5 Working Lead Standards. Pipet 0.0,
1.0, 2.0, 3.0, 4.0. and 5.0 ml of the stock lead
standard solution (4.4.4) into 250-ml
volumetric flasks. Add 5 ml of concentrated
HNO, to each flask and dilute to volume with
deionized distilled water. These working
standards contain 0.0,4.0, 8.0,12.0,16.0, and
20.0 u.g Pb/ml, respectively. Prepare, as
needed, additional standards at other
concentrations in a similar manner.
4.4.6 Air. Suitable quality for atomic
absorption analysis.
4.4.7 Acetylene. Suitable quality for
atomic absorption analysis.
4.4.8 Hydrogen Peroxide, 3percent (V/V).
Dilute 10 ml of 30 percent H»O, to 100 ml with
deionized distilled water.
5. Procedure
5.1 Sampling. The complexity of this
method is such that, in order to obtain
reliable results, testers should be trained and
experienced with the test procedures.
5.1.1 Pretest Preparation. Follow the same
general procedure given in Method 5, Section
4.1.1, except the filter need not be weighed.
5.1.2 Preliminary Determinations. Follow
the same general procedure given in Method
5, Section 4.1.2.
5.1.3 Preparation of Collection Train.
Follow the same general procedure given in
Method 5, Section 4.1.3, except place 100 ml
of 0.1 HNOs in each of the first two
impingers, leave the third impinger empty,
and transfer approximately 200 to 300 g of
preweighed silica gel from its container to the
fourth impinger. Set up the train as shown in
Figure 12-1.
5.1.4 Leak-Check Procedures. Follow the
general leak-check procedures given in
Method 5, Sections 4.1.4.1 (Pretest Leak-
Check), 4.1.4.2 (Leak-Checks During the
Sample Run), and 4.1.4.3 (Post-Test Leak-
Check).
5.1.5 Sampling Train Operation. Follow
the same general procedure given in Method
5, Section 4.1.5. For each run, record the data
required on a data sheet such as the one
shown in EPA Method 5, Figure 5-2.
5.1.8 Calculation of Percent Isokinetic.
Same as Method 5, Section 4.1.6.
5.2 Sample Recovery. Begin proper
cleanup procedure as soon as the probe is
removed from the stack at the end of the
sampling period.
Allow the probe to cool. When it can be
safety handled, wipe off all external
particulate matter near the tip of the probe
nozzle and place a cap over it. Do not cap off
the probe tip tightly while the sampling train
is cooling down as this would create a
vacuum in the filter holder, thus drawing
liquid from the impingers into the filter.
Before moving the sampling train to the
cleanup site, remove the probe from the
sampling train, wipe off the silicone grease,
and cap the open outlet of the probe. Be
careful not to lose any condensate that might
be present. Wipe off the silicone grease from
the glassware inlet where the probe was
fastened and cap the inlet Remove the
umbilical cord from the last impinger and cap
the impinger. The tester may use ground-glaH
stoppers, plastic caps, or serum caps to close
these openings.
Transfer the probe and filter-impinger
assembly to a cleanup area, which is clean
and protected from the wind so that the
chances of contaminating or losing the
sample is minimized.
Inspect the train prior to and during
disassembly and note any abnormal
conditions. Treat the samples as follows:
5.2.1 Container No. 1 (Filter). Carefully
remove the filter from the filter holder and
place it in its identified petri dish container. If
it is necessary to fold the filter, do so such
that the sample-exposed side is inside the
fold. Carefully transfer to the petri dish any
visible sample matter and/or filter fibers that
adhere to the filter holder gasket by using a
dry Nylon bristle brush and/or a sharp-edged
blade. Seal the container,
6.2.2 Container No. 2 (Probe). Taking can
that dust on the outside of the probe or other
exterior surfaces does not get into the
sample, quantitatively recover sample matter
or any condensate from the probe nozzle,
probe fitting, probe liner, and front half of the
filter holder by washing these components
with 0.1 N HNO. and placing the wash into a
glass sample storage container. Measure and
record (to the nearest 2-ml) the total amount
of 0.1 N HNO. used for each rinse. Perform
the 0.1 N HNO. rinses as follows:
Carefully remove the prebe nozzle and
rinse the inside surfaces with 0.1 N HNO.
from a wash bottle while brushing with a
stainless steel, Nylon-bristle brush. Brush
until the 0.1 N HNO, rinse shows no visible
particles, then make a final rinse of the inside
surface.
Brush and rinse with 0.1 N HNO. the inside
parts of the Swagelok fitting in a similar way
until no visible particles remain.
Rinse the probe liner with 0.1 N HNO..
While rotating the probe so that all inside
surfaces will be rinsed with 0.1 N HNO,, tilt
the probe and squirt 0.1 N HNO. into its
upper end. Let the 0.1 N HNO. drain from the
lower end into the sample container. The
tester may use a glass runnel to aid in
transferring liquid washes to the container.
Follow the rinse with a probe brush. Hold the
probe in an inclined position, squirt 0.1 N
HNO, into the upper end of the probe as the
probe brush is being pushed with a twisting
action through the probe; hold the sample
container underneath the lower end of the
probe and catch any 0.1 N HNO. and sample
matter that is brushed from the probe. Run
the brush through the probe three times or
more until no visible sample matter is carried
out with the 0.1 N HNO, and none remains on
the probe liner on visual inspection. With
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stainless steel or other metal probes, run the
brush through in the above prescribed
manner at least six times, since metal probes
have small crevices in which sample matter
can be entrapped. Rinse the brush with 01 N
HNOj and quantitatively collect these
washings in the sample container. After the
brushing make a final rinse of the probe as
described above.
it is recommended that two people clean
the probe to minimize loss of sample.
Between sampling runs, keep brushes clean
and picitected from contamination.
After insuring that all joints are wiped
clean of siiicone grease, brush and rinse with
0.1 N HNO> the inside ot the front half of the
filter holder. Brush and rinse each surface
three times or more, if needed, to remove
visible sample matter. Make a final rinse of
the brush and filter holder. After ail 01 N
HNO» washings and sample matt™ are
collected in the sample container, tighten the
lid on the sample container so that the fluid
will not leak out when it is shipped to the
laboratory. Mark the height of the fluid level
to determine whether leakage occurs during
transport. Label the container to clearly
identify its contents.
5.2.3 Container No. 3 (Silica Cell. Check
the color of the indicating silica gel to
determine if it has been completely spent and
make a notation of its condition. Transfer the
silica gel from the fourth impinger to the
original container and seal. The tester may
use a funnel to pour the silica gel and a
rubber policeman to remove the silica gel
from the impinger. It is not necessary to
remove the small amount of particles that
may adhere to the walls and are difficult to
remove. Since the gain in weight is to be used
for moisture calculations, do not use any
water or other liquids to transfer the silica
gel. If a balance is available in the field, the
tester may follow procedure for Container
No. 3 under Section 5 4 (Analysis).
5.2.4 Container No, 4 (Impingers) Due to
the large quantity of liquid involved, the
tester may place the impinger solutions in
several containers. Clean each of the first
three impir.gers and connecting glassware in
the following manner:
1. Wipe the impinger bdll joints free of
siiicone grease and cap the joints.
2. RMcile and agitate each impinger, so that
the irr.pifisjer contents might serve as a rinse
solution.
3. Transfer the contents of the impingers to
a 500-ml graduated cylinder. Remove the
outlf.-t ball joint cap and drain the contents
through this opening. Do not separate the
impinger parts (inner and outer tubes) while
transferring their contents to the cylinder.
Measure the liquid volume to within ± 2 ml.
Alternatively, determine the weight of the
liquid to within ± 0.5 g Record in the log the
volume or weight of the liquid present, along
with a notation of any color or film observed
in the impinger catch. The liquid volume or
weight is needed, along with the silica gel
data, to calculate the stack gas moisture
content (see Method 5, Figure 5-3).
4. Transfer the contents to Container No. 4.
5. Note: In steps 5 and 6 below, measure
and record the total amount of O.I N H.\'O3
used for rinsing. Pour approximately 30 mi of
0.1 N HNOi into each of the first three
impingers and agitate the impingers. Drain
the 0.1 N HN'Oj through the outlet arm of
each impinger into Container No. 4. Repeat
this operation a second time; inspect the
irn; :ngers for any abnormal conditions.
6. Wipe the ball joints of the glassware
connecting the impingers free of siiicone
grtjse and rinse each piece of glassware
twice with 0.1 N HNOa: transfer this rinse
into Container No. 4. (Do not rinse or brush
the gloss-fritted filter support.} Mark the
height of the fluid level to determine whether
leakage occuis during transport Label the
container to clearly identify its contents.
5.2.5 Blanks. Save 200 ml of the 0.1 N
HXOj used for sampling and cleanup as a
bhnk. Take the solution directly from the
bottle being used and place into a glass
Scimp'e container labeled "0.1 N HNOa
blank."
5 3 Sample Preparation.
5.3.1 Container No. 1 (Filter). Cut the filter
into strips and transfer the strips and all
loose pailiculatc matter into an 125-ml
E'ienmeyer flask. Rinse the petri dish with 10
ml of 50 percent HNO3 to insure a
quantitative transfer and add to the flask.
(\'ote. If the total volume required in Section
5 3.3 is expected to exceed 80 ml, use a 250-ml
Erlenmej er flask in place of the 125-nil Husk.)
5 3.2 Containers No, 2 and No. 4 (Probe and
ImpingiTs). (Check the liquid level in
Containers No. 2 and/or No. 4 and confirm as
to whether or not leakage occurred during
transport; note observation on the analysis
sheet. If a noticeable amount of leakage had
occurred, either void the sample or take
steps, subject to the approval of the
Administrator, to adjust the final results.)
Combine the contents of Containers No. 2
and \o. 4 and take to diyncss on a hot plate.
5.3.3 Sample Extraction for Lead. Based
on the approximate stack gas parliculdte
concentration and the total volume of stack
gas sampled, estimate the total weight of
pnriicula'.e sample collected. Then transfer
the residue from Containers No. 2 and No. 4
to the 12Vml Erlenmeyer flask tlut contains
the filter using rubber policeman and 10 mi of
50 percent HNOS for every 100 mg of sample
co'lectfd in the train or a minimum of 30 ml
of &0 percent HNO3. whichever is laiger.
Place the Erlenmeyer fl«isk on a hot plate
and heat with periodic stirring for 30 roin at a
tempprature just below boiling l! the s.trrtple
voUur,^ falls below 15 ml, add more 50
pr-cenl HNO3. Add 10 ml of 3 percent I (2O2
and continue heating for 10 mm. Add 50 ml of
hot (30°C) deionized distilled water and heat
foi 20 min. Remove the flask from the hot
plate and allow to cool. Filter the sample
through a Millipore membrane filter or
equivalent and transfer the filtrate to a 250-
ml volumetric flask. Dilute to volume wish
de.om/t-d distilled water.
534 filter Blank. Determine a filter bltmk
ur.in« two filters from each lot of filters used
in the sampling tram. Cut each filter into
stiips and place efioh filter in a separate 125-
m! Erlenrnpypt fljsk. Add 15 ml of 50 percent
H.\O3 and Ue.it as described in Section 5.3 3
us;ne 10 ml of 3 percent li,Q: and 50 ml of
hot, deuiMxed distilled water. Filter and
dilute In a total volume of 10U ml using
di.inni7<;d distilled water.
5/3.5 0.1 A' W.'vOa Blank. Take the entire
200 ml of 0 1 N HNOj to drvni ss on a steam
bath, ddd 15 ml of 50 percent HNO3, and (rent
as described in Section 5.3 3 using 10 m! of 3
percent }i,O, and 50 ml of hot, deionized
distilled water. Dilute to a total volume of 100
ml using deionized distilled water.
5.4 Analysis.
5.4 1 Lead Determination. Calibrate the
Epectrophotomcter as described in Section 6.2
and determine the absorbance for each
source sample, the filter blank, and 0.1 N
Hf\O3 blank. Analyze each sample three
times in this manner. Make appropriate
dilutions, as required, to bring all sample Pb
concentrations into the linear absorbance
range of the spectrophotometer.
If the Pb concentration of a sample is at the
low end of the calibration curve and high
accuracy is required, the sample can be taken
to dryness on a hot plate and the residue
dissolved in the appropriate volume of water
to bnr.g it into the optimum range of the
calibration curve.
5.4.2 Mandatory Check for Matrix Effects
on the Lead Results. The analysis for Pb by
atomic absorption is sensitive to the chemical
composition and to the physical properties
(viscosity, pH) of the sample (matrix effects).
Since the Pb procedure described here will be
applied to many different sources, many
sample matiices will be encountered. Thus,
check (mandatory'} at least one sample from
each souice using the Method of Additions to
ascertain that the chemical composition and
physical properties of the sample did not
cause erroneous analytical results.
Three acceptable "Method of Additions"
procedures are described in the General
Procedure Section of the Perkin Elmer
Corporation Manual (see Citation 9.1). If the
results of the Method of Additions procedure
on the source sample do not agree within 5
percent of the value obtained by the
conventional atomic absorption analysis,
then the tester nvjst reanalyze all samples
from the source using the Method of
Additions procedure.
5.4.3 Container No. 3 (Silica Get). The
tester may conduct this step in the field.
Weigh the spent silica gel (or silica gel plus
ipipinjji '.') to the nearest 0.5 g; record this
weight.
6. Calit'iolJon
Maintain a laboratory log of all
cahura'ions.
6.1 Sampling Train Calibration. Calibrate
the sampling train components according to
the indicated sections of Method 5. Probe
Nozrle (Section 5.1); Pilot Tube (Sec!;on 5.2);
Mtter'pg S>>tem (Section 5.3); Probe Heater
(Section 5.4): Temperature Gauges (Section
5.:); Lenk-Check of the Metering System
(Section 5 6); and Barometer (Section 5.7).
6.2 Spec.tropliolomp'ur. Measure the
alisoibance of the standard solutions using
the instrument settings recommended by the
specUophotometer manufacturer. Repeat
until good agreement (± 3 percent) is
obtained between two consecutive readings
Plot the dbsoibane.e (y-axis) versus
concentration in ng Pb/m! (x-axis). Draw or
compute a straight line through the linear
portion of the cm vi:. Do no! force the
calibration curve ilirouyi 1'fro, but if the
curve does not pass thrcn-gli the origin or at
IfKst he closer to the origin than ± 0.003
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
absorbance units, check for incorrectly
prepared standards and for curvature in the
calibration curve.
To determine stability of the calibration
curve, run a blank and a standard after every
five samples and recalibrate, as necessary.
7. Calculations
7.1 Dry Gas Volume. Using the data from
this test, calculate Vm, the total volume of
dry gas metered corrected to standard
conditions (20 °C and 760 mm Hg), by using
Equation 5-1 of Method 5. If necessary, adjust
Vm(,Ki) for leakages as outlined in Section 6.3
of Method 5. See the field data sheet for the
average dry gas meter temperature and
average orifice pressure drop.
7.2 Volume of Water Vapor and Moisture
Content. Using data obtained in this test and
Equations 5-2 and 5-3 of Method 5, calculate
the volume of water vapor V^,^ and the
moisture content Bw, of the stack gas.
7.3 Total Lead in Source Sample. For
each source sample correct the average
absorbance for the contribution of the filter
blank and the 0.1 N HMO, blank. Use the
calibration curve and this corrected
absorbance to determine the ng Pb
concentration in the sample aspirated into
the spectrophotometer. Calculate the total Pb
content C°Pb ('n Hg) in the original source
sample; correct for all the dilutions that were
made to bring the Pb concentration of the
sample into the linear range of the
spectrophotometer.
7.4 Lead Concentration. Calculate the
stack gas Pb concentration Cn in mg/dscm
as follows:
Cn,=K
c-rb
Eq.12-1
Where:
K=0.001 mg/ng for metric units.
= 2.205 lb/fig for English units.
7.5 Isokinetic Variation and Acceptable
Results. Same as Method 5, Sections 6.11 and
6.12, respectively. To calculate v,, the average
stack gas velocity, use Equation 2-9 of
Method 2 and the data from this field test.
A Alternative Test Methods for Inorganic
Lead
8.1 Simultaneous Determination of
Particulate and Lead Emissions. The tester
may use Method 5 to simultaneously
determine Pb provided that (1) he uses 0.1 N
HNO3 in the impingers, (2) he uses a glass
fiber filter with a low Pb background, and (3)
he treats and analyzes the entire train
contents, including the impingers, for Pb as
described in Section 5 of this method.
8.2 Filter Location. The tester may use a
filter between the third and fourth impinger
provided that he includes the filter in the
analysis for Pb.
8.3 In-stock Filter. The tester may use an
in-stack filter provided that (1) he uses a
glass-lined probe and at least two impingers,
each containing 100 ml of 0.1 N HNO3, after
the in-stack filter and (2) he recovers and
analyzes the probe and impinger contents for
Pb.
ft Bibliography
9.1 Perkin Elmer Corporation. Analytical
Methods for Atomic Absorption
Spectrophotometry. Norwalk, Connecticut.
September 1976.
9.2 American Society for Testing and
Materials. Annual Book of ASTM Standards.
Part 31; Water, Atmospheric Analysis.
Philadelphia, Pa. 1974. p. 40-42.
9.3 Klein. R. and C. Hack. Standard
Additions—Uses and Limitations in
Spectrophotometric Analysis. Amer. Lab.
9:21-27.1977.
9.4 Mitchell, W. J. andM. R. Midgett.
Determining Inorganic and Alkyl Lead
Emissions from Stationary Sources. U.S.
Environmental Protection Agency, Emission
Monitoring and Support Laboratory. Research
Triangle Park, NC. (Presented at National
APCA Meeting. Houston. June 26,1978.)
9.5 Same as Method 5, Citations 2 to 5
and 7 of Section 7.
*****
(Sections 111, 114, and 301(a) of the Clean Air
Act as amended (42 U.S.C. 7411, 7414, and
7601(a)))
(FR Doc. 80-1078 Filed 1-11-80; &45 am)
BILLING CODE 6560-01-M
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
AUTOMOBILE AND LIGHT-DUTY TRUCK
SURFACE COATING OPERATIONS
SUBMRTMM
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Federal Register / Vol. 44, No. 195 / Friday. October 5.1979 / Proposed Rules
40 CFR Part 60
[FRL-1285-4]
Automobile and Light-Duty Truck
Surface Coating Operations;
Standards of Performance
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: Standards of performance are
proposed to limit emissions of volatile
organic compounds (VOC) from new,
modified, and reconstructed automobile
and light-duty truck surface coating
operations within assembly plants.
Three new test methods are also
proposed. Reference Method 24
(Candidate 1 or Candidate 2) would be
used to determine the VOC content of
coating materials, and Reference
Method 25 would be used to determine
the percentage reduction of VOC
emissions achieved by add-on emission
control devices.
The standards implement the Clean
Air Act and are based on the
Administrator's determination that
automobile and light-duty truck surface
coating operations within assembly
plants contribute significantly to air
pollution. The intent is to require new,
modified, and reconstructed automobile
and light-duty truck surface coating
operations to use the best demonstrated
system of continuous emission
reduction, considering costs, nonair
quality health, and environmental and
energy impacts.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before December 14,
1979
Public Hearing. The public hearing
will be held on November 9. 1979, at 9
a.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony should
contact EPA by November 2,1979
ADDRESSES: Comments. Comments
should be submitted to: Central Docket
Section (A-130), Attention: Docket
Number A-79-05, U.S. Environmental
Protection Agency, 401 M Street SW.,
Washington, D.C. 20460.
Public Hearing. The public hearing
will be held at National Environmental
Resource Center (NERC), Rm. B-102,
R.T.P., N.C. Persons wishing to present
oral testimony should notify Ms. Shirley
Tabler, Emission Standards and
Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5421.
Background Information Document.
The Background Information Document
(BID) for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park. North
Carolina 27711, telephone number (919)
541-2777. Please refer to "Automobile
and Light-Duty Truck Surface Coating
Operations—Background Information
for Proposed Standards," EPA-450/3-
79-030.
Docket. The Docket, number A-79-05.
is available for public inspection and
copying at the EPA's Central Docket
Section, Room 2903 B, Waterside Mall,
Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards would apply
to new automobile and light-duty truck
surface coating operations. Existing
plants would not be covered unless they
undergo modifications resulting in
increased emissions or reconstructions.
The proposed standards would apply to
each prime coat operation, each guide
coat operation, and each topcoat
operation within an assembly plant.
Emissions of VOC from each of these
operations would be limited as follows:
0.10 kilogram of VOC (measured as
mass of carbon) per liter of applied
coating solids from prime coat
operations. 0.84 kilogram of VOC
(measured as mass of carbon) per liter
applied coating solids from guide coat
operations, 0.84 kilogram of VOC
(measured as mass of carbon) per liter
of applied coating solids from topcoat
operations.
These proposed emission limits are
based on Method 24 (Candidate 1)
which determines VOC content of
coatings expressed as the mass of
carbon. At the time the standards were
developed, it was believed that VOC
emissions should be determined from
carbon measurements. Method 24
(Candidate 1) was developed to measure
carbon directly and thus improve the
accuracy of the previously used ASTM
procedure D 2369-73, which measures
the mass of volatile organics indirectly.
However, questions have been raised
concerning the validity of using the
carbon method since the ratio of mass of
carbon to mass of VOC in solvents used
in automotive coatings varies over a
wide range. The effect which this
variation might have on the standards is
still being investigated. Method 24
(Candidate 2) was developed as a test
method for determining VOC emissions
from coating materials in terms of mass
of volatile organics and is also derived
from ASTM procedure D 2369-73. The
proposed emission limits, based on
Method 24 (Candidate 2) which
measures volatile organics, are. 0.16
kilogram of VOC per liter of applied
coating solids from prime coat
operations, and 1.36 kilogram of VOC
per liter of applied coating solids for
guide coat operations, and 1.36 kilogram
of VOC per liter of applied coating
solids from top coat operations. In order
to provide an opportunity for public
comment on both test methods, both are
being proposed, and the final selection
of a test method will be made before
promulgation, based on the comments
received.
Although the emission limits are
based on the use of water-based coating
materials in each coating operation, they
can also be met with solvent-based
coating materials through the use of
other control techniques, such as
incineration. Exemptions are included in
the proposed standards which
specifically exclude annual model
changeovers from consideration as
modifications.
Summary of Environmental, Energy, and
Economic Impacts
Environmental, energy, and economic
impacts of standards of performance are
normally expressed as incremental
differences between the impacts from a
facility complying with the proposed
standard and those for one complying
with a typical State Implementation
Plan (SIP) emission standard. In the case
of automobile and light-duty truck
surface coating operations, the
incremental differences will depend on
the control levels that will be required
by revised SIP's. Revisions to most SIP's
are currently in progress.
Most existing automobile and light-
duty truck surface coating operations
are located in areas which are
considered nonattainment areas for
purposes of achieving the National
Ambient Air Quality Standard (NAAQS)
for ozone. New facilities are expected to
locate in similar areas. States are in the
process of revising their SIP's for these
areas and are expected to include
revised emission limitations for
automobile and light-duty truck surface
coating operations in their new SIP's. In
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Federal Register / Vol. 44, No. 195 /Friday, October 5, 1979 / Proposed Rules
revising their SIP'S the States are relying
on the control techniques guideline
document, "Control of Volatile Organic
Emissions from Existing Stationary
Sources—Volume II: Surface Coating of
Cans, Coil, Paper, Fabrics, Automobiles
and Light-Duty Trucks" (EPA-450/2-77-
088 [CTG]).
Since control technique guidelines are
not binding, States may establish
emission limits which differ from the
guidelines. To the extent Spates adopt
the emission limits recommended in the
control techniques guideline document
as the basis for their revised SIFs, the
proposed standards of performance
would have little environmental, energy,
or economic impacts. The actual
incremental impacts of the proposed
standards of performance, therefore,
will be determined by the final emission
limitations adopted by the States in
their revised SIP'S. For the purpose of
this rulemaking, however, the
environmental, energy, and economic
impacts of the proposed standards have
been estimated based on emission limits
contained in existing SIP'S.
In addition to achieving further
reductions in emissions beyond those
required by a typical SIP, standards of
performance have other benefits. They
establish a degree of national uniformity
to avoid situations in which some States
may attract industries by relaxing air
pollution standards relative to other
States. Further, standards of
performance improve the efficiency of
case-by-case determinations of best
available control technology (BACT) for
facilities located in attainment areas,
and lowest achievable emission rates
(LAER) for facilities located in
nonattainment areas, by providing a
starting point for the basis of these
determinations. This results from the
process for developing a standard of
performance, which involves a
comprehensive analysis of alternative
emission control technologies and an
evaluation and verification of emission
test methods. Detailed cost and
economic analyses of various regulatory
alternatives are presented in the
supporting documents for standards of
performance.
Based on emission control levels
contained in existing SIFs, the proposed
standards of performance would reduce
emissions of VOC from new, modified,
or reconstructed automobile and light-
duty truck surface coating operations by
about 80 percent. National emissions of
VOC would be reduced-by about 4,800
metric tons per year by 1983.
Water pollution impacts of the
proposed standards would be relatively
small compared to the volume and
quality of the wastewater discharged
from plants meeting existing SIP levels.
The proposed standards are based on
the use of water-based coating
materials. These materials would lead to
a slight increase in the chemical oxygen
demand (COD) of the wastewater
discharged from the surface coating
operations within assembly plants. This
increase in COD, however, is not great
enough to require additional wastewater
treatment capacity beyond that required
in existing assembly plants using
solvent-based surface coating materials.
The solid waste impact of the
proposed standards would be negligible
compared to the amount of solid waste
generated by existing assembly plants.
The solid waste generated by water-
based coatings, however, is very sticky,
and equipment cleanup is more time
consuming than for solvent-based
coatings. Solid wastes from water-based
coatings do not present any special
disposal problems since they can be
disposed of by conventional landfill
procedures.
National energy consumption would
be increased by the use of water-based
coatings to comply with the proposed
standards. The equivalent of an
additional 18,000 barrels of fuel oil
would be consumed per year at a typical
assembly plant. This is equivalent to an
increase of about 25 percent in the
energy consumption of a typical surface
coating operation. National energy
consumption would be increased by the
equivalent of about 72,000 barrels of fuel
oil per year in 1983. This increase is
based on the projection that four new
assembly plants will be built by 1983.
The proposed standards would
increase the capital and annualized
costs of new automobile and light-duty
truck surface coating operations within
assembly plants. Capital costs for the
four new facilities planned by 1983
would be_increased by approximately
$19 million as a result of the proposed
standards. The incremental capital costs
for control represent about 0.2 percent of
the $10 billion planned for capital
expenditures. The corresponding
annualized costs would be increased by
approximately $9 million in 1983. The
price of an automobile or light-duty
truck manufactured at a new plant
which complies with the proposed
standards of performance would be
increased by less than 1 percent. This is
considered to be a reasonable control
cost.
Modifications and Reconstructions
During the development of the
proposed standards, the automobile
industry expressed concern that changes
to assembly plants made only for the
purpose of annual model changeovers
would be considered a modification or
reconstruction as defined in the Code of
Federal Regulations, Title 40, Parts 60.14
and 60.15 (40 CFR 60.14 and 60.15). A
modification is any physical or
operational change in an existing facility
which increases air pollution from that
facility. A reconstruction is any
replacement of components of an
existing facility which is so extensive
that the capital cost of the new
components exceeds 50 percent of the
capital cost of a new facility. In general,
modified and reconstructed facilities
must comply with standards of
performance. According to the available
information, changes to coating lines for
annual model changeovers do not cause
emissions to increase significantly.
Further, these changes would normally
not require a capital expenditure that
exceeds the 50 percent criterion for
reconstruction. Hence, it is very unlikely
that these annual facility changes would
be considered either modifications or
reconstructions. Therefore, the proposed
standards state that changes to surface
coating operations made only to
accommodate annual model
changeovers are not modifications or
reconstructions. In addition, by
exempting annual model changeovers,
enforcement efforts are greatly reduced
with little or no adverse environmental
impact.
Selection of Source and Pollutants
VOC are organic compounds which
participate in atmospheric
photochemical reactions or are
measured by Reference Methods 24
(Candidate 1 or Candidate 2) and 25.
There has been some confusion in the
past with the use of the term
"hydrocarbons." In addition to being
used in the most literal sense, the term
"hydrocarbons" has been used to refer
collectively to all organic chemicals.
Some organics which are photochemical
oxidant precursors are not
hydrocarbons (in the strictest definition)
and are not always used as solvents. For
purposes of this discussion, organic
compounds include all compounds of
carbon except carbonates, metallic
carbides, carbon monoxide, carbon
dioxide and carbonic acid.
Ozone and other photochemical
oxidants result in'a variety of adverse
impacts on health and welfare, inducing
impaired respiratory function, eye
irritation, deterioration of materials such
as rubber, and necrosis of plant tissue.
Further information on these effects can
be found in the April 1978 EPA
document "Air Quality Criteria for
Ozone and Other Photochemical
Oxidants," EPA-600/8-78-004. This
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Federal Register / Vol. 44. No. 195 /Friday. October 5. 1979 / Proposed Rules
document can be obtained from the EPA
library (see Addresses Section),
Industrial coating operations are a
major source of air pollution emissions
of VOC. Most coatings contain organic
solvents which evaporate upon drying of
the coating, resulting in the emission of
VOC. Among the largest individual
operations producing VOC emissions in
the industrial coating category are
automobile and light-duty truck surface
coating operations. Since the surface
coating operations for automobiles and
light-duty trucks are very similar in
nature, with line speed being the
primary difference, they are being
considered together in this study.
Automobile and light-duty truck
manufacturers employ a variety of
surface coatings, most often enamels
and lacquers, to produce the protective
and decorative finishes of their product.
These coatings normally use an organic
solvent base, which is released upon
drying.
The "Priority List for New Source
Performance Standards under the Clean
Air Act Amendments of 1977," which
was promulgated in 40 CFR 60.16, 44 FR
49222. dated August 21,1979, ranked
sources according to the impact that
standards promulgated in 1980 would
have on emissions in 1990. Automobile
and light-duty truck surface coating
operations rank 27 out of 59 on this list
of sources to be controlled.
The surface coating operation is an
integral part of an automobile or light-
duty truck assembly plant, accounting
for about one-quarter to one-third of the
total space occupied by a typical
assembly plant. Surface coatings are
applied in two main steps, prime coat
and topcoat. Prime coats may be water-
based or organic solvent-based. Water-
based coatings use water as the main
carrier for the coating solids, although
these coatings normally contain a small
amount of organic solvent. Solvent-
based coatings use organic solvent as
the coating solids carrier. Currently
about half of the domestic automobile
and light-duty truck assembly plants use
water-based prime coats.
Where water-based prime coating is
used, it is usually applied by EDP. The
EDP coat is normally followed by a
"guide coat," which provides a suitable
surface for application of the topcoat.
The guide coat may be water-based or
solvent-based.
Automobile and light-duty truck
topcoats presently being used are
almost entirely solvent-based. One or
more applications of topcoats are
applied to ensure sufficient coating
thinkness. An oven bake may follow
each topcoat application, or the coating
may be applied wet on wet.
In 1976, nationwide emissions of VOC
from automobile and light-duty truck
surface coating operations totaled about
135,000 metric tons. Prime and guide
coat operations accounted for about
50,000 metric tons with the remaining
85,000 metric tons being emitted from
topcoat operations. This represents
almost 15 percent of the volative organic
emissions from all industrial coating
operations.
VOC comprise the major air pollutant
emmitted by automobile and light-duty
truck assembly plants. Technology ia
available to reduce VOC emissions and
thereby reduce the formation of ozone
and other photochemical oxidants.
Consequently, automobile and light-duty
truck surface coating operations have
been selected for the development of
standards of performance.
Selection of Affected Facilities
The prime coat, guide coat, and
topcoat operations usually account for
more than 80 percent of the VOC
emissions from autombile and light-duty
truck assembly plants. The remaining
VOC emissions result from final topcoat
repair, cleanup, and coating of various
small component parts. These VOC
emission sources are much more
difficult to control than the main surface
coating operations for several reasons.
First, water-based coatings cannot be
used for final topcoat repair, since the
high temperatures required to cure
water-based coatings may damage heat
sensitive components which have been
attached to the vehicle by this stage of
production. Second, the use of solvents
is required for equipment cleanup
procedures. Third, add-on controls, such
as incineration, cannot be used
effectively on these cleanup operations
because they are composed of numerous
small operations located throughout the
plant. Since prime coat, guide coat, and
topcoat operations account for the bulk
of VOC emissions from autombile and
light-duty truck assembly plants, and
control techniques for reducing VOC
emissions from these operations are
demonstrated, they have been selected
for control by standards of performance.
The "affected facility" to which the
proposed standards would apply could
be designated as the entire surface
coating line or each individual surface
coating operation. A major
consideration in selecting the affected
facility was the potential effect that the
modification and reconstruction
provisions under 40 CFR 60.14 and 60.15,
which apply to all standards of
performance, could have on existing
assembly plants. A modification is any
physical or operational change in an
existing facility which increase* air
pollution from that facility. A
reconstruction is any replacement of
components of an existing facility which
is so extensive that the capital cost of
the new coraponensts exceeds 50
percent of the capital cost of a new
facility. For standards of performance to
apply, EPA must conclude that it is
technically and economically feasible
for the reconstructed facility to meet the
standards.
Many automobile and light-duty truck
assembly plaiTts that have a spray prime
coat system will be switching to EDP
prime coat systems in the future to
reduce VOC emissions to comply with
revised SIP's. The capital cost of this
change could be greater than 50 percent
of the capital cost of a new surface
coating line. If the surface coating line
were chosen as the affected facility, and
if this switch to an EDP prime coat
system were considered a
reconstruction of the surface coating
line, all surface coating operations on
the line would be required to comply
with the proposed standards. Most
plants would be reluctant to install an
EDP prime coat system to reduce VOC
emissions if, by doing so, the entire
surface coating line might then be
required to comply with standards of
performance. By designating the prime
coat, guide coat, and topcoat operations
as separate affected facilities, this
potential problem is avoided. Thus, each
surface coating operation (i.e., prime
coat, guide coat, and topcoat) has been
selected as an affected facility in the
proposed standards.
Selection of Best System of Emission
Reduction
VOC emissions from automobile and
light-duty truck surface coating
operations can be controlled by the use
of coatings having a low organic solvent
content, add-on emissions control
devices, or a combination of the two.
Low organic solvent coatings consist of
water-based enamels, high solids
enamels, and powder coatings. Add-on
emission control devices consist of such
techniques as incineration and carbon
adsorption.
Control Technologies
Water-based coating materials are
applied either by conventional spraying
or by EDP. Application of coatings by
EDP involves dipping the automobile or
truck to be coated into a bath containing
a dilute water solution of the coating
material. When charges of opposite
polarity are applied to the dip tank and
vehicle, the coating material deposits on
the vehicle. Most EDP systems presently
in use are anodic systems in which the
vehicle is given a positive charge.
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Federal Register / Vol. 44, No. 195 /Friday. October 5. 1979 / Proposed Rules
Cathodic EDP. in which the vehicle is
negatively charged, is a now technology
which is expanding rapidly in the
automotive industry. Cathodic EDP
provides better corrosion resistance and
requires lower cure temperatures than
anodic systems. Cathodic EDP systems
are also capable of applying better
coverage on deep recesses of parts.
The prime coat is usually followed by
a spray application of an intermediate
coat, or guide coat, before topcoat
application. The guide coat provides the
added film thickness necessary for
sanding and a suitable surface for
topcoat application. EDP can only be
used if the total film thickness on the
metal surface does not exceed a limiting
value. Since this limiting thickness is
about the same as the thickness of the
prime coat, spraying has to be used for
guide coat and topcoat application of
water-based coatings.
Currently, nearly half of domestic
automobile and light-duty truck
assembly plants use EDP for prime coat
application, but only two domestic
plants use water-based coating for guide
coat and topcoat applications.
Coatings whose solids content is
about 45 to 60 percent are being
developed by a number of companies.
When these coatings are applied at high
transfer efficiency rates, VOC emissions
are significantly less than emissions
from existing solvent-based systems.
While these high solids coatings could
be used in the automotive industry,
certain problems must be overcome. The
high working viscosity of these coatings
makes them unsuitable for use in many
existing application devices. In addition,
this high viscosity can produce an
"orange peel," or uneven, surface. It also
makes these coatings unsuitable for use
with metallic finishes. Metallic finishes,
which account for about 50 percent of
domestic demand, are produced by
adding small metal flakes to the paint.
As the paint dries, these flakes become
oriented parallel to the surface. With
high solids coatings, the viscosity of the
painf prevents movement of the flakes.
and they remain randomly oriented,
producing a rough surface. However.
techniques such as heated application
are being investigated to reduce these
problems, and it is expected that by 1982
high solids coatings will be considered
technically demonstrated for use in the
automotive industry.
Powder coatings are a special class of
high solids coatings (hat consist of
solids only. They are applied by
electrostatic spray and are being used
on a limited basis for topcoating
automobiles, both foreign and domestic.
The use of powder coatings is severely
limited, however, because metallic
finishes cannot be appbed using
powder. As with other high solids
coatings, research is continuing in the
use of powder coatings for the
automotive industry.
Thermal incineration has been used to
control VOC emissions from bake ovens
in automobile and light-duty truck
surface coating operations because of
the fairly low volume and high VOC
concentration in the exhaust stream.
Incineration normally achieves a VOC
emission reduction of over 90 percent.
Thermal incinerators have not, however,
been used for control of spray booth
VOC emissions. Typically, the spray
booth exhaust stream is a high volume
stream [95,000 to 200,000 liters per
second) which is very low in
concentration of VOC (about 50 ppm).
Thermal incineration of this exhaust
stream would require a large amount of
supplemental fuel, which is its main
drawback for control of spray booth
VOC emissions. There are no technical
problems with the use of thermal
incineration.
Catalytic incineration permits lower
incinerator operating temperatures and,
therefore, requires about 50 percent less
energy than thermal incineration.
Nevertheless, the energy consumption
would still be high if catalytic
incineration were used to control VOC
emissions from a spray booth. In
addition, catalytic incineration allows
the owner or operator less choice in
selecting a fuel; it requires the use of
natural gas to preheat the exhaust gases,
since oil firing tends to foul the catalyst.
While catalytic incineration is not
currently being employed in automobile
and light-duty truck surface coating
operations for control of VOC
emissions, there are no technical
problems which would preclude its use
on either bake oven or spray booth
exhaust gases. The primary limiting
factor is the high energy consumption of
natural gas, if catalytic incineration is
used to control emissions from spray
booths.
Carbon adsorption has been used
successfully to control VOC emissions
in a number of industrial applications.
The ability of carbon adsorption to
control VOC emissions from spray
booths and bake ovens in automobile
and light-duty truck surface coating
operations, however, is uncertain. The
presence of a high volume, low VOC
exhaust stream from spray booths
would require carbon adsorption units
much larger than any that have ever
been built. For bake ovens in automobile
and light-duty truck surface coating
operations, a major impediment to the
use of carbon adsorption is beat. The
high temperature of the bake oven
exhaust stream would require the use of
refrigeration to cool the gas stream
before it passes through the carbon bed.
Carbon adsorption, therefore, is not
considered a demonstrated technology
at this time for controlling VOC
emissions from automobile and light-
duty truck surface coating operations.
Work is continuing within the
automotive industry on efforts to apply
carbon adsorption to the control of VOC
emissions, however, and it may become
a demonstrated technology in the near
future.
Regulatory Options
Water-based coatings and
incineration are two well-demonstrated
and feasible techniques for controlling
emissions of VOC from automobile and
light-duty truck surface coating
operations. Based upon the use of these
two VOC emission control techniques.
the following two regulatory options
were evaluated.
Regulatory Option I includes two
alternatives which achieve essentially
equivalent control of VOC emissions
Alternative A is based on the use of
water-based prime coats, guide coats.
and topcoats. The prime coat would be
applied by EDP. Since the guide coat is
essentially a topcoat material, guide
coat emission levels as low as those
achieved by water-based topcoats
should be possible through a transfer of
technology from topcoat operations to
guide coat operations. Alternative B is
based on the use of a water-based prime
coat applied by EDP and solvent-based
guide coats and topcoats. Incineration of
the exhaust gas stream from the topcoat
spray booth and bake oven would be
used to control VOC emissions under
this alternative.
Regulatory Option II is based on the
use of a water-based prime coat applied
by EDP and solvent-based guide coa'.s
and topcoats. In this option, the exhnust
gas streams from both the guide r.oat
and topcoat spray booths and bake
ovens would be incinerated !o control
VOC emissions
Environmental. Energy, and Economic
Impacts
Standards based on Reprl.ilory
Option I would lead to a reduction in
VOC emissions of about 80 percent, am!
standards based on Regulatory Option II
would lead to a reduction in emissions
of about 90 percent, compared to VOC
emissions from automobile and light-
duty truck surface coating operations
controlled to meet current SIP
requirements. Growth projections
indicate there will be four new
automobile and light-duty truck
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assembly lines constructed by 1983.
Very few, if any, modifications or
reconstructions are expected during this
period. Based on these projections,
national VOC emissions in 1983 would
be reduced by about 4,800 metric tons
with standards based on Regulatory
Option I and about 5,400 metric tons
with standards based on Regulatory
Option II. Thus, both regulatory options
would result in a significant reduction in
VOC emissions from automobile and
light-duty truck surface coating
operations.
With regard to water pollution,
standards based on Regulatory Option II
would have essentially no impact.
Similarly, standards based on
Regulatory Option I(B) would have no
water pollution impact. Standards based
on Regulatory Option I(A), however,
would result in a slight increase in the
chemical oxygen demand (COD) of the
wastewater discharged from automobile
and light-duty truck surface coating
operations within assembly plants. This
increase is due to water-miscible
solvents in the water-based guide coats
and topcoats which become dissolved in
the wastewater. The increase in COD of
the wastewater, however, would be
small relative to current COD levels at
plants using solvent-based surface
coatings and meeting existing SIP's. In
addition, this increase would not require
the installation of a larger wastewater
treatment facility than would be built for
an assembly plant which used solvent-
based surface coatings.
The solid waste impact of the
proposed standards would be negligible.
The volume of sludge generated from
water-based surface coating operations
is approximately the same as that
generated from solvent-based surface
coating operations. The solid waste
generated by water-based coatings,
however, is very sticky, and equipment
cleanup is more time consuming than for
solvent-based coatings. Sludge from
either type of system can be disposed of
by conventional landfill procedures
without leachate problems.
With regard to energy impact,
standards based on Regulatory Option
I(A) would increase the energy
consumption of surface coating
operations at a new automobile or light-
duty truck assembly plant by about 25
percent. Regulatory Option I(B) would
cause an increase of about 150 to 429
percent in energy consumption.
Standards based on Regulatory Option
II would result in an increase of 300 to
700 percent in the energy consumption
of surface coating operations at a new
automobile or light-duty truck assembly
plant. The range in energy consumption
for those options which are based on
use of incineration reflects the
difference between catalytic and
thermal incineration.
The relatively high energy impact of
standards based on Regulatory Option
I(B) and Regulatory Option II is due to
the large amount of incineration fuel
needed. Standards based on Regulatory
Option II would increase energy
consumption at a new automobile and
light-duty truck assembly plant by the
equivalent of about 200,000 to 500,000
barrels of fuel oil per year, depending
upon whether catalytic or thermal
incineration was used. Standards based
on Regulatory Option I(B) would
increase energy consumption by the
equivalent of about 100,000 to 300,000
barrels of fuel oil per year.
Standards based on Regulatory
Option 1(A) would increase the energy
consumption of a typical new
automobile and light-duty truck
assembly plant by the equivalent of
about 18,000 barrels of fuel oil per year.
Approximately one-third of this increase
in energy consumption is due to the use
of air conditioning, which is necessary
with the use of water-based coatings,
and the remaining two-thirds are due to
the increased fuel required in the bake
ovens for curing water-based coatings.
Growth projections indicate that four
new automobile and light-duty truck
assembly lines (two automobile and two
truck lines) will be built by 1983. Based
on these projections, standards based
on Regulatory Option I(A) would
increase national energy consumption in
1983 by the equivalent of about 72,000
barrels of fuel oil. Standards based on
Regulatory Option I(B) would increase
national energy consumption in 1983 by
the equivalent of 400,000 to 1,200,000
barrels of fuel oil, depending on whether
catalytic or thermal incineration were
used. Standards based on Regulatory
Option II would increase national
energy consumption in 1983 by the
equivalent of 800,000 to 2,000,000 barrels
of fuel oil, again depending on whether
catalytic or thermal incineration were
used.
The economic impacts of standards
based on each regulatory option were
estimated using the growth projection of
four new assembly lines by 1983.
Incremental control costs were
determined by calculating the difference
between the capital and annualized
costs of new assembly plants controlled
to meet Regulatory Options I(A), I(B),
and II, respectively, with the
corresponding costs for new plants
designed to comply with existing SIP's.
Of the four assembly plants protected by
1983, two were assumed to be lacquer
lines and the other two enamel line*.
There are basic design differences
between these two types of surface
coatings which have a substantial
impact on the magnitude of the costs
estimated to comply with standards of
performance. Lacquer surface coating
operations, for example, require much
larger spray booths and bake ovens than
enamel surface coating operations.
Water-based systems also require large
spray booths and bake ovens; thus, the
incremental capital cost of installing a
water-based system in a plant which
would otherwise have used a lacquer
system is relatively low. The
incremental capital costs differential,
however, would be much larger if the
plant would have been designed for an
enamel system.
Tables 1 and 2 summarize the
economic impacts of the proposed
standards on plants of typical sizes.
Table 1 presents the incremental costs
of the various control options for a plant
which would have used solvent-based
lacquers. Table 2 presents similar costs
for plants which would have been
designed to use solvent-based enamels.
Though these tables present incremental
costs for passenger car plants, light-duty
truck plants would have similar cost
differentials. In all cases, it is assumed
the plants would install a water-based
EDP prime system in the absence of
standards of performance. Therefore, no
incremental costs associated with EDP
prime coat operations are included in
the costs presented in Tables 1 and 2. A
nominal production rate of 55 passenger
cars per hour was assumed for both
plants. Tables 1 and 2 show incremental
capitalized and annualized costs per
vehicle produced at each new facility.
The manufacturers would probably
distribute these incremental costs over
their entire annual production to arrive
at purchase prices for the automobiles
and light-duty trucks.
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Table 1 iMCRLHENTAL CONTROL COSTS"
(Compa-ed to the Costs of a Lacquer Plant)
Regulatory Options
KB)
II
Water-Based Coatings Thermal
Catalytic
Thermal
Capital Cost of Control
Alternative
Annualized Cost of Control
Alternative
Incremental Cost/Vehicle
Produced at this Facility
$ 720,000
$1,550,000
$7 34
$68 66
$50 66
$73.39
Assumes a line speed of 55 vehicles per hour and an annual production of 211,200 vehicles
Table 2 INCREMENTAL CONTROL COSTS
(Compared to the Costs of an Enamel Plant)
Catalytic
$11.800,000 $15.000,000 $12,800,000 $16,200,000
$14.500.000 $10,700.000 $15,500.000 $11.500.000
4S
I (A)
Regulatory Options
KB)
Water-Based Coatings Thermal
Catalytic
II
Thermal
Capital Cost of Control
Alternative
Annualized Cost of Control
Alternative
Incremental Cost/Vehicle
Produced at this Facility
$10,300,000
$ 3,640,000
$17 23
$26.61
$19 65
$31.30
Catalytic
$ 4,630.000 $ 5,850,000 $ 5,640,000 $ 7.000.000
$ 5,620,000 $ 4,150,000 $ 6,610.000 $ 4,890.G',J
$?3 IS
Assumes a line speed of 55 vehicles per hour and an annual production of 211,200 vehicles.
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Incremental capital costs for suing
incineration to reduce VOC emissions
from solvent-based lacquer plants to
levels comparable to water-based plants
are much larger than they are for using
incineration on a solvent-based enamel
plant. This large difference in costs
occurs because lacquer plants have
larger spray booth and bake oven areas
than enamel plants and, therefore, a
larger volume of exhaust gases. Since
larger incineration units are required,
the incremental capital costs of using
incineration to control VOC emissions
from a solvent-based lacquer plant are
about 15 to 25 times greater than they
are for using water-based coatings.
Similarly, energy consumption is much
greater; hence, the annualized costs of
using incineration are about 10 times
greater than they are for using water-
based coatings.
On the other hand, the incremental
capital costs of controlling VOC
emissions from new solvent-based
enamel plants by the use of incineration
are only about one-half the incremental
capital costs between a new solvent-
based enamel plant and a new water-
based plant. Due to the energy
consumption associated with
incinerators, however, the incremental
annualized costs of using incineration
with solvent-based enamel coatings
could vary from as little as 15 percent
more to as much as 90 percent more
than the annualized costs of using
water-based coatings.
While the incremental capital costs of
building a plant to use water-based
coatings can be larger or smaller than
the costs of using incineration,
depending upon whether a solvent-
based lacquer plant or a solvent-based
enamel plant is used as the starting
point, the annualized costs of using
water-based coatings are always less
than they are for using incineration. This
is due to the large energy consumption
of incineration units compared to the
energy consumption of water-based
coatings.
Since the incremental annualized
costs are less with Regulatory Option
I(A) than with Regulatory Option 1(B), it
is assumed in this analysis that
Regulatory Option 1(A) would be
incorporated at any new, modified, or
reconstructed facility to comply with
standards based on Regulatory Option I.
As noted, four new assembly plants are
expected to be built by 1983. The
incremental capital cost to the industry
for these plants to comply with
standards based on Regulatory Option I
would be approximately $19 million. The
corresponding incremental annualized
costs would be about $9 million in 1983.
If standards are based on Regulatory
Option II, it is expected that the industry
would choose catalytic incineration
because its annualized costs are lower
than those for thermal incineration.
Based this assumption, the incremental
capital costs for the industry under
Regulatory Option II would be
approximately $42 million, and the
incremental annualized costs by 1983
would be about $30 million. For
standards based on either Regulatory
Option I or Regulatory Option II, the
increase in the price of an automobile or
light-duty truck that is manufactured at
one of the new plants would be less
than 1 percent of the base price of the
vehicle.
Best System of Emission Reduction
Both Regulatory Options I and II
achieve a significant reduction in VOC
emissions compared to automobile and
light-duty truck assembly plants
controlled to comply with existing SIP's,
and neither option creates a significant
adverse impact on other environmental
media. In terms of energy consumption,
standards based on Regulatory Option II
would have as much as 10 to 25 times
the adverse impact on energy
consumption as standards based on
Regulatory Option I, while only
achieving 10 to 15 percent more
reductions in VOC emissions. The costs
of standards based on Regulatory
Option II range from two to three times
the costs of standards based on
Regulatory Option I. Thus, Regulatory
Option I(A), water-based coatings, was
selected as the best system of
continuous emission reduction,
considering costs and nonair quality
health, and environmental and energy
impacts.
Although water-based coatings are
considered to be the best system of
emission reduction at the present time, it
is very likely that plants built in the
future will use other systems to control
VOC emissions, such as high solids
coatings and powder coatings. High
solids coatings applied at high transfer
efficiencies are capable of achieving
equivalent emission reductions and are
expected to be less costly and require
less total energy than water-based
systems. These high solids coatings are
expected to be available by 1982 and
will probably be used by most new
sources to comply with the VOC
emission limitations. Powder coatings
are also expected to be available in the
future but are not demonstrated at this
time.
Selection of Format for the Proposed
Standards
A number of different formats could
be selected to limit VOC emissions from
automobile and light-duty truck surface
coating operations. The format
ultimately selected must be compatible
with any of the three different control
systems that could be used to comply
with the proposed standards. One
control system is the use of water-based
coating materials in the prime coat,
guide coat, and topcoat operations.
Another control system is the use of
solvent-based coating materials and
add-on VOC emission control devices
such as incineration. The third control
system consists of the use of high solids
coatings. Although the coatings to be
used in this system are not
demonstrated at this time, research is
continuing toward their development;
hence, they may be used in the future.
The formats considered were
emission limits expressed in terms of (1)
concentration of emissions in the
exhaust gases discharged to the
atmosphere; (2) mass emissions per unit
of production; or (3) mass emissions per
volume of coating solids applied.
The major advantage of the
concentration format is its simplicity of
enforcement. Direct emission
measurements oould be made using
Reference Method 25. There are,
however, two significant drawbacks to
the use of this format. Regardless of the
control approach chosen, emission
testing would be required for each stack
exhausting gases from the surface
coating operations (unless the owner or
operator could demonstrate to the
Administrator's satisfaction that testing
of representative stacks would give the
same results as testing all the stacks).
This testing would be time consuming
and costly because of the large number
of stacks associated with automobile
and light-duty truck surface coating
operations. Another potential problem
with this formal is the ease of
circumventing the standards by the
addition of dilution air. It would be
extremely difficult to determine whether
diluted air was being added
intentionally to reduce the concentration
of VOC emissions in the gases
discharged to the atmosphere, or
whether the air was being added to the
application or drying operation to
optimize performance and maintain a
safe working space.
A format of mass VOC emissions per
unit of production relates emissions to
individual plant production on a direct
basis. Where water-based coatings are
used, the average VOC content of the
coating materials cou]d be determined
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Federal Register / Vol. 44. No. 195 /Friday. October 5. 1979 / Proposed Rules
by using Reference Method 24
(Candidate 1 or Candidate 2). The
volume of coating materials used and
the percent solids could be determined
from purchase records. VOC emissions
could then be calculated by multiplying
the VOC content of the coating
materials by the volume of coating
materials used in a given time period
and by the percentage of solids, and
dividing the result by the number -of
vehicles produced in that time period.
This would provide a VOC emission
rate per unit of production.
Consequently, procedures to determine
compliance would be direct and
straightforward, although very time
consuming. This procedure would also
require data collection over an
excessively long period of time.
Where solvent-based coatings were
used with add-on emission control
devices, stack emission tests could be
performed to determine VOC emissions.
Dividing VOC emissions by the number
of vehicles produced would again yield
VOC emissions per unit of production.
This format, however, would not
account for differences in surface
coating requirements for different
vehicles caused by size and
configuration. In addition,
manufacturers of larger vehicles would
be required to reduce VOC emissions
more than manufacturers of smaller
vehicles.
A format of mass of VOC emissions
per volume of coating solids applied
also has the advantage of not requiring
itack emission testing unless add-on
emission control devices rather than
water-based coatings are used to
comply with the standards. The
introduction of dilution air into the
exhaust stream would not present a
problem with this format. The problem
of varying vehicle sizes and
configurations would be eliminate since
the format is in terms of volume of
applied solids regardless of the surface
area or number of vehicles coated. This
format would also allow flexibility in
selection of control systems, for it is
usable with any of the control methods.
Since this format overcomes the varying
dilution air and vehicle size problems
inherent with the other formats, it has
been selected as the format for the
proposed standards. In order to use a
format which is in terms of applied
solids, the transfer efficiency of the
application devices must be considered.
Transfer efficiency is defined as the
fraction of the total sprayed solids
which remain on the vehicle. Transfer
efficiency is an important factor because
as efficiency decreases, more coating
material is used and VOC emissions
increase. Equations have been
developed to use this format with water-
based coating materials as well as with
solvent-based coating materials in
combination with high transfer
efficiences and/or add-on emission
controls devices. These equations are
included in the proposed standards.
Selection of Numerical Emission Limits
Numerical Emission Limits
The numerical emission limits
selected for the proposed standard are:
• 0.10 kilogram of VOC per liter of
applied coating solids from prime coat
operations
• 0.84 kilogram of VOC per liter of
applied coating solids from guide coat
operations
• O.B4 kilogram of VOC per liter of
applied coating solids from topcoat
operations .
In all three limits, the mass of VOC is
measured as carbon in accordance with
Reference Methods 24 (Candidate 1) and
25. These emission limits are based on
the use of water-based coating materials
in the prime coat, guide coat, and
topcoat operations. Water-based coating
data were obtained from plants which
were using these materials as well as
from the vendors who supply them.
These data were used to calculate VOC
emission limits using a procedure
similar to proposed Method 24
(Candidate 1). A transfer efficiency of 40
percent was then applied to the values
obtained for guide coat and top-coat
emissions. This efficiency was
determined to be representative of a
well-operated air-atomized spray
system. The CTG-recommended limits
are based on the use of the same coating
materials as the proposed standards.
The limits in the CTG are expressed in
pounds of VOC per gallon of coating
(minus water) used in the EDP system or
the spray device. The limits in these
proposed standards, however, are
referenced to the amount of coating
solids which adhere to the vehicle body.
Therefore, to compare the limits in the
CTG to those proposed here, it is
necessary to account for the solids
content of the coating and the efficiency
of applying the guide coat and topcoat
to the vehicle body. Consideration of
transfer efficiency is significant because
the proposed standards can be met by
using high solids content coating
materials if the amount of overspray is
kept to a minimum. Since this format
provides equivalency determinations for
systems using solvent-based coating
materials in combination with high
transfer efficiencies and/or add-on
control devices, it allows flexibility in
selection of control systems.
As discussed in previous sections,
there are two types of EDP systems.
Anodic EDP was the first type
developed for use in automobile surface
coating operations. Cathodic EDP is the
second type and is a recent technology
improvement which results in greater
corrosion resistance. Consequently,
nearly 50 percent of the existing EDP
operations use cathodic systems, and
continued changeovers from anodic to
cathodic EDP are expected. Since
cathodic EDP produces a coating with
better corrosion resistance, the proposed
standards are based on the best
available cathodic EDP systems.
The coating material on which the
EDP emission limit is based is presently
in production use. Although this low
solvent content material is currently
available only in limited quantities, it is
expected to be available in sufficient
quantities for use in all new or modified
sources before promulgation of the
standard. The final promulgated
standards will be based on this low
solvent content material, rather than the
EDP material commonly used now, if it
is determined to be widely available at
that time.
The emission limit for guide coat
operations is based on a transfer of
technology from topcoat operations. The
guide coat is essentially a topcoat
material, without pigmentation, and
water-based topcoats are available
which can comply with the proposed
limits. Hence, the same emission limit is
proposed for the guide coat operation as
for the topcoat operation.
Because of the elevated temperatures
present in the prime coat, guide coat,
and topcoat bake ovens, additional
amounts of "cure volatile" VOC may be
emitted. These "cure volatile" emissions
are present only at high temperatures
and are not measured in the analysis
which is used to determine the VOC
content of coating materials. Cure
volatile emissions, however, are
believed to constitute only a sma!!
percentage of total VOC emissions
Consequently, because of the
complexity of measuring and controlling
cure volatile emissions, they will not be
considered in determining compliance
with the proposed standards.
A large number of coating materials
are used in topcoat operations, and each
may have a different VOC content.
Hence, an average VOC content of all
the coatings used in this operation
would be computed to determine
compliance with the proposed
standards. Either of two averaging
techniques could be used for computing
this average. Weighted averages provide
very accurate results but would require
keeping records of the total volume and
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Federal Register / Vol. 44, No. 195 /Friday, October 5, 1979 / Proposed Ruies
percent solids of each different coating
used. Arithmetic averages are not
always as accurate; however, they are
much simpler to calculate. In the case of
topcoat operations, normally 15 to 20
different coatings are used, end the
VOC content for most of these coatings
Is in the same general range. Therefore,
an arithmetic average would closely
approximate the values obtained from a
weighted average. An arithmetic
average would be calculated by
summing the VOC content of each
surface coating material used in a
surface coating operation (i.e., guide
coat or topcoat), and dividing the sum
by the number of different coating
materials used. Arithmetic averages are
also consistent with the approach being
incorporated into some revised SIP's.
For the EDP process, however, an
arithmetic average VOC content is not
appropriate to determine compliance
with the proposed standards. In an EDP
system, the coating material applied to
an automobile or light-duty truck body
is replaced by adding fresh coating
materials to maintain a relatively
constant concentration of solids,
solvent, and fluid level in the EDP
coating lank. Three different types of
materials are usually added in separate
streams—clear resin, pigment paste, and
solvent.
The clear resin and pigment paste are
very low in VOC content (i.e., 10 percent
or less), while the solvent is very high in
VOC content (i.e.. 90 percent or more).
The solvent additive stream is only
about 2 percent of the total volume
added. Consequently, an arithmetic
average of the three streams seriously
misrepresents the actual amount of VOC
added to the EDP coating tank.
Weighted averages, therefore, were
selected for determining the average
VOC content of Boating materials
applied by EDF.
If an automobile or light-duty truck
manufacturer chooses to use a control
technique other than water-based
coatings, the transfer efficiency of the
application devices used becomes very
important. As transfer efficiency
decreases, more coating material is used
and VOC emissions increase. Therefore
transfer efficiency must be taken into
account to determine equivalency to
water-based costings.
Electrostatic spraying, which applies
surface coatings at high transfer
efficiences, can in many industries be
used with water-based coatings if the
entire paint handling system feeding the
atomizers is insulated electically from
ground Otherwise, the high conductivity
of the water involved would ground out
and make ineffective the electrostatic
effect. In the case of the coating of
automobiles, however, because of the
larger number of colors involved, the
high frequency and speed of color
changes required, the large volume of
coatings consumed per shift, and the
large number of both automatic and
manual atomizers involved, it is not
technically feasible to combine water-
based coatings and electrostatic
methods for reasons of complexity, cost,
and personnel comfort. Consequently,
water-based surface coatings are
applied by air-atomized spray systems
at a transfer efficiency of about 40
percent. The numerical emission limits
included in the proposed standards were
developed based on the use of water-
based surface coatings applied at a 40
percent transfer efficiency. Therefore, if
surface coatings are apphed to a greater
than 40 percent transfer efficiency,
surface coatings with higher VOC
contents may be used with no increase
in VOC emissions to the atmosphere.
Transfer efficiencies for various means
of applying surface coatings have been
estimated, based on information
obtained from industries and vendors,
as follows:
Transtor
efficiency
Application method (percent)
An Atomued Spray ._.._..-. 40
Manuil Electrostatic Spray 75
Automatic Electrostatic Spray ... . ..... 95
ElectrodeposDion (EDP) . 106
These values are estimates which
reflect the high side of expected transfer
efficiency ranges, and therefore, are
intended to be used only for the purpose
of determining compliance with the
proposed standards.
Frequently, more than one application
method is used within a single surface
coating operation. In these cases, a
weighted average transfer efficiency,
based on the relative volume of coating
sprayed by each method, will be
estimated. These situations are likely to
vary among the different manufacturers
and the estimates, therefore, will be
subject to approval by the Administrator
on a case-by-case basis.
Method of Determining Compliance
The procedure for determining
compliance with the proposed standards
is complicated due to the number of
different control systems which may be
used. The following multistep procedure
would be used.
1. Determine the average VOC content
per liter of coating solids of the prime
coat guide coat, and topcoat materials
being used. This would require
analyzing all coating materials used in
each coating operation using the
proposed Reference Method 24
(Candidate 1 or Candidate 2) and
calculating an average VOC content for
each coating operation.
2. Select the appropriate transfer
efficiency for each surface coating
operation from the table included in the
proposed standards.
3. Calculate the mass of VOC
emissions per volume of applied solids
for each surface coating operation by
dividing the appropriate average VOC
content of the coatings (Step 1) by the
transfer efficiency of the surface coating
operation (Step 2). If the value obtained
is lower than the emission limit included
in the proposed standards, the surface
coating operation would be in
compliance. If the value obtained is
higher than the emission limit, add-on
VOC emission control would be
required to comply with the proposed
standards.
4. If add-on emission control is
required, calculate the emission
reduction efficiency in VOC emissions
which is required using the equations
included in the proposed standards.
5. In cases where all exhaust gases
are not vented to an emission control
device, determine the percentage of total
VOC emissions which enter the add-on
emission control device by sampling all
the stacks and using the equations
included in the proposed standards.
Representative sampling, however,
could be approved by the Administrator,
on a case-by-case basis, rather than
requiring sampling of all stacks for this
determination.
6. Calculate the actual efficiency of
the control device by determining VOC
emissions before and after the device
using the proposed Reference Method
25.
7. Calculate the VOC emission
reduction efficiency achieved by
multiplying the percentage of VOC
emissions which enter the add-on VOC
emission control device (Step 5) by the
add-on control device efficiency (Step
6). If the resulting value of the emission
reduction efficiency achieved were
greater than that required (Step 4), then
the surface coating operation would be
in compliance.
Detailed instructions, as well as the
equations to be used for these
calculations, are contained in the
proposed standards.
Selection of Monitoring Requirements
Monitoring requirements are generally
included in standards of performance to
provide a means for enforcement
personnel to ensure that emission
control measures adopted by a facility
to comply with standards of
performance are properly operated and
maintained. Surface coating operations
which have achieved compliance with
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the proposed standards without the use
of add-on VOC emission control devices
would be required to monitor the
average VOC content (weighted
averages for EDP and arithmetic
averages for guide coat and topcoat) of
the coating materials used in each
surface coating operation. Generally,
increases in the VOC content of the
coating materials would cause VOC
emissions to increase. These increases
could be caused by the use of new
coatings or by changes in the
composition of existing coatings.
Therefore, following the initial
performance test, increases in the
average VOC content of the coating
materials used in each surface coating
operation would have to be reported on
a quarterly basis.
Where add-on control devices, such
as incinerators, were used to comply
with the proposed standards,
combustion temperatures would be
monitored. Following the initial
performance test, decreases in the
incinerator combustion temperature
would be reported on a quarterly basis.
Performance Test Methods
Reference Method 24, "Determination
of Volatile Organic Compound Content
of Paint, Varnish, Lacquer, or Related
Products," is proposed in two forms—
Candidate 1 and Candidate 2. Candidate
1 leads to a determination of VOC
content expressed as the mass of
carbon. Candidate 2 yields a
determination of VOC content measured
as mass of volatile organics. The
decision as to which Candidate will be
used depends on the final format
selected for the proposed standards.
Reference Method 25, "Determination of
Total Gaseous Nonmethane Volatile
Organic Compound Emissions," is
proposed as the test method to
determine the percentage reduction of
VOC emissions achieved by add-on
emission control devices.
Public Hearing
A public hearing will be held to
discuss the proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given above (see
Addresses Section). Oral presentations
will be limited to 15 minutes each. Any
member of the public may file a written
statement before, during, or within 30
days after the hearing. Written
statements should be addressed to
"Docket" (see Addresses Section).
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section, Room 2903B, Waterside
Mall, 401 M Street, S.W., Washington,
D.C. 20460.
Docket
The docket, containing all supporting
information used by EPA to date, is
available for public inspection and
copying between 8:00 a.m. and 4:00 p.m.,
Monday through Friday, at EPA's
Central Docket Section, Room 2903B,
Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
EPA in the development of the
rulemaking. The docket is a dynamic
file, since material is added throughout
the rulemaking development. The
docketing system is intended to allow
members of the public and industries
involved to readily identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process. Along with the
statement of basis and purpose of the
promulgated rule and EPA responses to
significant comments, the contents of
the Docket will serve as the record in
case of judicial review [Section
307(d)(a)J.
Miscellaneous
As prescribed by Section 111,
establishment of standards of
performance for automobile and light-
duty truck surface coating operations
was preceded by the Administrator's
determination (40 CFR 60.16, 44 FR
49222, dated August 21,1979) that these
sources contribute significantly to air
pollution which may reasonably be
anticipated to endanger public health or
welfare. In accordance with Section 117
of the Act, publication of these
standards was preceded by consultation
with appropriate advisory committees,
independent experts, and Federal
departments and agencies. The
Administrator welcomes comments on
all aspects of the proposed regulations,
including the technological issues,
monitoring requirements, and the
proposed test methods. Comments are
requested specifically on Method 24
(Candidate 1 and Candidate 2) and the
coating material used as the basis for
the prime coat emission limit.
It should be noted that standards of
performance for new sources
established under Section 111 of the
Clean Air Act reflect:
. . . application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, and any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated [Section lll(a](l)|
Although emission control technology
may be available that can reduce
emissions below those levels required to
comply with standards of performance,
this technology might not be selected as
the basis of standards of performance
because of costs associated with its use.
Accordingly, standards of performance
should not be viewed as the ultimate in
achievable emission control. In fact, the
Act may require the imposition of a
more stringent emission standard in
several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new. or modified
sources locating in nonattainment areas
(i.e., those areas where statutorily
mandated health and welfare standards
are being violated). In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the NAAQS must
reduce emissions to the level which
reflects the LAER, as defined in section
171(3). The statute defines LAER as the
rate of emissions based on the
following, whichever is more stringent:
(A) 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
(B) the most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard.
A similar situation may arise under
the prevention-of-significant-
deterioration-of-air-quality provisions of
the Act. These provisions require that
certain sources employ BACT as defined
in section 169(3) for all pollutants
regulated under the Act. BACT must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all cases, SIP's approved or
promulgated under section 110 of the
Act must provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose. SIP's must, in some cases,
require greater emission reduction than
those required by standards of
performance for new sources-
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Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than standards of performance under
section 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire 5
years from the date of promulgation
unless EPA takes affirmative action to
extend them.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for any
new source standard of performance
under section lll(b) of the Act. An
economic impact assessment was
prepared for the proposed regulations
and for other regulatory alternatives. All
aspects of the assessment were
considered in the formulation of the
proposed standards to ensure that the
proposed standards would represent the
best system of emission reduction
considering costs. The economic impact
assessment is included in the
Background Information Document.
Dated: September 27, 1979.
Douglas M. Costle,
Administrator.
This proposed amendment to Part 60
of Chapter I, Title 40 of the Code of
Federal Regulations would—
1. Add a definition of the term
"volatile organic compound" to § 60.2 of
Subpart A—General Provisions as
follows:
$60.2 Definitions.
* * * • t *
(dd) "Volatile Organic Compound"
means any organic compound which
participates in atmospheric
photochemical reaction or is measured
by the applicable reference methods
specified under any subpart.
2. Add Subpart MM as follows:
Subpart MM—Standards of Performance
for Automobile and Light-Duty Truck
Surface Coating Operations
Sec
60.390 Applicability and designation of
affected facility.
60.391 Definitions.
60.392 Standards for volatile organic
compounds.
60.393 Monitoring of operations.
60.394 Test methods and procedures.
60.395 Modifications.
Authority: Sees. Ill and 301 (a) of the Clean
Air Art, as amended. [42 U.S.C. 7411,
7601(a)]. and additional authority as noted
below.
Subpart MM—Standards of
Performance for Automobile and
Light-Duty Truck Surface Coating
Operations
§60.390 Applicability and designation of
affected facility.
(a) The provisions of this subpart
apply to the following affected facilities
in an automobile or light-duty truck
surface coating line: each prime coat
operation, each guide coat operation,
and each topcoat operation.
(b) The provisions of this subpart
apply to any affected facility identified
in paragraph (aj of this section that
begins construction or modification after
(date of publication in the
Federal Register).
§60.391 Definitions.
All terms used in this subpart that are
not defined below have the meaning
given to them in the Act and in Subpart
A of this part.
(a) "Automobile" means a motor
vehicle capable of carrying no more
than 12 passengers.
(b) "Automobile and light-duty truck
body" means the body section rearward
of the windshield and the front-end
sheet metal or plastic exterior panel
material forward of the windshield of an
automobile or light-duty truck.
(c) "Bake oven" means a device which
uses heat to dry or cure coatings.
(d) "Electrodeposition (EDP)" means a
method of applying prime coat. The
automobile or light-duty truck body is
submerged in a tank filled with coating
material, and an electrical field is used
to deposit the material on the body.
(e) "Electrostatic spray application"
means a spray application method that
uses an electrical potential to increase
the transfer efficiency of the coating
solids. Electrostatic spray application
can be' used for prime coat, guide coat,
or topcoat operations.
(f) "Flash-off area" means the
structure on automobile and light-duty
truck assembly lines between the
coating application system (EDP tank or
spray booth) and the bake oven.
(g) "Guide coat operation" means the
guide coat spray booth, flash-off area
and bake oven(a) which are used to
apply and dry or cure a surface coating
on automobile and light-duty truck
bodies between the prime coat and
topcoat operation.
(h) "Light-duty truck" means any
motor vehicle rated at 3,850 kilograms
(ca. 8,500 pounds) gross vehicle weight
or less designed mainly to transport
property.
(i) "Prime coat operation" means the
prime coat application system (spray
booth or dip tank), flash-off area, and
bake oven(s) which are used to apply
and dry or cure the initial coat on the
surface of automobile or light-duty truck
bodies.
(j) "Spray application" means a
method of applying coatings by
atomizing the coating material and
directing this atomized spray toward the
part to be coated. Spray applications
can be used for prime coat, guide coat,
and topcoat operations.
(k) "Spray booth" means a structure
housing or manual spray application
equipment where prime coat guide coat,
or topcoat is applied to automobile or
light-duty truck bodies.
(1) "Surface coating operation" means
any prime coat, guide coat, or topcoat
operation on an automobile or light-duty
truck surface coating line.
(m) "Topcoat operation" means the
topcoat spray booth(s), flash-off area(s),
and bake oven(s) which are used to
apply and dry or cure the final coating(s)
on automobile and light-duty truck
bodies (i.e., those which give an
automobile or light-duty truck body its
color and surface appearance).
(n) "Transfer efficiency" means the
fraction of the total applied coating
solids which remains on the part.
(o) "Volatile organic compound"
(VOC) means any organic compound
which is measured by Method 24
(Candidate 1 or Candidate 2) and
Method 25.
(p) "VOC emissions" means the mass
of volatile organic compounds,
expressed as kilograms of carbon per
liter of applied coating solids, emitted
from a surface coating operation.
(q) "VOC content" means the volatile
organic compound content, in kilograms
of carbon per liter of coating solids, of a
coating material used in spray
applications or coating make-up stream
to an EDP tank.
§60.392 Standards for volatile organic
compounds.
After the performance test required by
§ 60.8 has been completed, no owner or
operator subject to the provisions of this
subpart shall discharge or cause of the
discharge into the atmosphere of VOC
emissions which exceed the following
limits:
(a) 0.10 kilogram of VOC (measured as
mass of carbon) per liter of applied
coating solids from each prime coat
operation.
(b) 0.84 kilogram of VOC (measured
as mass of carbon) per liter of applied
coating solids from each guide ooat
operation.
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(c) 0.84 kilogram of VOC (measured as
mass of carbon) per liter of applied
coating solids from each topcoat
operation,
§60.3*3 Monitoring of operation*.
(a) Any owner or operator subject to
the provisions of this subpart shall—(1)
Install, calibrate, operate, and maintain
a monitoring device which records the
combustion temperature of any effluent
gases which are emitted from any
surface coating operation and which are
incinerated to comply with J 60.392. TTie
manufacturer must certify that the
monitoring device is accurate to within
±2°C(±3.6°F).
(2) Determine the weighted average
VOC content of the coating materials
used in any EDP prime coat operation
whenever a change occurs in the
composition of any of these coating
materials. The owner or operator shall
compute the weighted average by the
fallowing equation:
I CS. x VOLS. « SC
VOLS. x SC
where:
C = Jhe weighted averaged VOC content of
all the coating materials used in an EDP
system.
CS, = the VOC content of the material in
each coating makeup stream.
VOLSi = the volume (cubic meter*) of each
makeup stream added to the EDP tank
during the previous month.
SC, = the solid content of the material in
each coating makeup stream expressed
as a volume fraction.
n = the number of makeup streams.
(3) Determine the average VOC
content of the coating materials in any
surface coating operation which uses
spray application whenever a change
occurs in the composition of any of
these coating materials. The owner or
operator shall determine and record the
arithmetic average of the VOC content
of all coating materials in a coating
operation which uses more than one
coating material.
(b) Any owner or operator subject to
the provisions of this subpart shall
report for each calendar quarter all
measurement results as follows:
(1) Where compliance with § 60.392 is
achieved without the use of add-on
control devices, any month during
which—
(i) The weighted average VOC content
of the makeup materials used in any
prime coat operation employing EDP
exceeds the most recent value which
demonstrated compliance with
{ 60.392(a) by the performance test
required in j 60.8.
(ii) The arithmetic average VOC
content of the coating materials used in
any surface coating operation employing
spray application exceeds the most
recent value which demonstrated
compliance with $ 60.392 by the
performance test required in $ 60.8.
(2) Where compliance with $ 60.392 is
achieved by the use of incineration, all
periods in excess of 5 minutes during
which the temperature in any
incinerator used to control the emission
from a surface coating operation
remains below the most recent level
which demonstrated compliance with
§ 60.392 by the performance tests
required in $ 60.8. The report required
under § 60.7(c) shall identify each such
occurrence and its duration.
(3) The reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless EPA takes affirmative action to
extend them.
§ 60.394 Test method* and procedures.
(a) The reference methods in
Appendix A to this part, except as
provided for in 5 60.8(b), shall be used to
determine compliance with § 60.392 as
follows:
(1) The owner or operator shall use
Reference Method 24 (Candidate 1 or
Candidate 2) to measure the VOC
content of every coating or makeup
material used in each surface coating
operation of an automobile or light-duty
truck surface coating line. The coating
sample shall be a 1 liter sample taken at
a point where the sample will be
representative of the coating material as
applied to the vehicle surface. The 1 liter
sample shall be divided into three
aliquots for triplicate determinations by
Method 24 (Candidate 1 or Candidate 2).
(2) The owner or operator shall
compute the arithmetic average VOC
content of all coating materials used in
each surface coating operation that uses
spray application.
(3) The owner or operator shall use
the calculation procedures given in
§ 60.393(a)(2J to compute the weighted
average VOC content of all makeup
materials added to an EDP tank during a
selected one month period for each
prime coat operation that uses EDP.
(4) The owner or operator shall
determine the VOC emissions by the
equation:
E =
where
E = the VOC emissions
C = the average VOC content of all the
coating or makeup materials used in that
operation. The owner or operator shall
use an arithmetic average for systems
using spray application and a weighted
average for systems using EDP.
TE=the appropriate transfer efficiency as
determinetHn paragraph (a)(5) of this
section.
(5] The owner or operator shall select
the appropriate transfer efficiency from
the following table for each surface
coating operation.
Apphcsbon method
Tiwwfcr
efficiency (TE)
Air /Men**) Spray -
Manual BectraeUbc Spray
Automatic Electrostatic Spray _
EtoctrodefXMWon _
9.40
ars
toe
If the owner or operator can justify to
the Administrator's satisfaction that
other values for transfer efficiencies are
appropriate, the Administrator will
approve their use on a case-by-case
basis. Where more than one application
method is used on an individual surface
coating operation, the owner or operator
shall perform an analysis to determine
the relative volume of solids coating
materials applied by each method. The
owner or operator shall use these
relative volumes of solids to compute a
weighted average transfer efficiency for
the operation. The Administrator will
review and approve this analysis on a
case-by-case basis.
(bj For each surface coating operation
which cannot achieve compliance with
§ 60.392 without the use ef add-on
control devices, the owner or operator
shall use the following procedures to
determine that the emission reduction
efficiency of the control device(s) is
sufficient to achieve compliance with
§ 60.392:
(1) The owner or operator shall
compute the emission reduction
efficiency required for each surface
coating operation by the following
equation:
EL
* 100
where:
ER = the required emission reduction
efficiency (in percent) for the applicable
surface coating operation to achieve
compliance with 5 60.392.
E =-- the VOC emissions from the applicable
surface coating operation.
EL - the numerical VOC emission limit in
§ 60.392 for the applicable surface
coating operation.
(2) The owner or operator shall
determine the emission reduction
efficiency achieved by the control
device(s) on each applicable surface
coating operation as follows:
(i) The owner or operator shall use
Reference Method 25 to determine the
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VOC concentration in the effluent gas
before and after the emission control
device for each stack that is equipped
with an emission control device. The
owner or operator shall use Reference
Method 2 to determine the volumetric
flowrate of the effluent gas before and
after the emission control device on
each stack. The Administrator will
approve testing of representative stacks,
on a case-by-case basis, if the owner or
operator can show to the
Administrator's satisfaction that testing
of representative stacks yields results
comparable to those that would be
obtained by testing all stacks.
(ii) For Method 25, the sampling time
for each run shall be at least 60 minutes
and the minimum sample volume shall
be at least 0.003 dscm (0.106 dscf) except
that shorter sampling times or smaller
volumes, when necessitated by process
variables or other factors, may be
approved by the Administrator.
(iii) The owner or operator shall
determine the efficiency of each
emission control device by the following
equation:
EFF = (CB x VOLB) - (CA x VOLA) x m
(CB x VOLB)
where:
EFF=the emission control device efficiency,
in percent.
CB=the concentration of VOC in the effluent
gas before the emission control device, in
parts per million by volume.
CA = the concentration of VOC in the effluent
gas after the emission control device, in
parts per million by volume.
VOLA = the volumetric flow rate of the
effluent gas after the emission control
device, in dry standard cubic meters per
second.
VOLB = the volumetric flow rate of the
effluent gas before the emission control
device, in dry standard cubic meters per
second,
If an emission control device controls
the emissions from more than one stack,
the owner or operator shall measure CB
and VOLB at a location between the
manifold that receives all the exhausts
from the applicable surface coating
operation and the control device. If a
manifold is not used, the product
CBxVOLB shall be replaced by the sum
of the individual products for each stack
on the applicable surface coating
operation controlled by this device.
(iv) The owner or operator shall
determine the fraction of the total VOC
discharged from an applicable surface
coating operation which enters each
emission control device on that
operation by the following equation:
CB. x VOLB
i n
I (CBt x VOLB,)
k=l *• "
where:
F, = the fraction of the total VOC discharged
from the applicable surface coating
operation which enters the emission
control device.
CB,=the value of CB for stack (k) on the
applicable surface coating operation.
CBk = the value of CB for each stack (k) on
the applicable surface coating operation.
VOLB,-the value of VOLB for each emission
control device (i).
VOLBi = the value of VOLB for each stack (k)
on the applicable surface coating
operation.
n = the number of stacks on the applicable
surface coating operation.
The owner or operator shall use the
procedures contained in clause (ii) of
this subparagraph for any emission
control device (i) that controls the
emissions from more than one stack.
(v) The owner or operator shall
determine the emission reduction
efficiency achieved by the control
device(s) on the applicable surface
coating operation using the equation:
EA = I (F x EFF )
where:
EA=the emission reduction efficiency
achieved, in percent.
EFF, = the emission reduction efficiency (in
percent) of each control device on the
applicable surface coating operation.
m = the number of control devices on the
applicable surface coating operation.
(3) If EA is greater than or equal to
ER, the applicable surface coating
operation will be in compliance with
§ 60.392.
§60.395 Modifications.
(a) The following physical or
operational changes are not, by
themselves, considered modifications of
existing facilities:
(1) Changes as a result of model year
changeovers or switches to larger cars.
(2) Changes in the application of the
coatings to increase paint film thickness.
Appendix A — Reference Methods
3. Method 24 (Candidate 1), Method 24
(Candidate 2), and Method 25 are added
to Appendix A as follows:
Method 24 (Candidate 1)—Determination of
Volatile Content (as Carbon) of Paint,
Vamish, Lacquer, or Related Products
1 Applicability and Principle
1.1 Applicability. This method is
applicable for the determination of volatile
content (as carbon) of paint, varnish, lacquer,
and related products listed in Section 2.
1.2 Principle. The weight of volatile
carbon per unit volume of solids is calculated
for paint, varnish, lacquer, or related surface
coating after using standard methods to
determine the volatile matter content, density
of the coating, density of the solvent, and
using the oxidation-nondispersive infrared
(NDIR) analysis for the carbon content.
2. Classification of Surface Coating
For the purpose of this method, the
applicable surface coatings are divided into
two classes. They are:
2.1 Class I: General Solvent- Type Paints
and Water Thinned Paints. This class
includes white linseed oil outside paint, white
soya and phthalic alkyd enamel, white
linseed o-phthalic alkyd enamel, red lead
primer, zinc chromate primer, flat white
inside enamel, white epoxy enamel, white
vinyl toluene, modified alkyd, white amino
modified baking enamel, and other solvent-
type paints not included in class II. It also
includes emulsion or latex paints and colored
enamels.
2.2 Class II: Varnishes and Lacquers. This
class includes clear and pigmented lacquers
and varnishes.
3 Applicable Standard Methods
Use the apparatus, reagents, and
procedures specified in the standard methods
below:
3.1 ASTMD1644-59 Method A Standard
Methods of test for Non-volatile Contents of
Varnishes. Do not use Method B.
3.2 ASTMD 1475-60. Standard Method of
Test for Density of Paint, Lacquer, and
Related Products.
3.3 ASTM D 2369-73: Standard Method
of Test for Volatile Content of Paints.
3.4 ASTM D 3272-76: Standard
Recommended Practice for Vacuum
Distillation of Solvents from Solvent-Base
Paints for Analysis.
4. Apparatus (Oxidation/NDIR Procedure)
4.1 Electric Furnace. Capable of
maintaining a temperature of 800+50° C.
4.2 Combustion Chamber. Stainless steel
tubing, 13 mm (Vi in ) internal diameter and
46 cm (18 in.) in length. Pack the tube loosely
with 3 mm (Ve in.) alumina pellets coated
with 5 percent palladium. Place plugs of
stainless steel wool at either end Other
catalytic systems which can demonstrate 95
percent efficiency as described in Section
65.4 are considered equivalent
4.3 Septum. Teflon '-coated rubber
septum.
4.4 Condenser. Ice bath condenser
4.5 Analyzer. Nondispersive infrared
analyzer (NDIR) to measure COi TO WITHIN
<>S PERCENT OF THE CALIBRATION GAS
CONCENTRATION.
4.6 Recorder. Capable of matching the
output of the NDIR.
4.7 Collection Tank. A collection tank of
at least 6 liters in volume. See procedure in
Section 6.5 1 for calibrating the volume of the
tank. The tank should be capable of
1 Mention of trade names or specific products
does not constitute endorsement by the
Environmental Protection Agency.
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withstanding a pressure of 2000 mm (80 in.)
Hg (gauge).
4.8 Pressure Gauge for Collection Tank.
Capable of measuring positive pressure to
1100 mm (42 in.) Hg and vacuum pressure to
700±5 mm (28±0.25 in.) Hg.
4.9 Vacuum Pump. Capable of evacuating
the collection tank to an absolute pressure of
51 mm (2 in.) Hg.
4 10 Analytical Balance. To measure to
within ±0.5 mg.
4.11 Syringes. 100±1.0 f»l. S00±1.0 /il.
and 1000 ±5 pi syringe, with needles long
enough to inject sample directly into the
carrier gas stream.
4.12 Mixer. Vortex-mixer to ensure
homogeneous mixing of solvent.
4.13 Flow Regulators. Rotameters. or
equivalent, to measure to 500 cc/min in flow-
rate.
4.14 Temperature Gauge. A thermometer
graduated in 0.1° C. with range from 0° C to
100° C.
4 15 Tank Calibration Equipment. A
balance to weigh collection tank to ±30 g or
a graduated glass cylinder to measure tank
volume within ±30 ml.
5. Reagents (Oxidation/NDIR Procedure)
5 1 Calibration Gases.
5.1.1 Zero Gas. Ni trogen.
5.1.2 CO, Cas. A range of concentration
to allow at least a 3-poinl calibration of each
measuring range of the instrument.
5.1.3 Carrier Gas. Air containing less than
1 ppm hydrocarbon as carbon, as certified by
the manufacturer.
5.2 Catalyst. Alumina (3 mm pellets)
coated with 5 percent palladium, or
equivalent (commercially available).
5.3 Acetone. Reagent grade.
5.4 Nitric Acid Solution. Dilute 70 percent
nitric acid 1:1 by volume with distilled water.
5.5 1-Butanol. -Ninety-nine molecular
percent pure.
5.6 Methane Gas 0.5 percent methane in
air
6 Procedure
6 1 Classification of Samples. Assign the
coating to one of the two classes discussed in
Section 2 above. Assign any coating not
clearly belonging to Class II to Class I.
6 2 Volatile Content. Use one of the
following methods to determine the volatile
content according to the class of coating
82 1 Class I. Use the Procedure in ASTM
D 2369-73 Record the following information:
W, = Weight of dish and sample, g.
Wj = Weight of dish and sample after heating,
8
S = Sample we:ght, g
Repeat the procedure for a total of three
determinations for each coating Calculate
the weight fraction of volatile matter W for
each analysis as follows.
"1
Report the arithmetic average weight fraction
W of the three determinations.
6.2.2 Class II. Use the procedure in ASTM
D 1644-59 Method A: record the following
information:
A = Weight of dish. g.
B=Weight of sample used, g.
C=Weight of dish and sample after heating.
g
Repeat the procedure for a total of three
determinations for each coating. Calculate
the weight fraction W of volatile content for
each analysis as follows:
u . (A * B - C)
6.5.3 Assemble the oxidation system as
shown in Figure 1. Heat the catalyst until the
temperature reaches equilibrium at 800 ±50'
C. Add ice to the condenser and remove
excess water to maintain the temperature at
O'C.
B
Report the arithmetic average weight fraction
W of three determinations.
6.3 Coating Density. Determine the
density Dm (in g/cm^ of the paint, varnish,
lacquer, or related product of either class
according to the procedure outlined in ASTM
D 1475-60. Make a total of'three
determinations for each coating. Report the
density Dm as the arithmetic average of the
three determinations.
6.4 Solvent Density.
6.4.1 Perform .the solvent extraction
according to the procedure outlined in ASTM
D 3272-76. For aqueous paint, use a
collection-rube m an ice-bath prior to the
collection-tube in the acetone and dry-ice
mixture to prevent water from freezing in the
collection-tube Combine the contents of both
tubes before analysis. If excessive foaming
occurs during distillation, discard the sample.
and repeat with a new sample treated with
an anti-foam spray (e.g Dow Coming's "Anti-
foam A Spray) before distillation. Anti-foam
spray must be nonorganic and nonflammable.
Use spray sparingly.
6.4.2 Determine the density D,(ing/cm*)
of the solvent according to the procedure
outlined in ASTM D 1475-60 Make a total of
three determinations for the solvent, and
report the average density D, as the
arithmetic average of the three
determinations.
6.5 Carbon Content of the Solvent.
Analyze the solvent within 24 hours after
distillation; keep it under refrigeration when
not in use. To determine the carbon content.
follow the procedure below:
6.5.1 Clean and calibrate the collection
tank as follows Rinse the inside of the tank
once with acetone, twice with tap water.
thrice with the nitric acid solution, and twice
with tap water. Weigh the tank when empty
and when full of water. Measure the
temperature of the water, and calculate the
volume as follows
Where
t = Temperature of the water. °C (°F)
V = Volume of the tank. nil.
We = Weight of the empty tank. g.
W,=Weight of the full tank, g.
D, = Density of water at temperature t. g/ml
Alternatively, measure the volume of water
necessary to fill the tank. The volume of the
tank connections and pressure gauge are
negligible for a tank volume of at least 6
liters
6.5.2 Calibrate the NDIR according to the
manufacturer's instruction. Use at least a 3-
point calibration. Introduce the COa
calibration gas through the analysis line.
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6.S.4 Determination of Conversion
Efficiency. Pass O.S percent methane gas In
•ir through carrier gas line; 0.5 percent CO.
should be generated within ±5 percent error.
Using a 100 n\ sample of 1-butanol. follow the
procedure in 6.5.5 to 6.5.13. Calculate the
theoretical COi volume percent as in Section
7.3. This value should equal the value as
measured by the NDIR, within ±5 percent
error. If conversion efficiency is 100 ±5
percent, analyze the solvent extracted from
the paint according to procedure in Sections
6.5.5 to 6.5.14.
6.5.5 Purge the collection tank twice with
Ni. then evacuate the tank to at least 50.8 mm
(2 in.) Hg absolute pressure. Connect the
cylinder to the collection line.
6.5.6 Mix the solvent sample thoroughly
on a vortex-mixer. Then, draw a sample
(0.100 to 0.300 ml) into the syringe. Record the
volume of sample used.
6.5.7 Turn analysis valve to "sample"
position, and turn the sample valve to "vent"
position. Then turn on the carrier gas at a
rate of 500 cc/min to flush the system for 2
minutes.
6.5.8 With gas flowing at 500 cc/min
(maintain this rate throughout the test
procedure), turn sample valve to "sample"
position. Open the tank valve and inject the
sample into the gas stream through the
injection septum. Continue to draw the
•ample into the tank until the NDIR'reads
lero. (Note.— On replicate samples, a
decrease in peak value indicates that the
catalyst or sample has deteriorated, assuming
that other factors, such as leaks, cell
contamination, mechanical defects of the
instruments, etc., have not occurred.)
6.5.9 At completion of collection, close the
tank valve, and turn sample valve to "vent"
position. Let the carrier gas flush the system
for 2 minutes, then turn off the carrier gas.
6.5.10 Disconnect the tank and pressurize
it with N. to about 1016 mm (40 in.) Hg gauge
pressure. Record the final tank pressure after
pressurization, the atmospheric pressure, and
the room temperature.
6.5.11 Connect the tank to the analysis
line and turn the analysis valve to "analysis"
position.
6.5.12 Pass the CO, sample gas at the
tame rate as the calibration gas. Keep the
rite constant by adjusting the rotameter as
tank pressure falls.
6.5.13 Record the CO, concentration when
the peak value is reached. This peak value
will remain constant as long as the sample
gas continues to flow at a constant rate.
6.5.14 Repeat steps 6.5.5 through 6.5.13
until three consecutive results are obtained
which differ from one another in value by no
more than ±5 percent. At the end of the third
test, check the catalyst function by passing
the collected sample gas through the catalyst
and into the NDIR No increase in
concentration value should occur. If the
concentration is higher, invalidate the test
series, replace the catalyst and repeat the
test.
6.5.15 Report the results as an arithmetic
average of the three determinations.
7. Calculations. Carry out the calculations,
retaining at least one extra decimal figure
beyond that of the acquired data. Round off
figures after decimal calculation.
7.1 Nomenclature.
C,» Volatile matter content as carbon per
unit volume of paint solids, g/1 (Ib/gal).
Dt-Density of 1-ButanoI, g/cm>.
D.—Average coating density, g/cm* (See
Section 6.3).
D,=Average solvent density, g/cm' (See
Section 6.4).
L*» Volume of 1-Butanol used in the test cm*.
U—Volume of paint solvent used in the test,
cm'.
74.12=Molecular weight of 1-BuIanol.
Mc^Mass of carbon, g.
4=Number of carbon atoms in 1-Butanol.
f*i=Absolute standard pressure, 760 mm Hg
(29.92 in. Hg):
P,=Absolute final tank pressure after
pressurization, mm Hg (in. Hg).
TMa= Absolute standard temperature, 293° K
(528' R).
T,-Absolute tank temperature, 'K (°R).
%Solv.«= Volume percent of solvent in paint
coating.
Vco,=Volume of CO, in liters, at standard
temperature and pressure.
VB=Total gas volume, corrected to standard
conditions, in liters.
V,c=Volume percent of CO..
V,=Volume of tank, liters.
W=Weight fraction of volatile matter
content.
7.2 Total Gas Volume, Corrected to
Standard Conditions.
Where:
K,=17.65 for English units.
Ki=0.3855 for Metric units.
73 Volume Percent of COf From 1-
Butanol:
*pc ' V " Equation 2
9*
7.4 Mss of Carbon
"c ' V V,» 2TBT OT «*•«« 3
7.5 Ptrctnt Volunt Solvtnt In P«!nt.
ff
Bol». • U J- (100) Equation 4
7.6 VolttUt Katttr Content as Carbon.
[((nation 5
Where:
K.-8.3445 for English units.
Ki-lOOQ for Metric units.
& Bibliography.
6.1 Standard Methods of Test for
Nonvolatile Content of Varnishes. In: 1974
Book of ASTM Standards. Part 27.
Philadelphia, Pennsylvania, ASTM
' Designation D 1644-59.1974. p. 285-286.
A2 Standard Method of Test for Volatile
Content of Paints. In: 1978 Book of ASTM
Standards, Part 27. Philadelphia,
Pennsylvania. ASTM Designation D 2360-73.
1978. p. 431-432.
A3 Standard Method of Test for Density
of Paint. Varnish, lacquer, and Related
Products. In: 1974 Book of ASTM Standards.
Part 25. Philadelphia, Pennsylvania. ASTM
Designation D 1476-60.1974. p. 231-233.
8.4 Standard Recommended Practice for
Vacuum Distillation of Solvents from
Solvent-Base Paints for Analysis. In: 1978
Annual Book of ASTM Standards, Part 27.
Philadelphia. Pennsylvania, ASTM
Designation D 3272076.1978. p. 612-614.
8.S So/o, Albert E., William L. Oaks, and
Robert D. MacPhee. Total Combustion
Analysis. Air Pollution Control District-
County of Los Angeles. August 1974.
Method 24 (Candidate 2)—
Determination of Volatile Organic
Compound Content (as Mass) of Paint.
Varnish, Lacquer, or Related Products
I. Applicability and Principle.
1.1 Applicability. This method applies to
the determination of volatile organic
compound content (as mass) of paint,
varnish, lacquer, and related products listed
in Section 2.
1.2 Principle. Standard methods are used
to determine the volatile matter content,
density of the coating, volume of solid, and
water content of the paint, varnish, lacquer.
and related surface coating. From this
information, the mass of volatile organic
compounds per unit volume of solids is
calculated.
2. Classification of Surface Coating. For the
purpose of this method, the applicable
surface coatings are divided into three
classes. They are:
2.1 Class I: General Solvent Reducible
Paints. This class includes white linseed oil
outside paint, white soya and phthalic alkyd
enamel, white linseed o-phthalic alkyd
enamel, red lead primer, zinc chroma te
primer, flat white inside enamel, white epoxy
enamel, white vinyl toluene, modified alkyd,
white amino modified baking enamel, and
other solvent-type paints not included in
Class II.
2.2 Class II: Varnishes and Lacquers. This
class includes clear and pigmented lacquers
and varnishes.
2.3 Class III. This class includes all water
reducible paints.
3. Applicable Standard Methods. Use the
apparatus, reagents, and procedures specified
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4.2 Non-Aqueous Volatile Content. Use
one of the following methods to determine
the non-aqueous volatile content according to
the class of coating.
4.2.1 Class 1. Use the procedure in ASTM
D 2369-73; record the following information:
W, = Weight of dish and sample, g.
W>=Weight of dish and sample after heating
g
S = Sample of weight, g.
Repeat the procedure for a total of three
determinations for each coating. Calculate
the weight fraction of non-aqueous volatile
matter Wv for each analysis as follows:
•l
Report the arithmetic average weight
fraction Wv of the three determifiations.
4.2.2 Class II. Use the procedure in ASTM
D 1644-75 Method A, record the following
information:
A = Weight of dish. g.
B=Weight of sample used, g.
C = Weight of dish and sample after heating,
g
Repeat the procedure for a total of three
determinations-for each coating. Calculate
the weight fraction W, of non-aqueous
volatile content for each analysis as follows:
w . (* * B - C)
Report the arithmetic average weight
fraction Wv of the three determinations
4.2.3 Class III.
4.231 Water Content. Determine the
water content (in % HjO) of the coating
according to either "Provisional Method of
Test for Water in Water Reducible Paint by
Direct Injection into a Gas Chromatograph"
or "Provisional Method of Test for Water in
Paint or Related coatings by the Karl Fischer
Titration Method." Repeat the procedure for
a total of three determinations for each
coating. Report the arithmetic average weight
percent % HjO of the three determinations.
4232 Volatile Content (Including Water).
Use the procedure in ASTM D 2369-73;
record the following information:
Wi = Weight of dish and sample, g.
Wj=Weight of dish and sample after heating,
g
S = Sample weight, g.
Repeat the procedure for a total of three
determinations for each coating. Calculate
the weight fraction of volatile matter as
follows
Report the arithmetic average weight
fraction V of the three determinations.
4.2.3.3 Non-Aqueous Volatile Matter.
Calculate the average non-aqueous volatile
mailer Wv as follows:
4.3 Coating Density. Determine the
density D. (in g/cm3) of the paint, varnish,
lacquer, or related product of any class
according to the procedure outlined in ASTM
D 1475-60. Make a total of three
determinations for each coating. Report the
density Dm as the arithmetic average of the
three determinations.
4.4 Non-Volatile Content. Determine the
volume fraction of the non-volatile matter of
the coating of any class according to the
procedure outlined in ASTM D 2697-73.
Calculate the volume fraction Pn of non-
volatile matter as follows
* Volume Nonvolatile Matter
res
"TOT
Make a total of three determinations for
each coating. Report the arithmetic average
volume fraction Pr of the three
determinations.
5. Volotile Organic Compounds Content.
Calculate the volatile organic compound
content Cm in terms of mass per volume of
solids (g/liter) as follows
U 0
v m
To convert g/liter to Ib/gal. multiply Cm by
8.3455 X 10"'.
6. Bibliography
61 Standard Methods of Test of
Nonvolatile Content of Varnishes. In. 1974
Book of ASTM Standards, Part 27.
Philadelphia. Pennsylvania, ASTM
Designation D 1644-75. 1978. p 288-289.
6.2 Standard Method of Test for Volatile
Content of Paints. In: 1978 Book of ASTM
Standards, Part 27. Philadelphia,
Pennsylvania. ASTM Designation D 2369-73.
1978 p. 431-432.
6.3 Standard Method of Test for Density
of Paint Varnish. Lacquer, and Related
Products. In. 1974 Book of ASTM Standards,
Part 25 Philadelphia, Pennsylvania. ASTM
Designation D 1476-60. 1974. p. 231-233.
6.4 Standard Method of Test for Water in
Water Reducible Paint by Direct Injection
into a Gas Chromatograph. Available from:
Chairman. Committee D-l on Paint and
Related Coatings and Materials, American
Society for Testing and Materials, 1916 Race
St., Philadelphia, PA 19103. ASTM
Designation D 3792.
6.5 Draft method of Test for Water in
Paint or Related Coatings by the Karl Fischer
Titration Method. Available from: Chairman,
Committee D-l on Paint and Related
Coatings and Materials. American Society for
Testing and Materials. 1916 Race St.,
Philadelphia, PA 19103.
Method 25—Determination of Total
Gaseous Nonmethane Organic
Emissions as Carbon: Manual Sampling
and Analysis Procedure
1. Principle and Applicability.
1.1 Principle. An emission sample is
anisokmetically drawn from the stack
through a chilled condensate trap by means
of an evacuated gas collection tank. Total
gaseous nonmethane organics (TGNMO) are
determined by combining the analytical
results obtained from independent analyses
of the condensate trap and evacuated tank
fractions. After sampling is completed, the
organic contents of the condensate trap are
oxidized to carbon dioxide which is
quantitatively collected in an evacuated
vessel; a portion of the carbon dioxide is
reduced to methane and measured by a flame
ionization detector (FID) A portion of the
sample collected in the gas sampling tank is
injected into a gas chromatographic (GC)
column to achieve separation of the
nonmethane organics from carbon monoxide,
carbon dioxide and methane; the nonmethane
organics are oxidized to carbon dioxide,
reduced to methane, and measured by a FID
1.2 Applicability. This method is
applicable to the measurement of total
gaseous nonmethane organics in source
emissions.
2. Apparatus.
2.1 General. TGNMO sampling equipment
can be constructed by a laboratory from
commercially available components and
components fabricated in a machine shop
The primary components of the sampling
system are a condensate trap, flow control
system, and gas sampling lank (Figure 1). The
analytical system consists of two major
subsystems, an oxidation system for recovery
of the sample from the condensate trap and a
TGNMO analyzer. The TGNMO analyzer is a
FID preceded by a reduction catalyst.
oxidation catalyst, and GC column with
backflush capability (Figures 2 and 3). The
system for the removal and conditioning of
the organics captured in the condensate trap
consists of a heat source, oxidation catalyst.
nondispersive infrared (ND1R) analyzer and
an intermediate gas collection tank (Figure 4).
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tn
3
*-<
CD
CO
Q.
Q.
CD
o.
E
CO
CO
0)
u.
D
cn
2 UJ
"5°=
V-MM-19
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Federal Register / Vol. 44. No. 195 / Friday. October 5,1979 / Proposed Rules
CARRIER GAS
CALIBRATION STANDARDS
SAMPLE TANK
INTERMEDIATE
COLLECTION
VESSEL
(CONDITIONED TRAP SAMPLE)
NON-METHANE
ORGANICS
REDUCTION
CATALYST
1
FLAME
IONIZATION
DETECTOR
HYDROGEN
COMBUSTION
AIR
Figure 2. Simplified schematic of total gaseous non-methane
organic (TGNMO) analyzer.
V-MM-20
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2
5
O
5
Z
5
3
3)
V-MM-21
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FLOW
METERS
t, CONTROL
II *rV VALVES \
SWITCHING
VALVES
CONNECTORS
CATALYST
BYPASS
CARRIER
15 percent
02/N2
SAMPLE
CONDENSATE
TRAP
OXIDATION
CATALYST
HEATED
CHAMBER
REGULATING
ROTAMETER
NDIR
ANALYZER
FOR MONITORING PROGRESS
OF COMBUSTION ONLY
QUICK
CONNECT
V
H20
TRAP
INTERMEDIATE
COLLECTION
VESSEL
VACUUM*'
PUMP
MERCURY *»FOR EVACUATING COLLECTION
MANOMETER VESSELS AND SAMPLE TANKS
Figure 4. Condensate recovery and conditioning apparatus.
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2.2 Sampling.
2.2.1 Probe. V»" stainless steel tubing.
2.2.2 Condensate Trap. The condensate
trap shall be constructed of 316 stainless
steel; construction details of a suitable trap
are shown in Figure 5.
2.2.3 Flow Shut-off Valve. Stainless steel
control valve for starting and stopping
sample flow. -•
2.2.4 Flow Control System. Any system
capable of maintaining the sampling rate to
within ±10 percent of the selected flow rate
(50—100 cc/min. range).
2.2.S Vacuum Gauge. Vacuum gauge
calibrated in mm Hg. for monitoring the
vacuum of the evacuated sampling tank
during leak checks and sampling
2.2.6 Gas Collection Tank. Stainless steel
or aluminum lank with a volume of 4 to 8
liters. The tank is fitted with a stainless steel
female quick connect for assembly to the
sampling train and analytical system.
2.2.7 Mercury manometer. U-tube mercury
manometer capable of measureing pressure
to within 1.0 mm Hg in the 0/900 mm range.
2.2.8 Vacuum Pump. Capable of
pulling a vacuum of 700 mm Hg.
2.3 Analysis. For analysis, the
following equipment is needed.
2.3.1 Condensate Recovery and
Conditioning Apparatus (Figure 4).
2.3.1.1 Heat Source. A heat source
sufficient to heat the condensate trap to
a temperature just below the point
where the trap turns a "cherry red"
color is required. An electric muffle-type
furnace heated to 600" C is
recommended.
2.3.1.2 Oxidizing Catalyst. Inconel
tubing packed with an oxidizing catalyst
capable of meeting the catalyst
efficiency criteria of this method
(Section 4.4.2).
2.3.1.3 Water Trap. Any leak proof
moisture trap capable of removing
moisture from the gas stream may be
used.
2.3.1.4 NDIR Detector. A detector
capable of indicating COS concentration
in the zero to 5 percent range. This
detector is required for monitoring the
progress of combustion of the organic
compounds from the condensate trap.
2.3.1.5 Pressure Regulator. Stainless
steel needle valve required to maintain
the NDIR detector cell at a constant
pressure.
2.3.1.6 Intermediate Collection Tank.
Stainless steel or aluminum collection
vessel. Tanks with nominal volumes in
the 1 to 4 liter range are recommended.
The end of the tank is fitted with a
female quick connect.
2.3.2 Total Gaseous Nonmethane
Organic (TGNMO) Analyzer. Semi-
continuous GC/FID analyzer capable of:
(1) separating CO, COj, and CH4 from
nonmethane organic compounds, and (2)
oxidizing the non-methane organic
compounds to CO», reducing the CO2 to
methane, and quantifying the methane.
The analyzer shall be demonstrated
prior to initial use to be capable of
proper separation, oxidation, reduction,
and measurement. As a minimum, this
demonstration shall include
measurement of a known TGNMO
concentration present in a mixture that
also contains CH4, CO, and CO2 (see
paragraph 4.4.1).
2.3.2.1 The TGNMO analyzer
consists of the following major
components.
2.3.2.1.1 Oxidation Catalyst. Inconel
tubing packed with an oxidation
catalyst capable of meeting the catalyst
efficiency criteria of paragraph 4.4.1.2.
2.3.2.1.2 Reduction Catalyst. Inconel
tubing packed with a reduction catalyst
capable of meeting the catalyst
efficiency criteria of paragraph 4.4.1.3.
2.3.2.1.3 Separation Column. A gas
chromatographic column capable of
separating CO, COj, and CH, from
nonmethane organic compounds. The
specified column is as follows: Va inch
O.D. stainless steel packed with 3 feet of
10 percent methyl silicone, Sp 2100* (or
equivalent) on Supelcoport* (or
equivalent), 80/100 mesh, followed by
1.5 feet porapak Q* (or equivalent) 60/80
mesh. The inlet side is to the silicone.
Other columns may be used subject to
the approval of the Administrator. In
any event, proper separation shall be
demonstrated according to the
procedures of paragraph 4.4.1.4.
2.3.2.1.4 Sample Injection System. A
gas chromatographic sample injection
valve with sample loop sized to properly
interface with the TGNMO system.
2.3.2.1.5 Flame lonization Detector
(FID). A flame ionization detector
meeting the following specifications is
required:
2.3,2.1.5.1 Linearity. A linearity of
±5 percent of the expected value for
each full scale setting up to the
maximum percent absolute (methane or
carbon equivalent) calibration point is
required. The FID shall be demonstrated
prior to initial use to meet this
specification through a 5-point
(minimum) calibration. There shall be at
least one calibration point in each of the
following ranges: 5-10, 50-100, 500-1,000,
5,000-10,000, and 40,000-100,000 ppm
(methane or carbon equivalent).
Certification of such demonstration by
the manufacturer is acceptable. An
additional linearity performance check
(see Section 4.4.1.1) must be made
before each use (i.e., before each set of
samples is analyzed or daily whichever
occurs first).
2.3.2.1.5.2 Range. Signal attenuators
shall be available so that a minimum
'Mention of trade name does not constitute
endorsement.
signal response of 10 percent of full
scale can be produced when analyzing
calibration gas or sample.
2.3.2.1.5.3 Sensitivity. The detector
sensitivity shall be equal to or better
than 2.0 percent of the full scale setting.
with a minimum full scale setting of 10
ppm (methane or carbon equivalent)
2.3.2.1.6 Data Recording System
Analog strip chart recorder or digital
integration system for permanently
recording the analytical results.
2.3.3 Mercury Manometer L'-tube
mercury manometer capable of
measuring pressure to within 1.0 mm Hg
in the 0-900 mm range.
2.3.4 Barometer. Mercury, aneroid, or
other barometer capable of measuring
atmospheric pressure to within 1 mm.
2.3.5 Vacuum Pump. Laboratory
vacuum pump capable of evacuating the
sample tanks to an absolute pressure of
5 mm Hg.
3. Reagents.
3.1 Sampling.
3.1.1 Crushed Dry Ice.
3.2 Analysis.
3.2.1 TGNMO Analyzer.
3.2.1.1 Carrier Gas. Pure helium,
containing less than 1 ppm organics.
3.2.1.2 Fuel Gas. Pure Hydrogen,
containing less than 1 ppm organics.
3.2.2 Condensate Recovery and
Conditioning Apparatus.
3.2.2.1 Carrier Gas. Five percent O,
in N2, containing less than 1'ppm
organics.
3.3 Calibration For all calibration
gases, the manufacturer must
recommend a maximum shelf life for
each cylinder so that the gas
concentration does not change more
than ±5 percent from its certified value
The date of gas cylinder preparation,
certified organic concentration and
recommended maximum shelf life must
be affixed to each cylinder before
shipment from the gas manufacturer to
the buyer.
3.3.1 TGNMO Analyzer
3.3.1.1 Oxidation Catalyst Efficiency
Check. Gas mixture standard with
nominal concentration of 5 percent
methane and 5 percent oxygen in
nitrogen.
3.3.1.2 Reducation Catalyst
Efficiency Check. Gas mixture standard
with nominal concentration of 5 percent
CO2 in air.
3.3.1.3 Flame lonizafion Detector
Linearity Calibration Gases (3). Gas
mixture standards with known methane
(CH4) concentrations in the 5-10 ppm.
500-1,000 ppm, and 5-10 percent range.
in air. These gas standards are to be
used to check the FID linearity as
described in Section 4.4.1.1.
3.3.1.4 System Operation Standards
(2). These calibration gases are required
V-MM-23
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Federal Register / Vol. 44. No. 195 /Friday, October 5. 1979 / Proposed Rules
to check the total system operation as
specified in Section 4.4.1.4. Two gas
mixtures are required:
3.3.1.4,1 Gas mixture standard
containing (nominal) 50 ppm CO, 50 ppm
CH4. 2 percent CO2, and 15 ppm C3HS,
prepared in air.
3.3.1.4.2 Gas mixture standard
containing (nominal) 50 ppm CO, 50 ppm
CH,, 2 percent CO», and 1,000 ppm C3H,,
prepared in air.
3.3.2 Condensate Recovery and
Conditioning Apparatus. The calibration
gas specified in paragraph 3.3.1.1 is
required for performing an oxidation
catalyst check according to the
procedure of paragraph 4.4.2.
4. Procedure.
4.1 Sampling.
4.1.1 Sample Tank Evacuation.
Either in the laboratory or in the field,
evacuate the sample tank to 5 mm Hg
absolute pressure or less (measured by a
mercury U-tube manometer). Record the
temperature, barometric pressure, and
tank vacuum as measured by the
manometer.
4.1.2 Sample Tank Leak Check. Leak
check the gas sample tank immediately
after the tank is evacuated. Once the
tank is evacuated, allow the tank to sit
for 30 minutes. The tank is acceptable if
no change in tank vacuum (measured by
the mercury manometer) is noted.
4.1.3 Assembly. Just prior to
assembly, use a mercury U-tube
manometer to measure the tank vacuum.
Record this vacuum (Ptl), the ambient
temperature (Tti), and the barometric
pressure (Pb,) at this time. Assuring that
the flow control valve is in the closed
position, assemble the sampling system
as shown in Figure 1, Immerse the
condensate trap body in dry ice to
within 1 or 2 inches of the point where
the inlet tube joins the trap body.
4.1.4 Leak Check Procedures.
V-MM-24
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Federal Register / Vol. 44. No. 195 / Friday, October 5, 1979 / Proposed Rules
PROBE, 3mm (1/8 m) 0.0.
INLET TUBE, gram (% in) 0.0.
CONNECTOR
EX IT TUBE. 6mm (X in) 0.0
CONNECTOR
CRIMPED AND WELDED GAS-TIGHT SEAL
^BARREL 19mm (* in) O.D. X 140mm (5-Vi in) LONG.
Urom (1/16 in) WALL
NO 40 HOLE
(THRU BOTH WALLS)
WELDED JOINTS
""-BARREL PACKING. 316 SS WOOL PACKED TIGHTLY
AT BOTTOM, LOOSELY AT TOP
HEAT SINK (NUT. PRESS-FIT TO BARREL)
WELDED PLUG
MATERIAL. TYPE 316 STAINLESS STEEL
Figure 5. Condensate trap2.
V-MM-25
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Federal Register / Vol. 44. No. 195 / Friday, October S, 1079 / Proposed Rules
(A
2
to
CO
a
a
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Federal Register / Vol. 44. No. 195 / Friday, October 5,1979 / Proposed Rules
VOLATILE ORGANIC CARBON
FACILITY,
LOCATION.
DATE
SAMPLE LOCATION.
OPERATOR
RUN NUMBER
TANK NUMBER.
.TRAP NUMBER.
.SAMPLE ID NUMBER.
PRETEST (MANOMETER)
PQ$T TF$T (MANOMETER)
TANK VACUUM,
mm Hg
(GAUGE!
fRAiinn
BAROMETRIC
PRESSURE,
mm Hg
AMBIENT
TEMPERATURE,
"C
LEAK RATE, mm Hg/5 mm..
TANK
PRETEST.
POST TEST.
TRAP HALF
TIME
CLOCK/SAMPLE
GAUGE VACUUM,
mm Hg
FLOWMETER SETTING
COMMENTS
Figure 7. Example Field Data Form.
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Federal Register / Vol. 44, No. 195 / Friday. October 5. 1979 / Proposed Rules
4.1.4 1 Pretest Leak Check. A pretest
leak check is required. After the
sampling train is assembled, record the
tank vacuum as indicated by the
vacuum gauge. Wait a minimum period
of 15 minutes and recheck the indicated
vacuum. If, the vacuum has not changed,
the portion of the sampling train behind
the shut-off valve does not leak and is
considered acceptable. To check the
front portion of the sampling train,
attach the leak check apparatus (Figure
6) to the probe tip. Evacuate the front
half of the train (i.e., do not open the
sampling train flow control valve) to a
vacuum of at least 500 mm Hg. Close the
shut-off valve on the leak check
apparatus and record the vacuum
indicated by the manometer on the data
sheet (Figure 7). Allow the system to sit
for 5 minutes and then recheck the
vacuum. A change of less than 2 mm Hg
for the 5-minute leak check period is
acceptable Record the front half leak
rate (mm Hg/5-minute period) on the
data form. When an acceptable leak
rate has been obtained disconnect the
leak check apparatus from the probe tip.
4.1.4.2 Post Test Leak Check. A leak
check is mandatory at the conclusion of
each test run. After sampling is
completed, attach the U-tube manometer
to the probe tip; minimize the amount of
flexible line used. Open the sample train
flow control valve for a period of 2
minutes or until the vacuum indicated
on the manometer stabilizes, whichever
occurs first; shut off the sample train
flow control valve. Record the vacuums
indicated on the manometer (front half)
and on the tank vacuum gauge (back-
half)- After 5 minutes, recheck these
vacuum readings. A leak rate of less
than 2 mm Hg per 5-minute period is
acceptable for the front half; the back
half portion is acceptable if no visible
change in the tank vacuum gauge
occurs Record the post test leak rate
(mm Hg per 5 minutes), and then
disconnect the manometer from the
probe tip and seal the probe. If the
sampling train does not pass the post
test leak check, invalidate the run.
4.1 5 Sample Train Operation Place
the probe into the stack such that the
probe is perpendicular to the direction
of stack gas flow; locate the probe tip at
a single preselected point. For stacks
having a negative static pressure, assure
that the sample port is sufficiently
sealed to prevent air in-leakage around
the probe Check the dry ice level and
add ice if necessary. Record the clock
time and sample tank gauge vacuum. To
begin sampling, open and adjust (if
applicable) the flow control valve(s) of
the flow control system utilized in the
sampling train; maintain a constant flow
rate (± 10 percent) throughout the
duration of the sampling period. Record
the gauge vacuum and flowmeler setting
(if applicable) at 5-minute intervals.
Select a total sample time greater than
or equal to the minimum sampling time
specified in the applicable subpart of the
regulation; end the sampling when this
time period is reached or wh«n a
constant flow rate can no longer be
maintained. When the sampling is
completed, close the gas sampling tank
control valve. Record the final readings.
Note: If the sampling had to be stopped
before obtaining the minimum sampling
time (specified in the applicable
subpart) because a constant flow rate
could not be maintained, proceed as
follows: After removing the probe from
the stack, remove the evacuated tank
from the sampling train {without
disconnecting other portions of the
sampling train) and connect another
evacuated tank to the sampling train.
Prior to attaching the new tank to the
sampling train, assure that the tank
vacuum (measured on-site by the U-tube
manometer) has been recorded on the
data form and that the tank has been
leak-checked (on-site). After the new
tank is attached to the sample train,
proceed with the sampling-, after the
required minimum sampling time has
been exceeded, end the lest.
4.2 Sample Recovery. After sampling
is completed, remove the probe from the
stack and seal the probe end. Conduct
the post test leak check according to the
procedures of paragraph 4.1.4.2. After
the post test leak check has been
conducted, disconnect the condensate
trap at the flow metering system. Tightly
seal the ends of the condensate trap;
keep the trap packed in dry ice until
analysis. Remove the flow metering
system from the sample tank. Attach the
U-tube manometer to the tank (keep
length of flexible connecting line to a
minimum) and record the final tank
vacuum (PJ, record the tank
temperature (Ttl and barometric
pressure at this time. Disconnect the
manometer from the tank. Assure that
the test run number is properly
identified on the condensate trap and
evacuated tank(s)
4.3 Analysis
4.3.1 Preparation
4.3.1.1 TGNMO Analyzer. Set the
carrier gas, air, and fuel flow rates and
then begin heating the catalysts to their
operating temperatures. Conduct the
calibration linearity check required in
paragraph 4.4.1.1 and the system
operation check required in paragraph
4.4.1.4. Optional: Conduct the catalyst
performance checks required in
paragraphs 4.4.1.2 and 4.4.1.3 prior to
analyzing the test samples
4.3.1.2 Condensate Recovery and
Conditioning Apparatus. Set the carrier
gas flow rate and begin heating the
catalyst to its operating temperature.
Conduct the catalyst performance check
required in paragraph 4.4.2 prior to
oxidizing any samples.
4.3.2 Condensate Trap Carbon.
Dioxide Purge and Evacuated SampSe
Tank Pressurization. The first step in
analysis is to purge the condensate trap
of any COS which it may contain and to
simultaneously pressurize the gas
sample tank. This is accomplished as
follows: Obtain both the sample tank
and condensate trap from the test run to
be analyzed. Set up the condensn'e
recovery and conditioning apparatus so
that the carrier flow bypasses the
condensate trap hook-up terminals.
bypasses the oxidation catalyst, and is
vented to the atmosphere. Next, attach
the condensate trap to the apparatus
and pack the trap in dry ice. Assure that
the valve isolating the collection vessel
connection from the atmospheric vent is
closed and then attach the gas sample
tank to the system as if it were the
intermediate collection vessel Record
the tank vacuum on the laboratory data
form. Assure that the NDIR analyzer
indicates a zero output level and then
switch the carrier flow through the
condensate trap; immediately switch the
carrier flow from vent to collect and
open the valve to the tank. The
condensate trap recovery and
conditioning apparatus should now be
set up as indicated in Figure 8. Monitor
the NDIR; when CO. is no longer being
passed through the system, switch the
carrier flow so that it once again
bypasses the condensate trap Continue
in this manner until the gas sample tank
is pressurized to a nominal gauge
pressure of 800 mm mercury. At this
time, isolate the tank, vent the carrier
flow, and record the sample tank
pressure (P,f), barometric pressure (PM)
and ambient temperature (TM). Remove
the gas sample tank from the system
V-MM-28
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Federal Register / Vol. 44. Np._195 / Friday, Octobers, 1979 / Proposed Rules
(OPEN)
FLOW
METERS
FLOW
^CONTROL
(OPEN)
CARRIER
6 pcrccntj
02/N2
VENT
VALVE
(OPEN)
REGULATING
ROTAMETER
QUICK rJ-i
CONNECT^
VALVE
(CLOSED)
TRAP
BYPASS
CATALYST
BYPASS
OXIDATION
CATALYST
HEATED
CHAMBER
1
1
1
1
*. FOR MONITORING PROGRESS
OF COMBUSTION ONLY
INTERMEDIATE
COLLECTION
VESSEL
VACUUM*
PUMP
(OFF)
V
H20
TRAP
MERCURY
MANOMETER
**FOR EVACUATING COLLECTION
VESSELS AND SAMPLE TANKS
Figure 8. Condensate recovery and conditioning apparatus, carbon dioxide purge.
V-MM-29
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Federal Register / Vol. 44. No. 195 / Friday. October 5,1979 / Proposed Rules
FLOW
X" METERS ~>\
~^y M
•*"^ FLOW
i -CONTROL
*fV VALVES N'T*
^h^ rV
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Federal Register / Vol. 44, No. 195 / Friday, October 5.1979 / Proposed Rules
4.3 3 Recovery of Condensate Trap
Sample. Oxidation and collection of the
sample in the condensate trap is now
ready to begin. From the step just
cor-pleted in paragraph 4.3.2 above, the
system should be set up so that the
carrier flow bypasses the condensate
irap. bypasses the oxidation catalyst
and is vented to the atmosphere. Attach
an evacuated intermediate collection
vessel to the system and then, switch
the carrier so that it flows through the
oxidation catalyst. Monitor the NDIR
and assure that the analyzer indicates a
zero output level. Switch the carrier
from vent to collect and open the
collection tank valve; remove the dry ice
from the trap and then switch the carrier
flow through the trap. The system
should now be set up to operate as
indicated in Figure 9.
Begin heating the condensate trap.
The trap should be heated to a
temperature at which the trap glows a
"dull red" (approximately 600° C) and
should be maintained at this
temperature for at least 5 minutes.
During oxidation of the condensate trap
sample, monitor the NDIR to determine
when all the sample has been removed
and oxidized (indicated by return to
baseline of NDIR analyzer output).
When complete recovery has been
indicated, remove the heat from the trap.
However, continue the carrier flow until
the intermediate collection vessel is
pressurized to a gauge pressure of 800
mm Hg (nominal). When the vessel is
pressurized, vent the carrier; measure
and record the final intermediate
collection vessel pressure (Pf) as well as
the barometric pressure (Pbv), ambient
temperature (Tv), and collection vessel
volume (Vv).
4.3.4 Analysis of Recovered
Condensate Sample. After the
preparation steps in paragraph 4.3.1
have been completed, the analyzer is
ready for conducting analyses. Assure
that the analyzer system is set so that
the carrier gas is routed through the
reduction catalyst to the FID (flow
through the separation column and
oxidation catalyst is optional). Attach
the intermediate collection vessel to the
tank inlet fitting of the TGNMO
analyzer. Purge the sample loop with
sample and then inject a preliminary
sample in order to determine the
appropriate FID attenuation. Inject
triplicate samples from the intermediate
collection vessel and record the values
(Gem)- When appropriate, check the
instrument calibration according to the
procedures of paragraph 4.4.1.4.
4.3.5 Analysis of Gas Sample Tank.
Assure that the analyzer is set up so that
the carrier flow is routed through the
separation column as well as both the
oxidation and reduction catalysts.
During analysis for the nonmethane
crganics the separation column is
operated as follows; First, operate the
column at —78° C (dry ice temperature)
lo elute the CO and CH4. After the CH.
peak, operate the column at 0° C to elute
the CO,. When the CO2 is completely
eluted, switch the carrier flow to
backflush the column and
simultaneously raise the column
temperature to 100° C in order to elute
all nonmethane organics. (Exact timings
for column operation are determined
from the calibration standard). Attach
the gas sample tank to the tank inlet
fitting of the TGNMO analyzer. Purge
the sample loop with sample and inject
a preliminary sample in order to
determine the appropriate FID
attenuation for monitoring the
backflushed non-methane organics.
Inject triplicate samples from the gas
sample tank and record the values
obtained for the nonmethane organics
(Ctm). When appropriate, check the
instrument calibration according to the
procedures of paragraph 4.4.1.4.
4.4 Calibration. Maintain a record of
performance of each item.
4.4.1 TGNMO Analyzer.
4.4.1.1 FID Calibration and linearity
check. Set up the TGNMO system so
that the carrier gas bypasses the
oxidation and reduction catalysts. Zero
and span the FID by injecting samples of
the high value (5-10 percent) calibration
gas (paragraph 3.3.1.3) and adjusting the
instrument output to the correct level.
Then check the instrument linearity by
injecting triplicate samples of the low
(5-10 ppm) and mid-range (500-1,000
ppm) calibration gases (paragraph
3.3.1.3). The system linearity is
acceptable if the results (average for
triplicate samples of each gas) are
within ±5 percent of the expected
values. This calibration and linearity
check shall be conducted prior to
analyzing each set of samples (i.e.,
samples from a given source test).
4.4.1.2 Oxidation Catalyst Efficiency
Check. This check should be performed
on a frequency established by the
amount of use of the analyzer and the
nature of the organic emissions to which
the catalyst is exposed. As a minimum,
perform this check prior to putting the
analyzer into service.
To confirm that the oxidation catalyst
is functioning in a correct manner, the
operator must turn off or bypass the
reduction catalyst while operating the
analyzer in an otherwise normal
fashion. Inject triplicate samples of the
methane standard gas (paragraph
3.3.1.1) into the system. If oxidation ia
adequate, the only gas that will then
reach the detector will be CO», to which
the FID has no response. If a response is
noted, the oxidation catalyst must be
replaced.
4.4.1.3 Reduction Catalyst Efficiency
Check. This check should be performed
on a frequency established by the
amount of use of the analyzer. As a
minimum, perform this check prior to
putting the analyzer into service. To
confirm proper operation of the
reduction catalyst, the operator must
bypass the oxidation catalyst while
operating the analyzer in an otherwise
normal manner. After setting the carrier
flow to bypass the oxidation catalyst
inject triplicate samples of the carbon
dioxide standard gas (Section 3.3.1.2).
The catalyst operation is acceptable if
the average response of the triplicate
CO2 sample injections is within ±2
percent of the expected value and no
one CO2 sample injection varies by more
than ±5 percent from the expected
value.
4.4.1.4 System Operation Check. This
system check should be conducted at a
frequency consistent with the amount of
use and the reliability of the particular
analyzer. As a minimum, this system
check shall be conducted before and
after each set of emission samples is
analyzed. If this system check is not
successfully completed at the conclusion
of the analyses, the results shall be
invalidated. Operate the TGNMO
analyzer in a normal fashion, passing
the carrier flow through the separation
column and both the oxidation and
reduction catalysts. Inject triplicate
samples of the two mixed gas standards
specified in Section 3.3.1.4. The system
operation is acceptable if, for each gas
mixture, the average non-methane
organic value for the triplicate samples
is within ±3 percent of the expected
value and no one sample analysis varies
by more than ±5 percent from the
average value for the triplicate samples.
4.4.2 Condensate Trap Recovery and
Conditioning Apparatus Oxidation
Catalyst Check. This catalyst check
should be conducted at a frequency
consistent with the amount of use of the
catalyst, as well as, the nature and
concentration level of the organics being
recovered by the system. As a minimum,
perform this check prior to and
immediately after conditioning each set
of emission sample traps.
Set up the condensate trap recovery
system so that the carrier flow bypasses
the trap inlet and is vented to the
atmosphere at the system outlet. Assure
that the tank collection valve is closed
and then attach an evacuated
intermediate collection vessel to the
system. Connect the methane standard
gas cylinder (Section 3.3.1.1] to the
V-MM-31
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Federal Register / Vol. 44, No. 195 / Friday, October 5. 1979 / Proposed Rules
system's condensate trap connector
(probe end, figure 4). Adjust the system
valving so that the standard gas cylinder
acts as the carrier gas; switch off the
carrier and use the cylinder of standard
gas to supply a gas flow rate equal to
the carrier flow normally used during
trap sample recovery. Now switch from
vent to collect in order to begin
collecting a sample. Continue collecting
a sample in the normal manner until the
intermediate vessel is filled to a nominal
pressure of 300 mm Hg. Remove the
intermediate vessel from the system and
vent the carrier flow to the atmosphere.
Switch the valving to return the system
to its normal carrier gas and normal
operating conditions. Set up the
TGNMO analyzer to operate with the
oxidation and reduction catalysts
bypassed. Inject a sample from the
intermediate collection vessel into the
analyzer. The operation of the
condensate trap recovery system
oxidation catalyst is acceptable if
oxidation of the standard methane gas
was 99.5 percent complete, as indicated
by the response of the TGNMO analyzer
FID.
4.4.3 Gas Sampling Tank. The
volume of the gas sampling tanks used
must be determined. Prior to putting
each tank in service, determine the tank
volume by weighting the tanks empty
and then filled with water; weight to the
nearest 0.5 gm and record the results.
4.4.4 Intermediate Collection Vessel.
The volume of the intermediate
collection vessels used to collect COa
during the analysis of the condensate
traps must be determined. Prior to
putting each vessel into service,
determine the volume by weighting the
vessel empty and then filled with water;
weigh to the nearest 0.5 gm and record
the results.
5. Calculations,
Note. All equations are written using
absolute pressure; absolute pressures are
determined by adding the measured
barometric pressure to the measured gauge
pressure.
5.1 Sample Volume. For each test
run, calculate the gas volume sampled:
0.386 V
5.2 Noncondensible Organics. For
each collection tank, determine the
concentration of nonmethane organics
(ppm C):
5.3 Condensible Organics. For each
condensate trap determine the
concentration of organics (ppm C):
0.386
—A r c
U *• v~
tf
r
x r
5.4 Total Gaseous Nonmethane
Organics (TGNMO). To determine the
TGNMO concentration for each test run,
use the following equation:
C=C, + CC
Where:
C=Total gaseous nonmethane organic
(TGNMO) concentration of the effluent,
ppm carbon equivalent.
Cc=Calcu!ated condensible organic
(condensate trap) concentration of the
effluent, ppm carbon equivalent.
COT = Measured concentration (TGNMO
analyzer) for the condensate trap
(intermediate collection vessel), ppm
methane.
C,=Calculated noncondensible organic
concentration of the effluent, ppm carbon
equivalent.
Ctm = Measured concentration (TGNMO
analyzer) for gas collection tank sample,
ppm methane.
Pf=Final pressure of intermediate collection
vessel, mm Hg , absolute.
Pu = Gas sample tank pressure prior to
sampling, mm Hg, absolute.
P,=Gas sample tank pressure after sampling,
but prior to pressurizing, mm Hg,
absolute.
Pt,=Final gas sample tank pressure after
pressurizing, mm Hg. absolute.
Tf=Fmal temperature of intermediate
Collection vessel, °K.
Ttl = Gas sample tank temperature prior to
sampling. °K.
T, = Cas sample tank temperature at
completion of sampling. °K.
Ttf=Gas sample tank temperature after
pressurizing. °K.
V = Gas collection tank volume, dscm.
V, = Intermediate collection tank volume.
dscm
V,=Gas volume sampled, dscm.
r=Total number of analyzer injections of
tank sample during analysis (where
j = injection number. 1 . . . r).
n = Total number of analyzer injections of
condensible intermediate collection
vessel during analysis (where
k = injection number, 1 . . . n).
Standard Conditions = Dry. 760 mm Hg.
293°K.
6. Bibliography.
6.1 Albert E. Salo, Samuel Witz, and
Robert D. MacPhee. "Determination of
Solvent Vapor Concentrations by Total
Combustion Analysis: A comparison of
Infrared with Flame lonization
Detectors." Presented at the 68th Annual
Meeting of the Air Pollution Control
Association, Boston, Ma. Paper No. 75-
33.2 June 15-20, 1975.
6.2 Albert E. Salo, William L. Oaks,
Robert D. MacPhee. "Measuring the
Organic Carbon Content of Source
Emissions for Air Pollution Control."
Presented at the 67th Annual Meeting of
the Air Pollution Control Association,
Denver, Colorado, Paper No. 74-190,
June 9-13,1974.
|FR Doc 78-30806 Fiied Ift-*-'9 8 45 ami
V-MM-32
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PHOSPHATE ROCK PLANTS
SUBMRTNN
-------
Federal Register / Vol. 44, No. 185 / Friday, September 21.1979 / Proposed Rules
140 CFR Part 60]
[FRL-1282-2]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants
AGENCY: Environmental Protection
Agency.
ACTION: Proposed Rule and
Announcement of Public Hearing.
SUMMARY: This action is being proposed
to limit emissions of particulate matter
from new, modified, and reconstructed
phosphate rock plants. Reference
Method 5 would be used for determining
compliance with these standards. The
standards implement the Clean Air Act
and result from the Administrator's
determination on August 21, 1979 [44 FR
49222) that phosphate rock plant
emissions contribute significantly to air
pollution. The intended effect is to
require new, modified, and
reconstructed phosphate rock plants to
use the best demonstrated system of
emission reduction, considering costs,
nonair quality health and environmental
impact and energy impacts.
DATES: Comments. Deadline for
comments is November 26, 1979.
Public hearing A public hearing will
be held on October 25, 1979.
Requests to speak at hearing. Persons
wishing to speak at the hearing must
contact Shirley Tabler, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5421 by October 18, 1979.
ADDRESSES: Comments. Comments
should be submitted to the Central
Docket Section (A-130), U.S.
Environmental Protection Agency. 401 M
Street, SW.. Washington, D.C. 20460.
Attention- Docket No. OAQPS-79-6.
Background Information. The
Background Information Document for
the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number: (919)
541-2777 Please refer to "Phosphate
Rock Plants. Background Information:
Proposed Standards of Performance"
(EPA-150/3-79-017).
Docket A docket (number OAQPS-
79-6) containing information used by
EPA in development of the proposed
standard is available for public
inspection between 8:00 a.m. and 4:00
p.m.. Monday through Friday, at EPA's
Central Docket Section, Room 2903B,
Waterside Mall, 401 M Street, SW.,
Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Don Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number: (919) 541-5271.
SUPPLEMENTARY INFORMATION!.
Summary of Proposed Standards
The proposed standards would apply
to new, modified, or reconstructed
phosphate rock dryers, calciners,
grinders, and ground rock handling and
storage facilities. The proposed
standards would limit emissions of
particulate matter to 0.02 kilogram [kg)
per megagram (Mg) of rock feed (0.04 lb"/
ton) from phosphate rock dryers, 0.055
kg/Mg (0.11 Ib/ton) from phosphate rock
calciners, and 0.006 kg/Mg (0.012 Ib/ton)
from phosphate rock grinders. An
opacity standard of zero percent opacity
is proposed for ground rock handling
system, dryers, calciners, and grinders.
The use of continuous opacity
monitoring systems would be required
for each affected facility. However,
when scrubbers are used for emission
control, continuous opacity monitoring
would not be required. Instead, the
pressure drop of the scrubber and the
liquid supply pressure would be
monitored as indicators of the scrubber
performance.
Summary of Environmental and
Economic Impacts
The proposed standards would impact
an estimated 110 teragrams (122 million
tons) of annual phosphate rock
production by 1995. About one half of
that would be due to construction of
new phosphate rock processing plants
and the remainder due to expansion of
industry capacity at existing plants.
The proposed standards would reduce
the particulate emissions from new
phosphate rock plants by about 99
percent below the levels that would
occur with no control and by about 85 to
98 percent below the levels allowed by
typical State standards, depending on
the type of facility. These emission
reductions would reduce nationwide
particulate emissions by about 19
gigagrams (21,000 tons) per year in 1985.
The maximum 24-hour average ambient
air concentration of particulate matter
due to emissions from a typical dryer
controlled to the level required by the
proposed standard would be about 88
fig/m3. Similarly, for a typical calciner,
imposition of the proposed emission
standard would result in a maximum
ambient level of 14 ^g/m3. and for a
typical grinder the ambient level could
reach a maximum of 1 fig/m3.
The annualized costs of operating
control equipment that would be needed
to attain the proposed standards were
estimated using model plants. Because
typical Florida phosphate rock plants
are larger than Western plants, the
control costs per ton of production are
lower.
The annualized cost of installing and
operating prevailing controls used to
meet existing State standards at typical
Florida phosphate rock plants is
estimated at $0.35 per metric ton. The
additional cost of employing control
technology to meet the proposed
standards at a new Florida plant is
estimated at $0.02/metric ton when
using baghouses and $0.07/metric ton
for scrubbers.
The annualized cost of using
prevailing controls to meet existing
State standards in a typical new
Western plant is $0.87/metric ton. The
additional cost of using control
technology to meet the proposed
standards at new Western plants is
estimated at $0 06/metric ton for
baghouse control and $0.21/metric ton
for scrubbers.
The additional costs of meeting the
proposed standards are relatively minor
when scrubbers or baghouses are used.
Electrostatic precipitators (ESP) could
also be used to meet the proposed
standards, but their use is not
anticipated because of their higher
annualized costs of operation. The
difference in cost between using the best
system of emission reduction to meet
the proposed standards level and using
prevailing controls to meet the State
Implementation Plan (SIP) levels would
have negligible impact on the
profitability of the plant and the future
growlh of the phosphate rock industry if
the proposed standards were
implemented. By the year 1985,
compliance with the proposed standards
would increase the industry cost of
production of phosphate rock by 01
percent (baghouse controls) to 0 2
percent (scrubber controls) above the
cost to meet existing State
Implementation Plan regulations A
more detailed discussion of the
economic analysis is discussed in the
Background Information Document.
Assuming baghouses are used to meet
the proposed standards, the total
industry capital cost for the first five
years after imposition of the proposed
standards would be about $8.5 million
greater than the capital costs incurred
meeting typical State standards. The
total industry annualized cost increase
to meet the proposed standards by the
fifth year would be about $0.8 million.
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The incremental energy required to
meet the proposed standards depends
on the control utilized. If baghouses are
employed, total industry energy
consumption in the fifth year after
imposition of the proposed standards
will increase by about 1.7 percent over
the levels projected to occur under State
regulations. Total industry consumption
in the fifth year will increase by 2.6
percent when scrubbers are employed,
and about 0.1 percent should
electrostatic precipitators be used. This
corresponds to a fifth year total increase
in industry energy consumpton of 39 x
10* kWh/vr when baghouses are used,
60 x 10* kWh/yr when high energy
scrubbers are used, and .009 x 106 kWh/
yr when electrostatic precipitators are
used.
Utilization of any of the alternative
control technologies (baghouse,
•crubber, or ESP) would result in
minimal adverse environmental impacts.
If high energy scrubbers or wet ESPs are
used to achieve the standards, this
would result in adverse impacts on solid
waste disposal, water pollution, and
energy consumption. However, the
incremental increase (over the
prevailing controls) of solid materials
and wastewaters produced during
control of emissions from phosphate
rock facilities is minor in comparison
with (1) the large volumes of process
wastewaters and solid wastes, and (2)
the total amounts of wastewaters and
solid waste already collected by
prevailing controls to meet existing
State standards. Utilization of baghouse
technology is marginally more
environmentally acceptable than other
control alternatives because no water
pollution and less solid waste is
produced.
Rationale for the Proposed Standards
Selection of Source for Control
Section 111 of the Act requires
establishment of standards of
performance for new, modified, or
reconstructed stationary sources that
cause or contribute significantly to air
pollution which may reasonably be
anticipated to endanger public health or
welfare. The EPA has determined that
sources which cause ambient suspended
particulate matter may cause adverse
health and welfare effects. Accordingly,
under the authority of Section 109 of the
Act, the Administrator has designated
particulate matter as a criteria pollutant
and has established national ambient
air quality standards for this pollutant.
Phosphate rock processing plants
have been shown to be a significant
source of particulate matter emissions.
The Priority List of sources for New
Source Performance Standards (40 CFR
60.16, 44 FR 49222, dated August 21,
1979) identified various sources of
emissions on a nationwide basis in
terms of the potential improvement in
emission reduction that could result
from their imposition. The sources on
this list are ranked based on decreasing
order of potential emission reduction.
Phosphate rock plants currently rank
16th of 59 sources on the list, and are,
therefore, of considerable importance
nationwide. In addition, a study
performed for EPA in 1975 by the
Argonne National Laboratory showed
phosphate rock dryers ranked 4th of the
nation's highest 18 particulate source
categories which require control
systems with moderate energy
consumption. The same study showed
phosphate rock grinders as ranking
fifteenth of the nation's 56 largest
particulate source categories. Finally,
results of dispersion modeling analysis
indicate that particulate emission
sources at phosphate rock plants
contribute significantly to the
deterioration of air quality.
Additional factors leading to the
selection of the phosphate rock industry
for the development of standards of
performance include the expected
growth rate of the industry and the
signficant reductions in particulate
matter emissions achievable with
application of available emissions
control technology. The United States is
the largest producer and consumer of
phosphate rock in the world. From 1959
to 1973, the production of phosphate
rock increased at an annual rate of
about six percent and production is
expected to increase at an annual rate
of about three percent per year through
the year 2000. By the year 1985 new and
modified phosphate rock plants would
cause an increase in nationwide
emissions of particulate matter of about
19 gigagrams per pear (21,000 tons/year)
above the level expected with
implementation of the proposed
standards. At most plants, the degree of
emissions control (imposed by State
Implementation plans) is considerably
less than that achievable with
application of the best technology for
emission control.
Selection of Affected Facility and
Pollutants
At phosphate rock installations, the
normal sequence of operation is: Mining,
beneficiation, conveying of wet rock to
and from storage, drying or calcining or
nodulizing, conveying and storage of dry
rock, grinding, and conveying and
storage of ground rock. Mining and
beneficiation are a minor source of
particulate emissions. Nodulizing. and
elemental phosphorous production are
not selected as affected facilities as
these sources are not expected to
exhibit growth potential. Dryers,
calciners, grinders and ground rock
handling systems account for nearly all
of the particulate matter emissions from
phosphate rock plants. Accordingly, the
proposed standards have been
developed for these sources.
Phosphate rock processing plants are
sources of emissions of participates.
fluorides, sulfur dioxide (SO,) and
certain radioactive substances.
Standards are being proposed only for
the control of particulate matter
emissions at this time. Based on
Tennessee Valley Authority research,
and emission measurements of fluorides
in calciner exhaust gases, it is unlikely
that significant quantities of fluorine
will be volatized at temperatures
experienced in dryers or calciners.
Emission of sulfur oxides generated by
oil-firing in dryers and calciners is
minimized by reaction with alkaline
materials naturally occurring in the
phosphate rock ore. Additional studies
of the radioactive materials in the
emissions are planned and EPA could, if
warranted, take additional action under
Section 112 of the Clean Air Act at a
future date.
Potential particulate emissions from
typical uncontrolled phosphate rock
facilities would amount to about 2.9 kg/
Mg (5.8 Ib/ton) of rock feed from the
dryer, 7.7 kg/Mg (15.4 Ib/ton) of rock
feed from the calciner. and about 0.8 kg/
Mg (1.6 Ib/ton) of rock feed from the
grinder. The typical State emission limit
for dryers is 0.13 kg/Mg (0.26 Ib/ton),
and the limit for calciners and grinders
is about 0.44 kg/Mg (0.88 Ib/ton).
Through application of alternative
control technology (e.g., the baghouse. or
high energy scrubber), the emissions
from these facilities could be further
reduced to 0.02 kg/Mg (0.04 Ib/ton) for
dryers, 0.055 kg/Mg (0.11 Ib/ton] for
calciners. and 0.006 kg/Mg (0 012 Ib/ton)
for grinders. Control limits for ground
rock handling and storage operations
are difficult to define owing to wide
variations jn system equipment and the
numerous fugitive emission sources
contained in these systems At most
installations, particulate emissions are
collected by an evacuation system and
vented through a baghouse. Greater
assurance that such control system are
installed, operated and maintained in
accordance with good practice can be
achieved by enforcing stringent opacity
standards.
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Selection of Best System of Emission
Reduction Considering Costs
Based on potential environmental,
economic and energy impacts, EPA has
concluded that either a fabric filitration
system or a high energy venturi scrubber
system is the best technological system
of continuous particulate emissions
reduction from each of the affected
facilities. The fabric filtration system,
high energy scrubber and high efficiency
electrostatic precipitator are judged to
be equally effective in terms of
emissions reduction capability. The
proposed standards are, therefore,
based on the use of any of the three
alternative control methods, although
cost considerations would favor the use
of the baghouse or high energy scrubber
over the ESP.
The economic and environmental
adverse impacts associated with the
alternative controls would favor the use
of the baghouse controls. The eonomic
and environmental advantages of the
baghouse are most apparent at grinding
and material handling/storage facilities,
where baghouses are already the
prevailing control employed. In contrast
to the baghouse, wet collection systems
produce water pollution and more solid
waste, although the incremental adverse
environmental impact produced by
these systems is small in comparison
with adverse effects presently produced
by phosphate rock plant processes, and
would not preclude the use of these
systems as environmentally acceptable
control alternatives.
Selection of Format for Standard
The format of the proposed standard
could be either a concentration standard
or a mass-per-unit-of-feed standard. A
control efficiency format could not be
selected because of limited scope in the
data base and practical considerations
involving the complexity of performance
test requirements. An equipment
standard was not considered because
Section 111 of the Act requires
application of emission limits when
feasible. The mass-emission-per-unit-
feed standard was selected over the
concentration standard format because
this format: (1) Is related directly to the
total quantity of emissions discharged to
the atmosphere, (2) is more equitable in
that the degree of emissions permitted is
related to the amount of product
processed, (3) is consistent with the
format of existing applicable State
standards, (4) does not discourage use of
more efficient process systems which
reduce exhaust gas volumes, and (5)
provides that the standard is not
circumvented by dilution or high volume
flows in the exhaust system. The mass
emissions format is appropriate for the
dryers, calciners, and grinder facilities.
However, because of wide variations in
the designs of ground rock handling
systems, and because a substantial
portion of the potential emissions are
fugitive and difficult to measure, a
visible emission standard is the only
format appropriate for ground rock
handling systems.
Emission Standards for Dryers
Source tests were conducted on
dryers at two phosphate rock plants
processing pebble rock. The pebble rock
is considered to present the most
adverse conditions for control of
emissions from dryers because it
receives relatively little washing and
enters the dryer containing a substantial
percentage of clay. Hence, any control
level limit for dryers processing pebble
rock should also be capable of meeting
the limit for all other dryers as well.
Particulate emissions from the dryer
controlled by a venturi scrubber
operating at about 4.4 kilopascals
pressure drop (18 inches of water)
averaged 0.020 and 0.019 kg/Mg (0.039
and 0.038 Ib/ton) for separate EPA tests.
Particulate emissions from the dryer
controlled by an ESP averaged 0.012 and
0.027 kg/Mg (0.024 and 0.054 Ib/ton) for
EPA and operator tests, respectively.
The test results show that the venturi
scrubber was capable of achieving
emission levels of 0.02 kg/Mg or better
from phosphate rock dryers emitting
high levels of particulates. The tests also
revealed that the venturi scrubber was
achieving a control efficiency of 99.2
percent. This is nearly equivalent to that
estimated to be attainable by the best
system of emission reduction (99.4
percent by a baghouse) when treating
the same emission loading and particle
size distribution. Based on analysis
using a programmable EPA scrubber
model (the model is described in EPA
report No. EPA-600/7-78-026), it was
estimated that increasing the scrubber
energy to a pressure drop of 6.2
kilopascals (25 inches of water) would
achieve the degree of control equivalent
to the best system of emission reduction,
reducing emission levels only marginally
(about 20 percent) below that measured.
It is concluded, therefore, that an
emission limit of 0.02 kg/Mg (0.04 lb/
ton) represents the emission level
attainable by the best system of
emission reduction.
Opacity data were gathered during
particulate tests at the two dryers.
Approximately fourteen hours of
measurements on four separate dates
were obtained as specified in EPA
Reference Method 9. At one facility
where emissions were controlled by a
medium-energy venturi scrubber, the
observations revealed zero percent
opacity throughout the test periods. At
the other facility, where emissions were
controlled by an ESP, opacity
observations ranged from zero percent
to 7.7 percent. The difference between
the opacity levels observed for the two
types of control systems primarily
reflected differences in diameters of
discharge stacks rather than significant
differences in control performance. ESPs
typically require larger stacks due to
higher volumes of flow required during
operation. Setting separate opacity
standards for the two control systems
was rejected because ESPs are not
expected to be used in meeting the
proposed standards. Thus the proposed
opacity standard is based on the
performance of the scrubber-controlled
facility and is set at zero percent
opacity. Control systems reflecting best
emissions control capability (the high
energy scrubber or baghouse) which
meets the proposed emissions limit
should experience no difficulty meeting
the proposed opacity standard. Should
any affected dryer facility be controlled
with an ESP and comply with the
particulate limit of 0.02 kg/Mg but not
the opacity limits, a separate opacity
limit may be established for the facility
under 40 CFR 60.11(e). The provisions of
40 CFR 60.11(e) allow owners or
operators of sources which exceed the
opacity standard while concurrently
achieving the performance emissions
limit to request establishment of a
specific opacity standard for that
facility.
Emission Standards for Calciners
Source tests were conducted on
calciners at two phosphate rock plants
processing western phosphate rock. The
western rock is considered to present
the most adverse conditions for
emissions control from calciners
because it receives less cleaning during
beneficiation than other ore types. In
addition one of the calciners selected for
test also processes a mix of both
beneficiated and unbeneficiated rock,
leading to a still more adverse control
problem. Presumably, any control
system demonstrating an emissions
level for these facilities should also be
capable of meeting this level for all
other calciners as well.
Particulate emissions from a calciner
controlled by a high-energy scrubber
operating in the range of 4.9 to 7.4
kilopascals pressure drop (twenty to
thirty inches of water) averaged 0.04 and
0.05 kg/Mg (0.08 and 0.10 Ib/ton) for two
different tests by the operator.
Particulate emissions from a calciner
controlled by a venturi scrubber
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operating at 3.0 kilopascals pressure
drop (1Z inches of water) averaged 0.07
kg/Mg (0.14 Ib/ton) for EPA tests and
0.12 and 0.068 kg/Mg (0.24 amd 0.136 lb/
ton) for different operator tests. The
emission level which would have been
attained had best technology been used
by this facility is estimated by adjusting
the test results to reflect the venturi
scrubber performance at 6.6 kilopascals
(27 inches water) pressure drop using
the EPA programmable scrubber model
Section 8.5 of the Background
Information Document for Phosphate
Rock Plants summarizes the expected
emission levels when the scrubber
energy is increased from medium to high
level. The adjusted level of control is
equivalent to that which would be
expected if baghouses were employed to
control calciner emissions, or 0.055 kg/
Mg (0.11 Ib/ton). Accordingly, this
control level is proposed as the emission
limit for calciners.
Opacity data were obtained during
the performance testing of the two
calciners. Zero percent opacity was
recorded at both facilities throughout
the 13.75 hours of observations, Based
on these test data, plus the fact that
better control technology must be
installed to comply with the
performance limits, it is proposed that
the opacity limit for calciner facilities be
set at zero percent opacity.
Emission Standards for Grinders
Source tests were conducted on four
separate grinders representing a wide
variation of exhaust air rates, grinder
designs, capacities, and product feeds
Emissions from each of the facilities are
controlled with baghouses. Emissions
averaged 0.0044, 0.002, 0.0005, and 0.0005
kg/Mg for EPA tests and 0.0022 kg/Mg
for operator tests. The emission tests
demonstrate that an emission level of
0.005 kg/Mg (0.01 Ib/ton) can be
achieved by fabric filters for a variety of
grinder applications. Installation of
baghouse controls for grinders is
motivated by the recovery value of the
product collected as much as by existing
emission standards. Hence, it is
expected that baghouses will remain the
predominant means of compliances with
emission standards for grinder facilities
Nearly 17 hours of opacity
observations were gathered during
particulate tests at two of the grinder
facilities. The average opacity level
recorded throughout the measurement
periods was zero percent. The use of
baghouses as control devices on these
two facilities represents demonstrated
best technology, therefore, the
Administrator believes that the opacity
standard for phosphate rock grinding
processes should be zero percent
opacity.
Emission Standards for Ground Rock
Handling and Storage Systems
Particulate emissions from handling
and storage of ground rock are very
difficult to characterize due to the fact
that these systems vary greatly from
plant to plant. A substantial portion of
the potential emissions from handling
and storage operations is fugitive
emissions. Normal industrial practice is
to control dust from the various sources
by utilizing enclosures and air
evacuation or pressure systems ducted
to baghouses. Baghouses provide
recovery of the rock dust which is
subsequently returned to the rock
inventory. Emissions from the
enclosures have zero percent opacity
when the process equipment is properly
maintained. Consequently, emissions
from the ground rock transfer system are
manifested and monitored at the overall
collection device (e.g.. the baghouse).
Because of wide variations in handling
and storage facilities, an opacity
standard is the only standard
appropriate for these facilities.
Source tests were conducted on three
pneumatic systems employed in the
transfer of ground phosphate rock. The
exhaust from the baghouses of each of
the transfer systems was witnessed to
determine the opacity of emissions
during normal transfer operations for
two hours at one system, and one hour
at the others. The opacity level of the
baghouse emissions was observed to be
zero percent throughout the test period.
Based on these results, an opacity limit
of zero percent opacity is proposed for
ground phosphate rock handling
systems
Testing, Monitoring, and Recordkeeping
Performance tests to determine
compliance with the proposed standards
would be required. Reference Method 5
(40 CFR Part 60, Appendix A) would be
used to measure the amount of
particulate emissions.
The proposed standards would
require continuous monitoring of the
opacity of emissions discharged from
phosphate rock dryers, calciners.
grinders and ground rock handling
systems. When a scrubber is used to
control the emissions, entrained water
droplets prevent the accurate
measurement of opacity; therefore, in
this case the proposed standard would
require monitoring the pressure drop
across the scrubber and the scrubbing
fluid supply pressure to the scrubber
rather than opacity. If other controls are
employed which would also preclude
the use of a continuous monitoring
system for measuring opacity as
specified by the standard, the operator
may request establishment of
alternative monitoring requirements
under the provisions of 40 CFR 60.13(i).
Excess emissions for affected
facilities using opacity monitoring
equipment are defined as all six-minute
periods in which the average opacity of
the stack plume exceeds zero percent.
Reporting of any excess emissions is
required under 40 CFR 60 on a quarterly
basis. For those facilities which use a
wet scrubber as the particulate control
device, the owner or operator is instead
required to submit reports each calendar
quarter for all measurements of scrubber
pressure drops and liquid supply
pressures less than 90 percent of the
average levels maintained during the
most recent performance test in which
compliance with the proposed standards
was demonstrated
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should cont;>ct EPA
at the address given in the ADDRESSES
Section of this preamble Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at the address of
the Docket (see ADDRESSES Section)
Docket
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are (1) to allow
interested persons to identify and locnte
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review
Miscellaneous
As prescribed by Section 111 of the
Act, this proposal of standards was
preceded by the Administrator's
determination that emissions from
phosphate rock plants contribute
significantly to air pollution which
causes or contributes to the
endangerment of public health or
welfare. In accordance with Section 117
of the Act, publication of this proposal
was preceded by consultation with
appropriate advisory committees,
independent experts, and Federal
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departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire 5
years from the date of promulgation
unless EPA takes affirmative action to
extend them. To accomplish this, a
provision automatically terminating the
reporting requirements at that time will
be included in the text of the final
regulations.
It should be noted that standards of
performance for new sources
established under Section 111 of the
Clean Air Act reflect the degree of
emission limitation achievable through
application uf the best technological
system of continuous emission reduction
which (taking into consideration the cost
of achieving such emission reduction,
any nonair quality health and
environmental impact and energy
requirements) the Administrator
determines has been adequately
demonstrated.
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with the standards of
performance, this technology might not
be selected as the basis of standards of
performance because of costs
associated with its use. Accordingly,
standards of performance should not be
viewed as the ultimate in achievable
emission control. In fact, the Act
requires (or has the potential for
requiring) the imposition of a more
stringent emission standard in several
situations. For example, applicable costs
do not play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas;
i.e., those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
Section 173 of the Act requires that new
or modified sources constructed in an
area which violates the National
Ambient Air Quality Standards
(NAAQS) must reduce emissions to the
level which reflects the "lowest
achievable emission rate" (LAER), as
defined in Section 171(3), for such
•ategory of source. The statute defines
LAER as that rate of emissions based on
the following, whichever is more
stringent:
(A) 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,
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source.
In no event can the emission rate
exceed any applicable new source
performance standard (Section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources (referred to
in Section 169(1)) employ "best
available control technology" (as
defined in Section 169(3)) for all
pollutants regulated under the Act. Best
available control technology (BACT)
must be determined on a case-by-case
basis, taking energy, environmental and
economic impacts and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to
Section 111 (or 112) of the Act.
In all events, State Implementation
Plans approved or promulgated under
Section 110 of the Act must provide for
the attainment and maintenance of
National Ambient Air Quality Standards
(NAAQS) designed to protect public
health and welfare. For this purpose,
SIPs must in some cases require greater
emission reductions than those required
by standards of performance for new
sources.
Finally, States are free under Section
116 of the Act to establish even more
stringent emission limits than those
established under Section 111 or those
necessary to attain or maintain the
NAAQS under Section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under Section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
EPA will review this regulation 4
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
Executive Order 12044, dated March
24,1978, whose objective is to improve
government regulations, requires
executive branch agencies to prepare
regulatory analyses for regulations that
may have major economic
consequences. The screening criteria
used by EPA to determine if a proposal
requires a regulatory analysis under
Executive Order 12044 are: (1)
Additional national annualized
compliance costs, including capital
charges, which total $100 million within
any calendar year by the attainment
date, if applicable, or within five years,
(2) a major increase in prices or
production costs.
The impacts associated with the
proposal of performance standards for
phosphate rock plants do not exceed the
EPA screening criteria. Therefore,
promulgation of the proposed standard
does not constitute a major action
requiring preparation of a regulatory
analysis under Executive Order 12044.
However, an economic impact
assessment of alternative control
technologies capable of meeting the
proposed NSPS has been prepared as
required under Section 317 of the Clean
Air Act and is included in the
Background Information Document for
Phosphate Rock Plants EPA considered
all the information in the economic
impact assessment in determining the
cost of the proposed standard.
Dated. September 14. 1979
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I of Title 40 of the Code of
Federal Regulations as follows:
1. By adding Subpart NN to the Table
of Sections as follows:
Subpart NN—Standards of Performance for
Phosphate Rock Plants
Sec.
60.400 Applicability and designation of
affected facility
60.401 Definitions.
60.402 Standard for participate matter.
60.403 Monitoring of emissions and
operations.
60.404 Test methods and procedures.
Authority. Sec. Ill and 301(a), Clean Air
Act, as amended, (42 U.S.C. 7411, 7601(a)),
and additional authority as noted below:
2. By adding subpart NN as follows:
Subpart NN—Standards of
Performance for Phosphate Rock
Plants
§ 60.400 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the following affected
facilities used in phosphate rock plants:
dryers, calciners, grinders, and ground
rock handling and storage facilities.
(b) Any facility under paragraph (a) of
this section which commences
construction, modification, or
reconstruction after September 21,1979,
is subject to the requirements of this
part.
V-NN-6
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Federal Register / Vol. 44, No. 185 / Friday, September 21. 1979 / Proposed Rules
{•0.401 Definition*.
(a) "Phosphate rock plant" means any
plant which produces or prepares
phosphate rock product by any or all of
the following processes: mining,
beneficiation, crushing, screening,
cleaning, drying, calcining, and grinding.
(b) "Phosphate rock feed" means the
ore which is fed to phosphate rock
facilities, including, but not limited to
the following minerals: Fluorapatite,
hydroxylapatite, chlorapatite and
carbonate-apatite.
(c) "Dryer" means a unit in which the
moisture content of phosphate rock is
reduced by contact with a heated gas
stream.
(d) "Calciner" means a unit in which
the moisture and organic matter of
phosphate rock is reduced within a
combustion chamber.
(e) "Grinder" means a unit which is
used to reduce the size of dry phosphate
rock.
(f) "Ground phosphate rock handling
and storage system" means a system
which is used for the conveyance and
storage of ground phosphate rock.
§ 60.402 Standard for participate matter.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any phosphate rock dryer
any gases which:
(i) Contain particulate matter in
excess of 0.020 kilogram per megagram
of phosphate rock feed (0.04 Ib/ton), or
(ii) Exhibit greater than 0 percent
opacity.
(2) From any phosphate rock calciner
any gases which:
(i) Contain particulate matter in
excess of 0.055 kilogram per megagram
of phosphate rock feed (0.11 Ib/ton), or
(ii) Exhibit greater than 0 percent
opacity.
(3) From any phosphate rock grinder
any gases which:
(i) Contain particulate matter in
excess of 0.006 kilogram per megagram
of phosphate rock feed (0.012 Ib/ton), or
(ii) Exhibit greater than 0 percent
opacity.
(4) From any phosphate rock handling
and storage system any gases which
exhtbit greater than 0 percent opacity.
{ 60.403 Monitoring of emissions and
operations
(a) Any owner or operator subject to
the provisions of this subpart shall
install, calibrate, maintain, and operate
a continuous monitoring system, except
as provided in paragraph (b) of this
section, to monitor and record the
opacity of the gases discharged into the
atmosphere from any phosphate rock
dryer, calciner, grinder or ground rock
handling system. The span of this
system shall be set at 40 percent
opacity.
(b) The owner or operator of any
affected phosphate rock facility using a
wet scrubbing emission control device
shall not be subject to the requirements
in paragraph,(a) of this section, but shall
install, calibrate, maintain, and operate
the following continuous monitoring
devices:
(1) A monitoring device for the
continuous measurement of the pressure
loss of the gas stream through the
scrubber. The monitoring device must be
certified by the manufacturer to be
accurate within ±250 pascals (±1 inch
water) gauge pressure.
(2) A monitoring device for the
continuous measurement of the
scrubbing liquid supply pressure to the
control device. The monitoring device
must be accurate within ±5 percent of
design scrubbing liquid supply pressure.
(c) For the purpose of conducting a
performance test under § 60.8, the owner
or operator of any phosphate rock plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and
operate a device for measuring the
phosphate rock feed to any affected
dryer, calciner, grinder, or ground rock
handling system. The measuring device
used must be accurate to within ±5
percent of the mass rate over its
operating range.
(d) For the purpose of reports required
under § 60,7(c), periods of excess
emissions that shall be reported are
defined as all six-minute periods during
which the average opacity of the plume
from any phosphate rock dryer, calciner,
grinder or ground rock handling system
subject to paragraph (a) of this section
exceeds 0 percent.
(e) Any owner or operator subject to
requirements under paragraph (b) of this
section shall report for each calendar
quarter all measurement results that are
less than 90 percent of the average
levels maintained during the most recent
performance test conducted under § 60.8
in which the affected facility
demonstrated compliance with the
standard under § 60.402.
(Sec. 114, Clean Air Act as amended (42
U.SC. 7414))
§ 60.404 Test methods and procedures
(a) Reference methods in Appendix A
of this part, except as provided under
§ 60.8(b) shall be used to determine
compliance with § 60.402 as follows:
(1) Method 5 for the measurement of
particulate matter and associated
moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and
volumetric flow rates,
(4) Method 3 for gas analysis, and
(5) Method 9 for the measurement of
the opacity of emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the minimum sampled volume of
0.84 dscm (30'dscf) except that shorter
sampling times and smaller sample
volumes, when necessitated by process
variables or other factors, may be
approved by the Administrator.
(c) For each run, average phosphate
rock feed rate in megagrams per hour
shall be determined using a device
meeting the requirements of § 60.403(c).
(d) For each run, emissions expressed
in kilograms per megagram of phosphate
rock feed shall be determined using the
following equatjon:
(C,C)J10 '
Where:
E = Emissions of particulates in kilograms per
megagrams of phosphate rock feed.
C, = Concentration of particulates in mg/
dscm as measured by Method 5.
Qs = Volumetric flow rate in dscm/hr as
determined by Method 2.
10~6= Conversion factor for milligrams to
kilograms.
M = Average phosphate rock feed rate in
megagrams per hour.
(Sec. 114, Clean Air Act, as amended. (42
U.S.C. 7414))
[FRDoc 79-293
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Federal Register / Vol. 44, No. 213 / Thursday, November 1, 1979 / Proposed Rules
40 CFR Part 60
[FRL 1349-8]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants; Extension of Comment Period
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for phosphate rock plants,
which were proposed on September 21,
1979 (44 FR 54970), is being extended
from November 26, 1979 to December 26,
1979.
DATES: Comments must be received on
or before December 26,1979.
ADDRESSES: Comments should be
submitted to Mr. David R. Patrick, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park. North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: On
September 21,1979 (44 FR 54970). the
Environmental Protection Agency
proposed standards of performance for
the control of particulate emissions from
phosphate rock plants. The notice of
proposal requested public comments on
the standards by November 26,1979.
Due to a delay in the shipping of the
Support Document, sufficient copies of
the document have not been available to
all interested parties in time to allow
their meaningful review and comment
by November 26,1979. EPA has received
a request from the industry to extend the
comment period by 30 days through
December 26,1979. An extension of this
length is justified since the shipping
delay has resulted in approximately a
three-week delay in processing requests
for the document.
Dated: October 26, 1979.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation.
[FR Doc. 79-J3855 Flltd 10-31-79, SH6 am]
Federal Register / Vol. 45. No. 12 / Thursday,
January 17, 1980 / Proposed Rules
40 CFR Part 60
[FRL 1391-6]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for phosphate rock plants,
which were proposed on September 21,
1979 (44 FR 54970), is being extended
from December 26,1979, to February 15,
1980. The extension is given because
there was about a six week delay in
distributing the document for review
DATES: Comments. Comments must be
received on or before February 15,1980.
ADDRESSES: Comments. Comments
should be submitted to Mr. David R.
Patrick Chief, Standards Development
Branch (MD-13), Emission Standards
and Engineering Division,
Environmental Protection Agency,
Research Trinagle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Stnadards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: On
September 21,1979 (44 FR 54970), the
Environmental Protectioin Agency
proposed standards of performance for
the control of particulate emissions from
phosphate rock plants. The notice of
proposal requested public comments on
the standards by December 26,1979.
Due to a delay in the shipping of the
Support Document, sufficient copies of
the document have not been available to
all interested parties in time to allow
their meaningful review and comment
by December 26,1979. EPA has received
a request from the industry to extend the
comment period by 45 days through
February 15, 1980. An extension of this
length is justified since the shipping
delay has resulted in approximately a
six week delay in processing requests
for the document.
Dated: January 8, 1980.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation
[FR Dm W>-lr>.ll Filed 1-16-80. 845 am|
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
AMMONIUM SULFATE
MANUFACTURE
SUBPART PP
-------
Federal Register / Vol. 45, No. 24 / Monday, February 4, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1353-3]
Standards of Performance for New
Stationary Sources; Ammonium
Sulfate Manufacture
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule and Notice of
Public Hearing.
SUMMARY: The proposed standards
would limit atmospheric emissions of
particulate matter from new, modified,
and reconstructed ammonium sulfate
manufacturing dryers. The standards
implement section 111 of the Clean Air
Act and are based on the
Administrator's determination that
ammonium sulfate manufacturing plants
contribute significantly to air pollution.
The intended effect is to require new,
modified, and reconstructed ammonium
sulfate manufacturing plants to use the
best demonstrated system of continuous
emission reduction, considering costs,
nonair quality health and environmental
impact, and energy impacts.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before April 5,1980.
Public Hearings. The public hearing
will be held on March 6,1980 (about 30
days after proposal) beginning at 9 a.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony at the
hearing should contact EPA by February
29,1980 (one week before hearing).
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to Central Docket Section (A-
130), U.S. Environmental Protection
Agency, 401 M Street, SW., Washington.
D.C. 20460, Attention: Docket No. A-79-
31.
Public Hearing. The public hearing
will be held at The Environmental
Research Center Auditorium Rm B-102,
Research Triangle Park, N.C. Persons
wishing to present oral testimony should
notify Shirley Tabler, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5421.
Background Information Document.
The background information document
for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number (919)
541-2777. Please refer to "Ammonium
Sulfate Manufacture—Background
Information for Proposed Emission
Standards," EPA-450/3-79-034.
Docket. A docket, number A-79-31,
containing information used by EPA in
development of the proposed standards,
is available for public inspection
between 8:00 a.m. and 4:00 p.m., Monday
through Friday, at EPA's Centra! Docket
Section (A-130), Room 2903B, Waterside
Mall, 401 M Street, SW., Washington,
D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards would limit
atmospheric particulate matter
emissions from new, modified, and
reconstructed ammonium sulfate dryers
at caprolactam by-product ammonium
sulfate plants, synthetic ammonium
sulfate plants, and coke oven by-product
ammonium sulfate plants.
Specifically, the proposed standards
would limit exhaust emissions from
ammonium sulfate dryers to 0.15
kilogram of particulate matter per
megagram of ammonium sulfate
production (0.30 Ib/ton). An opacity
emission standard is also proposed and
would limit emissions from the affected
facility to no more than 15 percent.
The proposed standards would
require continuous monitoring of the
pressure drop across the control system
for any affected facility to help ensure
proper operation and maintenance of
the system. Flow monitoring devices
necessary to determine the mass flow of
ammonium sulfate feed material to the
process would also be required.
Summary of Environmental, Energy, and
Economic Impacts
The proposed standards would reduce
projected 1985 particulate emissions
from new, modified, and reconstructed
ammonium sulfate dryers from about
670 megagrams (737 tons) per year, the
level of emissions under a typical State
Implementation Plan, to about 131
megagrams (144 tons) per year.
Compliance with the proposed
standards would amount to an 80
percent reduction of particulate
emissions under a State Implementation
Plan and would bring the overall
collection efficiency to near 99.9 percent
of the uncontrolled emissions. This
reduction in emission would result in
reduction of ambient air concentrations
of particulate matter in the vicinity of
new, modified, and reconstructed
ammonium sulfate plants. The proposed
standards are based on the use of
venturi scrubbing or fabric filtration to
control particulate matter. No water
discharge would be generated by the
control equipment required and all
captured particulate matter would be
reclaimed; therefore, the proposed
standards would have no adverse
impact on water quality or solid waste.
The proposed standards would not
significantly increase energy
consumption at ammonium sulfate
plants and would have a minimal impact
on national energy consumption. The
incremental energy needed to operate
control equipment to meet the standards
would range from 0.10 percent of the
total energy required to run a synthetic
or coke oven by-product ammonium
sulfate plant to 0.65 percent of the total
energy required to operate a
caprolactam by-product ammonium
sulfale plant.
Economic analysis indicates that the
impact of the proposed standards is
reasonable. Cumulative capital costs of
complying with the proposed standards
for the ammonium sulfate industry as a
whole would be about $1.0 million by
1985. Annualized cost to the industry in
the fifth year of the proposed standards
would be about $0.5 million. The
industry-wide price increase necessary
to offset the cost of compliance would
amount to less than 0.01 percent of the
wholesale price of ammonium sulfate.
Costs of emission control required by
the proposed standards are not expected
to prevent or hinder expansion or
continued production in the ammonium
sulfate industry.
Rationale
Selection of Source for Control
The Priority List (40 CFR 60.16, 44 FR
49222, August 21,1979) identifies various
sources of emissions on a nationwide
basis in terms of quantities of emission
from source categories, the mobility and
competitive nature of each source
category, and the extent to which each
pollutant endangers health and welfare.
The Priority List reflects the
Administrator's determination that
emissions from the listed source
categories contribute significantly to air
pollution and is intended to identify
major source categories for which
standards of performance are to be
promulgated. The ammonium sulfate
manufacturing industry is listed among
V-PP-2
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Federal Register / Vol. 45, No. 24 / Monday, February 4, 1980 / Proposed Rules
those source categories for which new
source performance standards (NSPS)
must be promulgated.
Ammonium sulfate has been an
important nitrogen fertilizer for many
years. Its early rise to importance as a
fertilizer resulted from its availability as
a by-product from such basic industries
as steel manufacturing and petroleum
refining. By-product generation has
continued to dominate the industry. By-
product ammonium sulfate from the
caprolactam segment of the synthetic
fibers industry is now the single largest
source, accounting for more than 50
percent of ammonium sulfate
production.
Production of ammonium sulfate as a
by-product also ensures that it will
continue as an important source of
nitrogen fertilizer in the United States.
This is illustrated by the fact that, in
response to an increase in demand,
caprolactam production is expected to
increase at compounded annual growth
rates of up to 7 percent through the year
1985; and for every megagram of
caprolactam produced, 2.5 to 4.5
megagrams of ammonium sulfate are
produced as a by-product.
Over 90 percent of ammonium sulfate
is generated from three types of plants:
Synthetic, caprolactam by-product, and
coke oven by-product. Investigation has
shown that the impact of regulation and
potential for emission reduction is
significant only within these three
Industry sectors. Synthetic ammomium
sulfate is produced by the direct
combination of ammonia and sufuric
acid. Caprolactam ammomium sulfate is
produced as a by-product from streams
generated during caprolactam
manufacture. Ammonia recovered from
coke oven off-gas is reacted with
sulfuric acid to produce coke oven
ammonium sulfate. These three major
segments of the ammonium sulfate
industry would be regulated by the
proposed new source performance
standards.
Selection of Pollutant
Study of the ammonium sulfate
industry has shown that ammonium
sulfate emissions are the principal
pollutant emitted to the atmosphere
from ammonium sulfate plants. At
operating temperatures, the ammonium
sulfate emissions occur as solid
paniculate matter, a "criteria" pollutant
for which national ambient air quality
standards have been promulgated.
Currently, a variety of wet collection
systems are employed to control
ammonium sulfate particulate emissions
to levels of compliance with State and
local air pollution regulations (typically
• reduction of 97 to 98 percent). Existing
State regulations range from a low of
0.71 kilogram of particulate per
megagram of ammonium sulfate
production to a high of 1.3 kilograms per
megagram. By the year 1985, new,
modified, and reconstructed ammonium
sulfate manufacturing dryers would
cause annual nationwide particulate
emissions to increase by about 670 Mg/
year (737 tons/year), with emissions
controlled to the level of a typical State
Implementation Plan (SIP) regulation.
(Estimate based on growth rate
demonstrated over past decade.)
Volatile organic compounds (VOC)
are also emitted from process dryers at
caprolactam by-product ammonium
sulfate plants. Test data indicate that
the caprolactam VOC mass emissions
are largely in the vapor phase and at
least two orders of magnitude lower
than ammonium sulfate particulate
emissions (110 kg/Mg for particulate
matter versus 0.78 kg/Mg for the VOC
emissions). In addition, wet collectors
currently in use as particulate control
systems have demonstrated an 88
percent removal efficiency of
uncontrolled caprolactam VOC
emissions. At this control level, new,
modified, and reconstructed
caprolactam ammonium sulfate plants
would add only about 76 megagrams per
year to nationwide VOC emissions by
1985. Therefore, the only pollutant
recommended for control by the
proposed standards is particulate
matter.
Selection of the Affected Facility
Ammonium sulfate crystals are
formed by continuously circulating a
mother liquor through a crystallizer.
When optimum crystal size is achieved,
precipitated crystals are separated from
the mother liquor (dewatered) usually
by centrifuges. Following dewatering,
the crystals are dried and screened to
product specifications.
Nearly all of the particnlate matter
emitted to the atmosphere from
ammonium sulfate manufacturing plants
is in the gaseous exhaust streams from
the process dryers. Other plant
processes, such as crystallization,
dewatering, screening, and materials
handling, are not significant emission
sources.
Ammonium sulfate dryers can be
either of the fluidized bed or the rotary
drum type. All fluidized bed units found
in the industry are heated continuously
with steam-heated air. The rotary units
are either direct-fired or steam heated.
Air flow rates for the ammonium sulfate
dryers at caprolactam plants range from
560 scm/Mg of product to 3,200 scm/Mg
of product. The lower value represents
direct-fired rotary drum units and the
higher value represents fluidized bed
drying units using steam-heated air. At
synthetic plants, air flow rates range
from 360 scm/Mg to 770 scm/Mg of
product. All drying units at synthetic
plants are of the rotary drum type.
One consequence of the wide range of
gas flow rates for the differing drying
systems is that particulate emission
rates, which are directly related to the
gas-to-product ratio, also vary
considerably for each drying unit
involved. (Gas-to-product ratio is
defined as the volume of dryer exhaust
gas per unit of production, e.g., dry
standard cubic meters per megagram of
ammonium sulfate produced.) Emission
tests using EPA Method 5 show an
uncontrolled ammonium sulfate
emission range of 0.44 kg/Mg to 76.7 kg/
Mg for rotary dryers. The one fluidized
bed dryer tested showed an
uncontrolled emission rate of 110 kg/Mg
of ammonium sulfate production.
Since the process dryer is the only
significant source of ammonium sulfate
particulate emissions, the ammonium
sulfate manufacturing industry can be
effectively controlled by specifying
emission limitations for the process
dryer. Therefore, the ammonium sulfate
dryer has been selected as the affected
facility for which particulate matter
regulations are proposed.
Selection of the Format of the
Recommended Standards
A number of regulatory formats are
available for standards limiting the
emission of particulate matter to the
atmosphere. Among the formats judged
as inappropriate for application in the
ammonium sulfate industry were a mass
per unit time performance standards
and such non-performance standards as
design, equipment, work practice, and
operational specifications. A standard
based on mass per unit time (e.g., kg/hr)
would require that a relationship be
constructed showing how the allowable
mass rate of emissions would vary with
both production and time. Such a
relationship could not be determined
without extensive source tests
performed at great expense.
Section lll(h) of the Clean Air Act
establishes a presumption against
design, equipment, work practice, and
operational standards. For example, a
standard based on a specific type of
drying equipment without add-on
controls or a standard limiting the dryer
air flow rate cannot be promulgated
unless a standard of performance is not
feasible. Performance standards for
control of ammonium sulfate dryer
particulate emissions have been
determined as practical and feasible;
therefore, design, equipment, work
V-PP-3
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Federal Register / Vol. 45, No. 24 / Monday, February 4, 1980 / Proposed Rules
practice, or operational standards were
not considered as regulatory options.
Two additional formats for the
proposed standards were considered:
mass standards, which limit emissions
per unit of feed to the ammonium sulfate
dryer or per unit of ammonium sulfate
processed by the dryer; and
concentration standards, which limit
emissions per unit volume of exhaust
gases discharged to the atmosphere.
Mass standards, expressed as
allowable emissions per unit of
production, are related directly to the
quantity of participate matter
discharged to the atmosphere. They
regulate emissions based on units of
input or output, thereby denying any
dilution advantage. Mass standards also
allow for variation in process techniques
such as decreasing the air flow rate
through the dryer. A primary
disadvantage of mass standards, as
compared to concentration standards, is
that their enforcement may be more time
consuming and therefore more costly.
The more numerous measurements and
calculations required also increase the
opportunities for error. Determining
mass emissions requires the
development of a material balance on
process data concerning the operation of
the plant, whether it be input flow rates
or production flow rates. The need for
such a material balance is particularly
relevant in the case of ammonium
sulfate plants. The determination of
throughput in the ammonium sulfate
dryer is seldom direct. None of the
plants investigated during development
of the proposed standards made direct
measurements of the dryer input or
output. Process weights were
determined indirectly through
monitoring of input stream feed rates.
In general, enforcement of
concentration standards requires a
minimum of data and information.
thereby decreasing-the costs of
enforcement and reducing the chances
of error. However, in the ammonium
sulfate industry, enforcement of
concentration standards may be
complicated by use of two-stage
fluidized bed dryers which add ambient
air streams at the discharge end of the
dryer. There is a potential for
circumventing^ concentration standards
by diluting the exhaust gases discharged
to the atmosphere with excess air, thus
lowering the concentration of pollutants
emitted but not the total mass emitted.
For combustion operations, this problem
can usually be overcome by correcting
the concentration measured in the gas
stream to a reference condition such as
a specified oxygen or carbon dioxide
percentage in the gas stream. However.
in the ammonium sulfate industry the
drying process frequently does not
involve direct combustion operations.
The drying air may be heated by an
outside source; therefore, it is not
always possible to "correct" the amount
of exhaust air to account for dilution.
Since design dryer gas flow rates vary
from process to process, concentration
standards applied to the ammonium
sulfate industry would penalize those
plant operators who chose to use a low
air flow rate for the ammonium sulfate
dryer. A decrease in the amount of dryer
air decreases the volume of gases
released but not necessarily the quantity
of particulate matter emitted. As a
result, the concentration of particulate
matter in the exhaust gas stream would
increase even though the total mass
emitted might remain nearly the same.
Because mass standards directly limit
the amount of particulate matter emitted
into the atmosphere per megagram of
ammonium sulfate production, the same
emission limit can be applied to all
dryer types and sizes, production rates,
and air flow rates. The flexibility of
mass standards to accommodate
process variations, such as the wide
gange of gas-to-product ratios found in.
the industry, allows all segments of the
ammonium sulfate industry to be
regulated with a single mass emission
standard. These advantages outweigh
the drawbacks associated with the "
determination of process weight.
Consequently, mass standards were
judged more suitable for regulation of
particulate emissions from ammonium
sulfate dryers and were selected as the
format for expressing the standards of
performance for ammonium sulfate
manufacturing plants.
The mass limit proposed will apply to
the exhaust gas streams as they
discharge from control equipment. The
proposed standards express allowable
particulate emissions in kilograms per
megagram (kg/Mg) of ammonium sulfate
production.
Selection of the Best System of Emission
Reduction and the Numerical Emission
Limits
Section 111 of the Clean Air Act
requires that standards of performance
reflect the degree of emission control
achievable through application of the
best demonstrated technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact, and energy requirements) has
been adequately demonstrated. The
proposed standards were developed
based on information derived from (1)
available technical literature on the
ammonium sulfate manufacturing
industry and applicable emission control
technology, (2) technical studies
performed for EPA by independent
research organizations, (3) information
obtained from the industry during visits
to ammonium sulfate plants and
meetings with various representatives of
the industry, (4) comments and
suggestions solicited from experts, and
(5) results of emission measurements
conducted by EPA.
Control Technology
Both venturi scrubbing and fabric
filtration represent the most efficient
add-on control techniques available to
abate particulate emissions. In
application to particulate collection from
ammonium sulfate dryers, both have the
potential to reduce ammonium sulfate
emissions from process dryers to less
than 0.15 kilogram per megagram of
ammonium sulfate production, although
energy requirements and costs may
differ considerably.
Venturi scrubbers are most suitable
for application to ammonium sulfate
dryers. In caprolactam by-product
ammonium sulfate plants, ammonium
sulfate feed streams are used as a
scrubbing liquor and in synthetic
ammonium sulfate plants the
condensate from the reactor/crystallizer
is used as the scrubbing liquor. This
allows the collected particulate to be
easily recycled to the system without
the addition of excess water. Because
medium-energy (25 to 33 centimeters
water guage (VV.G.) pressure drop)
venturi scrubbing with high liquid-to-gas
ratios achieves a high collection
efficiency and because venturi
scrubbing is compatible with and
complimentary to the processes
involved, it is considered the most
attractive add-on control system.
The fabric filter baghouse should also
be able to achieve the level of control
required by the standards based on
similar applications in other industries.
Normal operation of a baghouse for
ammonium sulfate particulate collection,
i.e., at temperatures above the dewpoint
of the exhaust gas, should be feasible.
However, in asseessing fabric filters as
an emission control option, the following
factors must be considered. For high gas
flow rates, capital and operating costs
as well as energy requirements are
higher for fabric filters than for medium
energy scrubbers of the same
construction material. For caprolactam
by-product plants using steam-heated
fluidized bed dryers, the ratio of gas
flow to product rate is at least an order
of magnitude higher than that of the
direct-fired rotary drum dryer operating
with fabric filters. As the size of a
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baghouse becomes larger, capital and
annual operating costs increase. For
example, maintaining the temperature of
the exhaust gas and baghouse surfaces
above the dewpoint may require more
energy than would ordinarily be
required to operate the dryer.
With caprolactam by-product
ammonium sulfate plants apparently
providing most of the anticipated growth
in the ammonium sulfate industry,
consideration should also be given to
caprolactam VOC mass emissions from
ammonium sulfate dryers. Available test
data indicate that most of the
caprolactam emissions associated with
the ammonium sulfate dryer are in the
vapor state. This suggests that the
caprolactam emissions would pass
through a fabric filter collection system.
On the other hand, a venturi scrubber
has demonstrated removal efficiency of
88 percent of the caprolactam from
ammonium sulfate dryers. Thus, use of
venturi scrubbers would, at a minimum,
maintain existing VOC control levels
now achieved by in-use wet collection
systems.
Emission Tests
Based on a survey of the ammonium
sulfate production industry, four plants
were selected for EPA Method 5
particulate emission testing. These four
ammonium sulfate manufacturing plants
were then tested by EPA in order to
evaluate control techniques currently
used for controlling particulate
emissions from ammonium sulfate
dryers,
Presently throughout the ammonium
sulfate industry, a variety of wet-
scrubbing systems are employed to
control ammonium sulfate particulate
emissions. The majority of these are
low-energy wet scrubbers, although
medium-energy venturi scrubbers are
being used with some ammonium sulfate
dryers. For wet scrubbing systems in
general, collection efficiency tends to
increase with increased energy input,
i.e., the higher the pressure drop, the
higher the removal efficiency of
particulates. This was borne out by
analysis of EPA test results. For
example, a synthetic ammonium sulfate
plant, with a rotary drum drying facility
controlled by a low-energy wet scrubber
operating at a pressure drop of 15
centimeters (6 inches) W.G., showed a
particulate collection efficiency of 97
percent. EPA test results from facilities
with increased energy inputs, e.g.,
venturi scrubbers operating at pressure
drops of 25.9 centimenters and 33
centimeters (10 and 13 inches) W.G.
showed typically higher control
efficiencies. In these latter cases, control
efficiencies of 99.8 and 99.9 percent by
weight were demonstrated with outlet
particulate emission rates of 0.158 kg/
Mg and 0.156 kg/Mg of ammonium
sulfate production, respectively, at a
synthetic ammonium sulfate plant using
a rotary dryer and a caprolactam by-
product ammonium sulfate plant using a
fluidized bed dryer.
Additional emission test data on wet
scrubbing control units have been
provided by ammonium sulfate plant
operators. At one facility, test results
using EPA Method 5 show an average
particulate emission rate of 0.135 kg/Mg
of ammonium sulfate production. The
facility, a caprolactam ammonium
sulfate plant with a fluidized bed dryer,
is controlled by a centrifugal scrubber
preceded by a series of cyclones. The
scrubber operates at 34 centimeters (13.4
inches) W.G. pressure drop.
Alternative emission control
techniques were also examined. The one
dry ammonium sulfate particulate
control system in use (a fabric filter unit)
was tested by EPA because it represents
a unique application of this control
method in the ammonium sulfate
industry. The facility, a synthetic
ammonium sulfate plant using a rotary
dryer, did achieve a low mass emission
rate, 0.007 kg/Mg (0.014 Ib/ton);
however, this emission rate is not
considered representative of a typical
ammonium sulfate facility. For example,
the baghouse in use was originally
designed for another application, and
the gas flow rate to this unit is
appreciably lower than normal direct-
fired gas flow. This constraint on gas
flow rate, by restricting the ratio of
dryer exhaust gas-to-product rate,
results in a significantly lower
uncontrolled inlet emission rate than
most other dryers used in the industry.
In fact, the fabric filter inlet
uncontrolled particulate emission rate
was 0.41 kg/Mg of production, while
those of facilities controlled by venturi
scrubbers were 110 kg/Mg and 77 kg/
Mg. This represents an uncontrolled
mass emission difference in the range of
two orders of magnitude. Thus,
comparison of the outlet mass emissions
for this facility with those of the other
facilities tested is, in this situation,
somewhat misleading.
Regulatory Options
Review of the performance of the
emission control techniques led to the
identification of two regulatory options.
The two options are based on emission
control techniques representative of two
distinct levels of control. Each option
specifies numerical emission limits for
ammonium sulfate dryers applicable to
the three major sectors of the
ammonium sulfate industry. Option I is
equivalent to no additional regulatory
action. For this option, particulate
emission levels would be set by existing
SIP regulations, typically in the range of
0.71 kg/Mg to 1.3 kg/Mg of ammonium
sulfate production. This option is
characterized by the use of a low energy
wet scrubber to meet the required
emission limit, a reduction of 97 to 98
percent. Option II, based on the use of a
venturi scrubber or fabric filter, would
set an emission limit of 0.15 kilogram of
particulate per megagram of ammonium
sulfate production. As applied to the
ammonium sulfate industry, both the
venturi scrubber and the fabric filter
control systems are capable of greater
than 99.9 percent control efficiency.
Option II therefore represents the most
stringent control level that can be met
by all segments of the ammonium
sulfate industry.
Using model plants for the new,
modified, and reconstructed ammonium
sulfate facilities, the environmental
impacts, energy impacts, and economic
impacts of each regulatory option were
analyzed and compared. Each
ammonium sulfate manufacturing sector
is unique from a technical standpoint.
Dryer types and sizes, gas-to-product
flow rates, and uncontrolled particulate
emission rates vary from one sector to
another and often within each sector.
For these reasons it was apparent that
no single model plant could adequately
characterize the ammonium sulfate
industry. Accordingly, several model
dryers were specified in terms of the
following parameters: Production rate.
dryer types, exhaust gas flow rates,
emission rates, stack height, stack
diameter, and exit gas temperatures.
The evaluation of these parameters may
be found in Chapters 6, 7, and 8 of the
document, "Ammonium Sulfate
Manufacture—Background Information
for Proposed Emission Standards."
Under Option I, annual nationwide
particulate emissions from new,
modified, and reconstructed ammonium
sulfate manufacturing plants would
increase by about 670 Mg/year (737
tons/year) between 1980 and 1985.
Under Option II, nationwide particulate
emissions would increase by 131 Mg/
year (144 tons/year) during the same
period. This represents a reduction of
about 80 percent in the particulate
emissions emitted under Option I, a
typical SIP regulation.
Dispersion analysis under "worst
case" atmospheric and meteorological
conditions shows that the maximum 24-
hour concentration of particulates in the
vicinity of a new, modified, and
reconstructed ammonium sulfate plan!
would be reduced by a factor of 80
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percent (from 224 to 47.4 micrograms per
cubic meter) by controlling to Option II
rather than the SIP emission limit. The
maximum annual average is reduced
from 29.1 to 6.15 micrograms per cubic
meter under Option II.
Effluent guidelines set forth in 40 CFR
418.60 limit water pollution from
synthetic and coke oven ammonium
sulfate plants. In the caprolactam by-
product ammonium sulfate plant, water
is removed in the crystallizer,
condensed and recycled to the principal
plant for plant use. The addition of a
scrubber for emission control would nol
create a water pollution problem since
all scrubbing liquor would be recycled
to the process. The use of a baghouse
would not create a water pollution
problem since it is a dry collection
system. Consequently, the water
pollution impact of Option II would be
zero.
The ammonium sulfate plants
generate no solid waste as part of the
process since all collected ammonium
sulfate is recycled to the process.
Furthermore, no significant increase in
noise level is anticipated under Option
II.
For typical plants in the ammonium
sulfate manufacturing industry, an
increase in energy consumption would
result from compliance with Option II.
The energy required, in excess of thai
required by a typical SIP regulation, to
control caprolactam by-product
ammonium sulfate plants to the level of
Option II would be 8.8 gigawatt hours of
electricity per year in 1985 using venturi
scrubbers. The overall energy increase
would amount to less than 0.65 percent
of the total energy required to operate a
typical caprolactam by-product
ammonium sulfate plant. For synthetic
and for coke oven by-product
ammonium sulfate plants, the 1985
incremental energy increase would be
0.61 and 0.14 gigawatt hours per year,
respectively, or less than a 0.1 percent
increase. The total industry-wide energy
increment would be 9.5 gigawatt hours
per year in 1985. This figure indicates
that Option II would not significantly
increase energy consumption at
ammonium sulfate plants and would
have minimal impact on national energy
consumption.
Economic analysis also indicates that
the impact of Option II is minimal. The
capital cost of the installed emission
control equipment necessary to meet
Option II, on all new, modified, and
reconstructed ammonium sulfate
facilities coming on line nationwide
during the period 1980 to 1985, would be
about $958,000. The total annualized
cost of operating this equipment during
the same period would be about
$480,200. These costs are considered
reasonable, and are not expected to
prevent or hinder expansion or
continued production in the ammonium
sulfate manufacturing industry. The
incremental cost necessary to offset the
cost of meeting Option II would be
about 0.01 percent of the wholesale
price of ammonium sulfate.
Consideration of the beneficial impact
on national particulate emissions; the
lack of water pollution impact or solid
waste impact; the minimal energy
impact; the reasonable cost impact; and
the general availability of demonstrated
emission control technology leads to the
selection of Option II as the basis for the
proposed standards of performance for
ammonium sulfate dryers.
Selection of Opacity Emission Limits
The best indirect method of ensuring
proper operation and maintenance of
emission control equipment is the
specification of exhaust gasopacity
limits. Determining an acceptable
exhaust gas opacity limit is possible
because opacity levels were evaluated
for ammonium sulfate dryers during EPA
tests; therefore, the data base for the
particulate standards includes
information on opacity. Ammonium
sulfate dryers were observed to have no
opacity readings greater than 15 percent
opacity, and a total of 90 minutes of
opacity of less than or equal to 15
percent but greater than 10 percent
during observation periods of 180,120.
438, and 408 minutes (1146 minutes
total). Therefore, a standard of 15
percent opacity is proposed for all
affected facilities to ensure proper
operation and maintenance of control
systems on a day-to-day basis.
Selection of Performance Test Methods
The use of EPA Reference Method 5—
"Determination of Particulate Emissions
from Stationary Sources" would be
required to determine compliance with
the mass standards for particulate
matter emissions. Results of
performance tests using Method 5
conducted by EPA on existing
ammonium sulfate dryers comprise a
major portion of the data base used in
the development of the proposed
standards. EPA Reference Method 5 has
been shown to provide a representative
measurement of particulate matter
emissions. Therefore, it is included for
the purpose of determining compliance
with the proposed standards.
Method 5 calculations require imput
data obtained from three other EPA test
methods conducted previous to the
performance of Method 5. Method 1,
"Sample and Velocity Traverse for
Stationary Sources," must be used to
obtain representative measurements of
pollutant emissions. The average gas
velocity in the exhaust stack is
measured by conducting Method 2,
"Determination of Stack Gas Velocity
and Volumetric Flow Rate (Type S Pitot
Tube)." The analysis of gas composition
is measured by conducting Method 3,
"Gas Analysis for Carbon Dioxide,
Oxygen, Excess Air, and Dry Molecular
Weight," These three tests provide data
necessary in Method 5 for determining
concentration of particulate matter in
the dryer exhaust. All opacity
observations would be made in
accordance with the procedures
established in EPA Method 9 for stack
emissions.
Since the proposed standards are
expressed as mass of emissions per unit
mass of ammonium sulfate production, it
will be necessary to quantify production
rate in addition to measuring particulate
emissions. Ammonium sulfate
production in megagrams shall be
determined by direct measurement using
product weigh scales or computed from
a material balance. A material balance
computation based on the chemical
reactions used in the formation of
ammonium sulfate is an acceptable
method of determining production rate
since the formation reactions used in all
industrial sectors are quantitative and
irreversible.
If a material balance is used, the
ammonium sulfate production rate for
synthetic and coke oven by-product
ammonium sulfate plants shall be
calculated from the metered sulfuric
acid feed rate to the reactor/crystallizer.
For caprolactam by-product ammonium
sulfate plants, production rate shall be
determined from the oximation
ammonium sulfate solution flow rate
and the oleum flow to the caprolactam
rearrangement reaction.
Selection of Monitoring Requirements
To further ensure that installed
emission control systems continuously
comply with standards of performance
through proper operation and
maintenance, monitoring requirements
are generally included in standards of
performance. In the case of ammonium
sulfate dryers, the most straightforward
means of ensuring proper operation and
maintenance is to require monitoring of
actual particulate emissions released to
the atmosphere. Currently, however,
there are no continuous particulate
monitors in operation for ammonium
sulfate dryers; and resolution of the
sampling problems and development of
performance specifications for
continuous particulate monitors would
entail a major development program. For
these reasons, continuous monitoring of
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participate emissions from ammonium
sulfate dryers is not required by the
proposed standards.
The best indirect method of
monitoring proper operation and
maintenance of emission control
equipment is to continuously monitor
the opacity of the exhaust gas. The
proposed opacity limit for ammonium
sulfate dryers is 15 percent. However, in
the case of ammonium sulfate dryers,
the character of the exhaust gas when
wet scrubbers are used for emission
reduction precludes the use of
continuous in-stack opacity monitors.
Where condensed moisture is present in
the exhaust gas stream, in-stack
continuous monitoring of opacity is not
feasible; water droplets and steam can
interfere with operation of the
monitoring instrument. Since most
affected facilities are likely to use wet
scrubbers, continuous monitoring of
opacity is not required by the proposed
standards.
An alternative to participate or
opacity monitors is the use of a pressure
drop monitor as a means of ensuring
proper operation and maintenance of
emission control equipment For venturt
scrubbers, participate removal
efficiency is related directly to pressure
drop across the venturi; the higher the
pressure drop, the higher the removal
efficiency. For fabric filters, pressure
drop is used as an indicator of excessive
filter resistance or damaged filter media.
Therefore, in order to provide a
continuous indicator of emission control
equipment operation and maintenance,
the proposed standards would require
that the owner or operator of any
ammonium sulfate manufacturing plant
subject to the standards install,
calibrate, maintain, and operate a
monitoring device which continuously
measures and permanently records the
total pressure drop across the process,
emission control system. The monitoring
device shall have an accuracy of ±5
percent over its operating range.
The proposed standards would also
require the owner or operator of any
ammonium sulfate manufacturing plant
subject to the standards to install,
calibrate, maintain, and operate flow
monitoring devices necessary to
determine the mass flow of ammonium
Sulfate feed material to the process. The
flow monitoring device shall have an
accuracy of ±5 percent over its
operating range. The ammonium sulfate
feed streams are: for synthetic and coke
oven by-product ammonium sulfate
plants, the sulfuric acid feed stream to
the reactor/crystallizer; for caprolactam
by-product ammonium sulfate plants.
the oximation ammonium sulfate stream
to the ammonium sulfate plant and the
oleum stream to the caprolactam
rearrangement reaction.
Records of pressure drop and
calibration measurements would have to
be retained for at least 2 years following
the date of the measurements by owners
and operators subject to this subpart.
This requirement is included under
§ 60.7(d) of the general provisions of 40
CFR Part 60.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with section 307(d}(5) of the
Clean Air Act Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Docket address
given in the ADDRESSES section of this
preamble.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section in Washington, D.C. (See
ADDRESSES section of this preamble.)
Docket
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are: (1) To allow
interested persons to identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review. The
docket requirement is discussed in
section 307(d) of the Clean Air Act.
Miscellaneous
As prescribed by section 111 of the
Act, this proposal of standards has been
preceded by the Administrator's
determination that emissions from
ammonium sulfate manufacturing plants
contribute significantly to air pollution
which may reasonably be anticipated to
endanger public health or welfare (40
CFR 60.16. 44 FR 49222, August 21.1979).
In accordance with section 117 of the
Act, publication of these proposed
standards was preceded by consultation
with appropriate advisory committees,
independent experts, and Federal
departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation, including economic and
technological issues.
It should be noted that standards of
performance for new stationary sources
established under section 111 of the
Clean Air Act reflect:
* * * application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, (section lll(a)(l))
Although there may be emission
control technology available that is
capable of reducing emissions below
those levels required to comply with
standards of performance, this
technology might not be selected as the
basis of standards of performance
because of costs associated with its use.
Accordingly, these standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas;
i.e., those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the national
ambient air quality standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3), for such category of
source. The statute defines LAER as that
rate of emissions based on the
following, whichever is more stringent:
(A) 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
(B) The most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate
exceed any applicable new source
performance standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part Q. These provisions
require that certain sources (referred to
in section 169(1)) employ "best available
control technology" (as defined in
section 169(3)) for all pollutants
regulated-ander the Act "Best available
control technology" (BACT) must be
determined on a case-by-case basis.
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taking energy, environmental, and
economic impacts and other cost into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112} of the Act.
In all events, State Implementation
Plans (SIPs) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of the national ambient air
quality standards (NAAQS) designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for any
new source standard of performance
promulgated under section ll(b) of the
Act. An economic impact assessment
was prepared for the proposed
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the proposed standards
to ensure that the proposed standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the background information
document.
Dated: January 28,1980.
Douglas M. Costle,
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
It is proposed that 40 CFR Part 60 be
amended by adding a new Subpart P as
follows:
Subpart PP—Standards of Performance for
Ammonium Sulfate Manufacture
Sec.
60.420 Applicability and designation of
affected facilty.
60.421 Definitions.
60.422 Standards for particulate matter.
60.423 Monitoring of operations.
60.424 Test methods and procedures.
Authority: Sec. Ill, 301(a), Clean Air Act
as amended, (42 U.S.C. 7411, 7601(a)), and
additional authority as noted below.
Subpart PP—Standards of
Performance for Ammonium Sulfate
Manufacture
§ 60.420 Applicability and designation of
affected facility.
The affected facility to which the
provisions of this subpart apply is each
ammonium sulfate dryer with an
ammonium sulfate manufacturing plant
in the caprolactam by-product,
synthetic, and coke oven by-product
sectors of the ammonium sulfate
industry.
§ 60.421 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Ammonium sulfate manufacturing
plant" means any plant which produces
ammonium sulfate.
(b) "Ammonium sulfate dryer" means
a unit or vessel in which ammonium
sulfate is charged for the purpose of
reducing the moisture content of the
product using a heating gas stream. The
unit includes foundations,
superstructure, material charger
systems, exhaust systems, and integral
control systems and instrumentation.
(c) "Caprolactam by-product
ammonium sulfate manufacturing plant"
means any plant which produces
ammonium sulfate as a by-product from
process streams generated during
caprolactam manufacture.
(d) "Synthetic ammonium sulfate
manufacturing plant" means any plant
which produces ammonium sulfate by
direct combination of ammonia and
sulfuric acid.
(e) "Coke oven by-product ammonium
sulfate manufacturing plant" means any
plant which produces ammonium sulfate
by reacting sulfuric acid with ammonia
recovered as a by-product from the
manufacture of coke.
(f) "Ammonium sulfate feed material
streams" means the sulfuric acid feed
stream to the reactor/crystallizer for
synthetic and coke oven by-product
ammonium sulfate manufacturing
plants; and means the oximation
ammonium sulfate stream to the
ammonium sulfate manufacturing plant
and the oleum stream to the
caprolactam rearrangement reaction for
caprolactam by-product ammonium
sulfate manufacturing plants.
§ 60.422 Standards for particulate matter.
On or after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator of an ammonium
sulfate dryer subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere, from any
ammonium sulfate dryer, particulate
matter at emission rates exceeding 0.15
kilogram of particulate per megagram of
ammonium sulfate produced [0.30 pound
of particulate per ton of ammonium
sulfate produced) and exhaust gases
with opacity of greater than 15 percent
opacity.
§ 60.423 Monitoring of operations.
(a) The owner or operator of any
ammonium sulfate manufacturing plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and
operate flow monitoring devices which
can be used to determine the mass flow
of ammonium sulfate feed material
streams to the process. The flow
monitoring device shall have an
accuracy of ± 5 percent over its range.
(b) The owner or operator of any
ammonium sulfate manufacturing plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and.
operate a monitoring device which
continuously measures and permanently
records the total pressure drop across
the emission control system. The
monitoring device shall have an
accuracy of ± 5 percent over its
operating range.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
§ 60.424 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided in
§ 60.8(b), shall be used to determine
compliance with § 60.422 as follows:
(1) Method 5 for the concentration of
particulate matter.
(2) Method 1 for sample and velocity
traverses.
(3) Method 2 for velocity and
volumetric flow rate.
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the volume shall be at least 1.50 dry
standard cubic meters (53 dry standard
cubic feet).
(c) for each run, the particulate
emission rate, E, shall be computed as
follows:
E = Q,d x C, -=-1000
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(1) E is the participate emision rate
(kg/hr),
(2) Q HI is the average volumetric flow
rate (dscm/hr) as determined by Method
2; and
(3) C, is the average concentration (g/
dscm) of participate matter as
determined by Method 5,
(d) For each run, the rate of
ammonium sulfate production, P (Mg/
hr), shall be determined by direct
measurement using product weight
scales or computed from a material
balance. If production rate is determined
by material balance, the following
equations shall be used.
(1) For synthetic and coke oven by-
product ammonium sulfate plants, the
ammonium sulfate production rate shall
be determined using the following
equation:
P=AxBxCx 0.0808
where:
P = Ammonium sulfate production rate in
megagrams per hour.
A = Sulfuric acid flow rate to the reactor/
crystallizer in liters per minute averaged
over the time period taken to conduct the
run.
B = Acid density (a function of acid strength
and temperature) in grams per cubic
centimeter.
C = Percent acid strength in decimal form.
0.0808 ~ Physical constant for conversion of
time, volume, and mass units.
(2) For caprolactam by-product
ammonium sulfate plants the ammonium
sulfate production rate shall be
determined using the following equation:
P = [DxExFx (0.8612)] + [G X H X I
X (1.1620)]
where:
P = Production rate of caprolactam by-
product ammonium sulfate in megagrams
per hour.
D = Oximation ammonium sulfate process
stream flow rate in liters per minute
averaged over the time period taken to
conduct the run.
E = Density of the process stream solution in
grams per liter.
F = Percent ammonium sulfate in the process
solution in decimal form.
G = Oleum flow rate to the rearrangement
reaction in liters per minute averaged over
the time period taken to conduct the run
H = Density of oleum in grams per liter.
I = Equivalent sulfuric acid percent of the
oleum in decimal form.
0.8612 = Physical constant for conversion of
time and mass units.
1.1620 = Physical constant for conversion of
time and mass units.
(e) For each run, the dryer emission
rate shall be computed as follows:
R = E/P
where:
(1) R is the dryer emission rate (kg/
Mg):
(2) E is the particulate emission rate
(kg/hr) from (c) above; and
(3) P is the rate of ammonium sulfate
production (Mg/hr) from (d) above.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
|FR Doo 80-3593 Filed 2-1-Bft 8:45 am)
BILLING CODE S5SO-01-M
V-PP-9
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
CONTINUOUS MONITORING
PERFORMANCE SPECIFICATIONS
APPENDIX B
-------
Federal Register / Vol. 44. No. 197 / Wednesday. October 10.1979 / Proposed Rules
40 CFR Part 60
[FRL 1276-4]
Standards of Performance for New
Stationary Sources; Continuous
Monitoring Performance
Specifications
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Revisions.
SUMMARY: On October 6,1975 (40 FR
46250). the EPA promulgated revisions to
40 CFR Part 60, Standards of
Performance for New Stationary
Sources, to establish specific
requirements pertaining to continuous
emission monitoring. An appendix to the
regulation contained Performance
Specifications 1 through 3, which
detailed the continuous monitoring
instrument performance and equipment
specifications, installation requirements,
and test and data computation
procedures for evaluating the
acceptability of continuous monitoring
systems. Since the promulgation of these
performance specifications, the need for
a number of changes which would
clarify the specification test procedures,
equipment specifications, and
monitoring system installation
requirements has become apparent. The
purpose of the revisions is to
incorporate these changes into
Performance Specifications 1 through 3.
The proposed revisions would apply
to all monitoring systems currently
subject to performance specifications 1,
2, or 3. including source's subject to
Appendix P to 40 CFR Part 51.
DATES: Comments must be received on
or before December 10,1979.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to the Central Docket Section
(A-130). Attn: Docket No. OAQPS-79-4,
U.S. Environmental Protection Agency,
401 M Street, S.W., Washington, D.C.
20460.
Docket. Docket No. OAQPS-79-4.
containing material relevant to this
rulemaking. is located in the U.S.
Environmental Protection Agency,
Central Docket Section, Room 2903B, 401
M Street. S.W., Washington, D.C. The
docket may be inspected between 8
A.M. and 4 P.M. on weekdays, and a
reasonable fee may be charged for
copying,
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: Changes
common to all three of the performance
specifications are the clarification of the
procedures and equipment
specifications, especially the
requirement for intalling the continuous
monitoring sample interface and of the
calculation procedure for relative
accuracy. Specific changes to the
specifications are as follows:
Performance Specification
1. The optical design specification for
mean and peak spectral responses and
for the angle of view and projection
have been changed from "500 to 600 rim"
range to "515 to 585 nm" range and from
"5°" to "3°", respectively.
2. The following equipment
specifications have been added:
a. Optical alignment sight indicator
for readily checking alignment.
b. For instruments having automatic
compensation for dirt accumulation on
exposed optical surfaces, a
compensation indicator at the control
panel so that the permissible maximum
4 percent compensation can be
determined.
c. Easy access to exposed optical
surfaces for cleaning and maintenance.
d. A system for checking zero and
upscale calibration (previously required
in paragraph 60.13).
e. For systems with slotted tubes, a
slotted portion greater than 90 percent of
effluent pathlength (shorter slots are
permitted if shown to be equivalent).
f. An equipment specification for the
monitoring system data recorder
resolution of <5 percent of full scale.
3. A procedure for determining the
acceptability of the optical alignment
sight has been specified; the optical
alignment sight must be capable of
indicating that the instrument is
misaligned when an error of ±2 percent
opacity is caused by misalignment of the
instrument at a pathlength of 8 meters.
4. Procedures for calibrating the
attenuators used during instrument
calibrations have been added; these
procedures require the use of a
laboratory spectrophotometer operating
in the 400-700 nm range with a detector
angle view of <10 degrees and an
accuracy of 1 percent.
5. The following changes have been
made to the procedures for the
operational test period:
a. The requirement for an analog strip
chart recorder during the performance
tests has been deleted; all data are
collected on the monitoring system data
recorder.
b. Adjustment of the zero and span at
24-hour intervals during the drift tests is
optional; adjustments are required only
when the accumulated drift exceeds the
24-hour drift specification.
c. The amount of automatic zero
compensation for dirt accumulation
must be determined during the 24-hour
zero check so that the actual zero drift
can be quantified. The automatic zero
compensation system must be operated
during the performance test.
d. The requirement for offsetting the
data recorder zero during the
operational test period has been deleted.
e. Off the stack "zero alignment" of
the instrument prior to installation is
permitted.
Performance Specification 2
1. "Continuous monitoring system"
has been redefined to include the
diluent monitor, if applicable. The
change requires that the relative
accuracy of the system be determined in
terms of the emission standard, e.g..
mass per unit calorific value for fossil-
fuel fired steam generators.
2. The applicability of the test
procedures excludes single-pass, in-situ
continuous monitoring systems. The
procedures for determining the
acceptability of these systems are
evaluated on a case-by-case basis.
3. For extractive systems with diluent
monitors, the pollutant and diluent
monitors are required to use the same
sample interface.
4. The procedure for determining the
acceptability of the calibration gases
has been revised, and the 20 percent
(with 95 percent confidence interval)
criterion has been changed to 5 percent
of mean value with no single value being
over 10 percent from the mean.
5. For low concentrations, a 10 percent
of the applicable standard limitation for
the relative accuracy has been added.
6. An equipment specification for the
system data recorder requiring that the
chart scale be readable to within <0.50
percent of full-scale has been added.
7. Instead of spanning the instrument
at 90 percent of full-scale, a mid-level
span is required.
8. The response time test procedure
has been revised and the difference
limitation between the up-scale and
down-scale time has been deleted.
9. The relative accuracy test
procedure has been revised to allow
different tests (e.g., pollutant, diluent.
moisture) during a 1-hour period to be
correlated.
10. A low-level drift may be
substituted for the zero drift test.
V-Appendix B-2
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10. 1979 / Proposed Rules
Performance Specification 3
1. The applicability of the test
procedures has been limited to those •
monitors that introduce calibration
gases directly into the analyzer and are
used as diluent monitors. Alternative
procedures for other types of monitors
are evaluated on a case-by-case basis.
2. Other changes were made to be
consistent with the revisions under
Performance Specification 2.
The proposed revised performance
specifications would apply to all sources
subject (o Performance Specifications 1,
2, or 3. These include sources subject to
standards of performance that have
already been promulgated and sources
subject to Appendix P to 40 CFR Part 51.
Since the purpose of these revisions is to
clarify the performance specifications
which were promulgated on October 6,
1975, not to establish more stringent
requirements, it is reasonable to
conclude that most continuous
monitoring instruments which met and
can continue to meet the October 6,
1975, specifications can also meet the
revised specifications.
Under Executive Order 12044, the
Environmental Protection Agency is
required to judge whether a regulation is
"significant" and therefore subject to the
procedural requirements of the Order or
whether it may follow other specialized
development procedures. EPA labels
these other regulations "specialized". I
have reviewed this regulation and
determined that it is a specialized
regulation not subject to the procedural
requirements of Executive Order 12044.
Dated: October 1,1979.
Douglas M. Costle,
Administrator.
It is proposed to revise Appendix B,
Part 60 of Chapter I, Title 40 of the Code
of Federal Regulations as follows:
Appendix B—Performance
Specifications
Performance Specification 1—
Specifications and Test Procedures For
Opacity Continuous Monitoring Systems
in Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains instrument design,
performance, and installation
requirements, and test and data
computation procedures for evaluating
the acceptability of continuous
monitoring systems for opacity. Certain
design requirements and test procedures
established in the Specification may not
be applicable to all instrument designs;
equivalent systems and test procedures
may be used with prior approval by the
Administrator.
1.2 Principle. The opacity of
particulate matter in stack emissions is
continuously monitored by a
measurement system based upon the
principle of transmissometry. Light
having specific spectral characteristics
is projected from a lamp through the
effluent in the stack or duct and the
intensity of the projected light is
measured by a sensor. The projected
light is attenuated due to absorption and
scatter by the particulale matter in the
effluent; the percentage of visible light
attenuated is defined as the opacity of
the emission. Transparent stack
emissions that do not attenuate light will
have a transmittance of 100 percent or
an opacity of zero percent. Opaque
stack emissions that attenuate all of the
visible light will have a transmittance of
zero percent or an opacity of 100
percent.
This specification establishes specific
design criteria for the transmissometer
system. Any opacity continuous
monitoring system that is expected to
meet this specification is first checked to
verify that the design specifications are
met. Then, the opacity continuous
monitoring system is calibrated,
installed, an operated for a specified
length of time. During this specified time
period, the system is evaluated to
determine conformance with the
established performance specifications.
2. Definitions
2.1 Continuous Monitoring System.
The total equipment required for the
determination of opacity. The system
consists of the following major
subsystems;
2.1.1 Sample Interface. That portion
of the system that protects the analyzer
from the effects of the stack effluent and
aids in keeping the optical surfaces
clean.
2.1.2 Analyzer. That portion of the
system that senses the pollutant and
generates a signal output that is a
function of the opacity.
2.1.3 Data Recorder. That portion of
the system that processes the analyzer
output and provides a permanent record
of the output signal in terms of opacity.
The data recorder may include
automatic data reduction capabilities.
2.2 Transmissometer. That portion of
the system that includes the sample
interface and the analyzer.
2.3 Transmittance. The fraction of
incident light that is transmitted through
an optical medium.
2.4 Opacity. The fraction of incident1
light that is attenuated by an optical
medium. Opacity (Op) and
transmittance (Tr) are related by:
Op = l-Tr.
2.5 Optical Density. A logarithmic
measure of the amount of incident light
attenuated. Optical density (D) is
related to the transmittance and opacity
as follows:
D=-log,.Tr=-log,oIl-Op).
2.6 Peak Spectral Response. The
wavelength of maximum sensitivity of
the transmissometer.
2.7 Mean Spectral Response. The
wavelength which bisects the total area
under the effective spectral response
curve of the transmissometer.
2.8 Angle of View. The angle that
contains all of the radiation detected by
the photodetector assembly of the
analyzer at a level greater than 2.5
percent of the peak detector response.
2.9 Angle of Projection. The angle
that contains all of the radiation
projected from the lamp assembly of the
analyzer at a level of greater than 2.5
percent of the peak illuminace.
2.10 Span Value. The opacity value
at which the continuous monitoring
system is set to produce the maximum
data display output as specified in the
applicable subpart.
2.11 Upscale Calibration Value. The
opacity value at which a calibration
check of the monitoring system is
performed by simulating an upscale
opacity condition as viewed by the
receiver.
2.12 Calibration Error. The
difference between the opacity values
indicated by the continuous monitoring
system and the known values "of a series
of calibration attenuators (filters or
screens).
2.13 Zero Drift. The difference in
continuous monitoring system output
readings before and after a stated period
of normal continuous operation during
which no unscheduled maintenance,
-repair, or adjustment took place and
when the opacity (simulated) at the time
of the measurements was zero.
2.14 Calibration Drift. The difference
in the continuous monitoring system
output readings before and after a stated
period of normal continuous operation
during which no unscheduled
maintenance, repair, or adjustment took
place and when the opacity (simulated)
at the time of the measurements was the
same known upscale calibration value.
2.15 Response Time. The amount of
time it takes the continuous monitoring
system to display on the data recorder
95 percent of a step change in opacity.
2.16 Conditioning Period. A period of
time (168 hours minimum) during which
the continuous monitoring system is
operated without unscheduled
maintenance, repair, or adjustment prior
to initiation of the operational test
period.
V-Appendix B-3
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Federal Register / Vol. 44, No. 197 / Wednesday. October 10. 1979 / Proposed Rules
2.17 Operational Test Period. A
period of time (168 hours) during which
the continuous monitoring system is
expected to operate within the
established performance specifications
without any unscheduled maintenance,
repair, or adjustment.
2.18 Pathlength. The depth of
effluent in the light beam between the
receiver and the transmitter of a single-
pass transmissometer, or the depth of
effluent between the transceiver and
reflector of a double-pass
transmissometer. Two pathlengths are
referenced by this Specification as
follows:
2.18.1 Monitor Pathlength. The
pathlength at the installed location of
the continuous monitoring system.
2.18.2 Emission Outlet Pathlength.
The pathlength at the location where
emissions are released to the
atmosphere.
3. Apparatus
3.1 Continuous Monitoring System.
Use any continuous monitoring system
for opacity which is expected to meet
the design specifications in Section 5
and the performance specifications in
Section 7. The data recorder may be an
analog strip chart recorder type or other
suitable device with an input signal
range compatible with the analyzer
output.
3.2 Calibration Attenuators. Use
optical filters with neutral spectral
characteristics or screens known to
produce specified optical densities to
visible light. The attenuators must be of
sufficient size to attenuate the entire
light beam of the transmissometer.
Select and calibrate a minimum of three
attenuators according to the procedures
in Sections 8.1.2. and 8.1.3.
3.3 Upscale Calibration Value
Attenuator. Use an optical filter with
neutral spectral characteristics, a
screen, or other device that produces an
opacity value (corrected for pathlength,
if necessary) that is greater than the sum
of the applicable opacity standard and
one-fourth of the difference between the
opacity standard and the instrument
span value, but less than the sum of the
opacity standard and one-half of the
difference between the opacity standard
and the instrument span value.
3.4 Calibration Spectrophotometer.
To calibrate the calibration attenuators
use a laboratory Spectrophotometer
meeting the following minimum design
specification:
Parameter
Specification
Wavelength range
Detector angle ol view
Accuracy
. 400-700 nrn
. S10°
.... S 0.5 pet. transmttance
4. Installation Specifications
Install the continuous monitoring
system where the opacity measurements
are representative of the total emissions
from the affected facility. Use a
measurement path that represents the
average opacity over the cross section.
Those requirements can be met as
follows:
4.1 Measurement Location. Select a
measurement location that is (a)
downstream from all particulate control
equipment; (b) where condensed water
vapor is not present; (c) accessible in
order to permit routine maintenance;"
and (d) free of interference from
ambient light (applicable only if
transmissometer is responsive to
ambient light).
4.2 Measurement Path. Select a
measurement path that passes through
the centroid of the cross section.
Additional requirements or
modifications must be met for certain
locations as follows:
4.2.1 If the location is in a straight
vertical section of stack or duct and is
less than 4 equivalent diameters
downstream or 1 equivalent diameter
upstream from a bend, use a path that is
in the plane defined by the bend.
4.2.2 If the location is in a vertical
section of stack or duct and is less than
4 diameters downstream and 1 diameter
upstream from a bend, use a path in the
plane defined by the bend upstream of
the transmissometer.
4.2.3 If the location is in a horizontal
section of duct and is at least 4
diameters downstream from a vertical
bend, use a path in the horizontal plane
that is one-third the distance up the
vertical axis from the bottom of the duct.
4.2.4 If the location is in a horizontal
section of duct and is less than 4
diameters downstream from a vertical
bend, use a path in the horizontal plane
that is two-thirds the distance up the
vertical axis from the bottom of the duct
for upward flow in the vertical section,
and one-third the distance up the
vertical axis from the bottom of the duct
for downward flow.
4.3 Alternate Locations and
Measurement Paths. Other locations and
measurement paths may be selected by
demonstrating to the Administrator that
the average opacity measured at the
alternate location or path is equivalent
(± 10 percent) to the opacity as
measured at a location meeting the
criteria of Sections 4.1 and 4.2. To
conduct this demonstration, measure the
opacities at the two locations or paths
for a minimum period of two hours. The
opacities of the two locations or paths
may be measured at different times, but
must be measured at the same process
operating conditions.
5. Design Specifications
Continuous monitoring systems for
opacity must comply with the following
design specifications:
5.1 Optics.
5.1.1 Spectral Response. The peak
and mean spectral responses will occur
between 515 nm and 585 nm. The
response at any wavelength below 400
nm or above 700 nm will be less than 10
percent of the peak spectral response.
5.1.2 Angle of View. The total angle
of view will be no greater than 4
degrees.
5.1.3 Angle of Projection. The total
angle of projection will be no greater
than 4 degrees.
5.2 Optical Alignment sight. Each
analyzer will provide some method for
visually determining that the instrument
is optically aligned. The system
provided will be capable of indicating
that the unit is misaligned when an error
of ± 2 percent opacity occurs due to
misalignment at a monitor pathlength of
eight (8) meters.
5.3 Simulated Zero and Upscale
Calibration System. Each analyzer will
include a system for simulating a zero,
opacity and an upscale opacity value for
the purpose of performing periodic
checks of the transmissometer
calibration while on an operating stack
or duct. This calibration system will
provide, as a minimum, a system check
of the analyzer internal optics and all
electronic circuitry including the lamp
and photodetector assembly.
5.4 Access to External Optics. Each
analyzer will provide a means of access
to the optical surfaces exposed to the
effluent stream in order to permit the
surfaces to be cleaned Without requiring
removal of the unit from the Source
mounting or without requiring optical
realignment of the unit.
5.5 Automatic Zero Compensation
Indicator. If the monitoring system has a
feature which provides automatic zero
compensation for dirt accumulation on
exposed optical surfaces, the system
will also provide some means of
indicating that a compensation of
4 ± 0.5 percent opacity has been
exceeded; this indicator shall be at a
location accessible to the operator (e.g.,
the data output terminal). During the
operational test period, the system must
provide some means for determining the
actual amount of zero compensation at
the specified 24-hour intervals so that
the actual 24-hour zero drift can be
determined (see Section 8.4.1).
5.6 Slotted Tube. For
transmissometers that use slotted tubes,
the length of the slotted portion(s) must
V-Appendix B-4
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10. 1979 / .Proposed Rules
be equal to or greater than 90 percent of
the monitor pathlength, and the slotted
tube must be of sufficient size and
orientation so as not to interfere with
the free flow of effluent through the
entire optical volume of the
transmissometer photodetector. The
manufacturer must also show that the
transmissometer uses appropriate
methods to minimize light reflections; as
a minimum, this demonstration shall
consist of laboratory operation of the
transmissometer both with and without
the slotted tube in position. Should the
operator desire to use a slotted tube
design with a slotted portion equal to
less than 90 percent of the monitor
pathlength, the operator must
demonstrate to the Administrator that
acceptable results can be obtained. As a
minimum demonstration, the effluent
opacity shall be measured using both
the slotted tube instrument and another
instrument meeting the requirement of
this specification but not of the slotted
tube design. The measurements must be
made at the same location and at the
same process operating conditions for a
minimum period of two hours with each
instrument. The shorter slotted tube may
be used if the average opacity measured
is equivalent (± 10 percent) to the
opacity measured by tfie non-slotted
tube design.
6. Optical Design Specifications
Verifciation Procedure.
These procedures will not be
applicable to all designs and will require
modification in some cases; all
modifications are subject to the
approval of the Administrator.
Test each analyzer for conformance
with the design specifications of
Sections 5.1 and 5.2 or obtain a
certificate of conformance from the
analyzer manufacturer as follows;
6.1 Spectral Response. Obtain
detector response, lamp emissivity and
filter transmittance data for the
components used in the measurement
system from their respective
manufacturers.
6.2 Angle of View. Set up the
receiver as specified by the
manufacturer's written instructions.
Draw an arc with radius of 3 meters in
the horizontal direction. Using a small
(less than 3 centimeters) non-directional
light source, measure the receiver
response at 4-centimeter intervals on the
arc for 24 centimeters on either side of
the detector centerline. Repeat the test
in the vertical direction.
6.3 Angle of Projection. Set up the
projector as specified by the
manufacturer's written instructions.
Draw an arc with radius of 3 meters in
the horizontal direction. Using a small
(less than 3 centimeters) photoelectric
light detector, measure the light
intensity at 4-centimeter intervals on the
arc for 24 centimeters on either side of
the light source centerline of projection.
Repeat the test in the vertical direction.
6.4 Optical Alignment Sight. In the
laboratory set up the instrument as
specified by the manufacturers written
instructions for a monitor pathlength of
8 meters. Assure that the instrument has
been properly aligned and that a proper
zero and span have been obtained.
Insert an attenuator of 10 percent
(nominal) opacity into the instrument
pathlength. Slowly misalign the
projector unit until a positive or negative
shift of two percent opacity is obtained
by the data recorder. Then, following
the manufacturer's written instructions,
check the alignment and assure that the
alignment procedure does in fact
indicate that the instrument is
misaligned. Realign the instrument and
follow the same procedure for checking
misalignment of the receiver or
retroreflector unit'.
6.5 Manufacturer's Certificate of
Conformance (Alternative to above).
Obtain from the manufacturer a
certificate of conformance which
certifies that the first analyzer randomly
sampled from each month's production
was tested according to Sections 6.1
through 6.3 and satisfactorily met all
requirements of Section 5 of this
Specification. If any of the requirements
were not met, the certificate must state
that the entire month's analyzer
production was resampled according to
the military standard 105D sampling
procedure (MIL-STD-105D) inspection
level II; was retested for each of the
applicable requirements under Section 5
of this Specification; and was
determined to be acceptable under MIL-
STD-105D procedures, acceptable
quality level 1.0, The certificate of
conformance must include the results of
each test performed for the analyzer(s)
sampled during the month the analyzer
being installed was produced.
7. Performance Specifications
The opacity continuous monitoring
system performance specifications are
listed in Table 1-1.
Table 1-1.—Performance specifications
Table 1-1.—Performance specifications—Continued
Parameter
Specifications
Parameter
Specification!
6 Calibration dnfl (24-hour) •
7 Data recorder resolution
• S pet opacity
: 0 50 pet ol full scale
span value
1 Calibration error • . .
2 Response time
3 Conditioning period6
4 Operational test penod •
5 Zero drift (24-hour) • . ..
S 3 pet opacity
S 10 seconds
=f 168 hours
a 168 hours
S 2 pet opacity
• Expressed as sum of absolute mean and the 95 percent
confidence interval
• During the conditioning and operational test periods the
continuous monitonng system shall not require any corrective
maintenance, repair, replacement, or adjustment other than
that clearly specified as routine and required in the operation
and maintenance manuals
8. Performance Specification
Verification Procedure
Test each continuous monitoring
system that conforms to the design
specifications (Section 5) using the
following procedures to determine
conformance with the performance
specifications of Section 7.
8.1 Preliminary Adjustments and
Tests. Prior to installation of the system
on the stack, perform these steps or tests
at the affected facility or in the
manufacturer's laboratory.
8.1.1 Equipment Preparation. Set up
and calibrate the monitoring system for
the monitor pathlength to be used in the
installation as specified by the
manufacturer's written instructions. If
the monitonng system has automatic
pathlength adjustment, follow the
manufacturer's instructions to adjust the
signal output from the analyzer to
equivalent values based on the emission
outlet pathlength. Set the span at the
value specified in the applicable
subpart. At this time perform the zero
alignment by balancing the response of
the continuous monitoring system so
that the simulated zero check coincides
with the actual zero check performed
across the simulated monitor pathlength
Then, assure that the upscale calibration
value is within the required opacity
range (Section 3.3).
B.I.2 Calibrated Attenuator
Selection. Based on the span value
specified in the applicable subpart,
select a minimum of three calibrated
attenuators (low, mid, and high range)
using Table 1-2. If the system is
operating with automatic pathlength
compensation, calculates the attenuator
values required to obtain a system
response equivalent to the applicable
values shown in Table 1-2, use equation
1-1 for the conversion. A series of filters
with nominal optical density (opacity)
values of 0.1(20), 0.2(37), 0.3(50), 0.4(60).
0.5(68). 0.6(75), 0.7(80), 0.8(84). 0.9(88).
and 1.0(90) are commercially available
Within this limitation of filter
availability, select the calibrated
V-Appendix B-5
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Federal Register / Vol. 44. No. 197 / Wednesday, October 10, 1979 / Proposed Rules
attenuators having the values given in
Table 1-2 or having values closest to
those calculated by Equation 1-1.
Table 1-2.—Required Calibrated Attenuator Values
(Nominal)
Span vaKje
(percent opacrty)
Calibrated attenuator
optical density
(equivalent opacrty
m parenthesis)
Low-range D, Mid-range High-range
50
60
70
80
90
100
0 1 (20)
1 (20)
1 (20)
1 (20)
1 (20)
1 (20)
02
2
.3
3
4
4
(37)
(37)
(50)
(50)
(60)
(60)
03
3
4
.6
7
9 (1
(50)
(50)
ISO)
(751
(80)
37';)
D, = D2 (L./L,)
Equation 1-1
Where:
Di = Nominal optical density value of
required mid. low. or high range
calibration attenuators.
Dz = Desired attenuator optical density
output value from Table 1-2 at the span
required by the applicable subpart.
L, = Monitor pathlength.
Lz = Emission outlet pathlength.
8.1.3 Attenuator Calibration.
Calibrate the required filters or screens
using a laboratory spectrophotometer
meeting the specifications of Section 3.4
to measure the transmittance in the 400
to 700 nm wavelength range; make
measurements at wavelength intervals
of 20 nm or less. As an alternate
procedure use an instrument meeting the
specifications of Section 3.4 to measure
the C.I E. Daylightc Luminous
Transmittance of the attenuators. During
the calibration procedure assure that a
minimum of 75 percent of the total area
of the attenuator is checked The
attenuator manufacturer must specify
the period of time over which the
attenuator values can be considered
stable, as well as any special handling
and storing procedures required to
enhance attenuator stability. To assure
stability, attenuator values must be
rechecked at intervals less than or equal
to the period of stability guaranteed by
the manufacturer. However, values must
be rechecked at least every 3 months. If
desired, testability checks may be
performed on an instrument other than
that initially used for the attenuator
calibration (Section 3.4). However, if a
different instrument is used, the
instrument shall be a high quality
laboratory transmissometer or
spectrophotometer and the same
instrument shall always be used for the
stability checks. If a secondary
instrument is to be used for stability
checks, the value of the calibrated
attenuator shall be measured on this
secondary instrument immediately
following calibration and prior to being
used. If over a period time an attenuator
value changes by more than ±2 percent
opacity, it shall be recalibrated or
replaced by a new attenuator.
If this procedure is conducted by the
filter or screen manufacturer or
independent laboratory, obtain a
statement certifying the values and that
the specified procedure, or equivalent,
was used.
8.1.4 Calibration Error Test. Insert
the calibrated attenuators (low, mid, and
high range) in the transmissometer path
at or as near to the midpoint as feasible.
The attenuator must be placed in the
measurement path at a point where the
effluent will be measured; i.e., do not
place the calibrated attenuator in the
instrument housing. While inserting the
attenuator, assure that the entire
projected beam will pass through the
attenuator and that the attenuator is
inserted in a manner which minimizes
interference from reflected light. Make a
total of five nonconsecutive readings for
each filter. Record the monitoring
system output readings in percent
opacity (see example Figure 1-1).
8.1.5 System Response Test. Insert
the high-range calibrated attenuator in
the transmissometer path five times and
record the time required for the system
to respond to 95 percent of final zero
and high-range filter values (see
example Figure 1-2).
8.2 Preliminary Field Adjustments.
Install the continuous monitoring system
on the affected facility according to the
manufacturer's written instructions and
perform the following preliminary
adjustments;
8.2.1 Optical and Zero Alignment.
When the facility is not in operation,
conduct the optical alignment by
aligning the light beam from the
transmissometer upon the optical
surface located across the duct or stack
(i.e., the retroflector or photodetector, as
applicable) in accordance with the
manufacturer's instructions. Under clear
stack conditions, verify the zero
alignment (performed in Section 8.1.1)
by assuring that the monitoring system
response for the simulated zero check
coincides with the actual zero measured
by the transmissometer across the clear
stack. Adjust the zero alignment, if
necessary. Then, after the affected
facility has been started up and the
effluent stream reaches normal
operating temperature, recheck the
optical alignment. If the optical
alignment has shifted realign the optics.
8.2.2 Optical and Zero Alignment
(Alternative Procedure). If the facility is
already on line and a zero stack
condition cannot practicably be
obtained, use the zero alignment
obtained during the preliminary
adjustments (Section 8.1.1) prior to
installation of the transmissometer on
the stack. After completing all the
preliminary adjustments and tests
required in Section 8.1, install the
system at the source and align the
optics, i.e., align the light beam from the
transmissometer upon the optical
surface located across the duct or stack
in accordance with the manufacturer's
instruction. The zero alignment
conducted in this manner shall be
verified and adjusted, if necessary, the
first time the facility is not in operation
after the operational test period has
been completed.
8.3 Conditioning Period. After
completing the preliminary field
adjustments (Section 8.2), operate the
system according to the manufacturer's
instructions for an initial conditioning
period of not less than 168 hours while
the source is operating. Except during
times of instrument zero and upscale
calibration checks, the continuous
monitoring system will analyze the
effluent gas for opacity and produce a
permanent record of the continuous
monitoring system output. During this
conditioning period there shall be no
unscheduled maintenance, repair, or
adjustment. Conduct daily zero
calibration and upscale calibration
checks, and, when accumulated drift
exceeds the daily operating limits, make
adjustments and/or clean the exposed
optical surfaces. The data recorder shall
reflect these checks and adjustments. At
the end of the operational test period,
verify that the instrument optical
alignment is correct. If the conditioning
period is interrupted because of source
breakdown (record the dates and times
of process shutdown), continue the 168-
hour period following resumption of
source operation. If the conditioning
period is interrupted because of monitor
failure, restart the 168-hour conditioning
period when the monitor becomes
operational.
8.4 Operational Test Period. After
completing the conditioning period
operate the system for an additional
168-hour period. It is not necessary that
the 168-hour operational test period
immediately follow the 168-hour
conditioning period. Except during times
of instrument zero and upscale
calibration checks, the continuous
monitoring system will analyze the
effluent gas for opacity and will produce
a permanent record of the continuous
monitoring system output. During this
period, there will be no unscheduled
maintenance, repair, or adjustment. Zero
and calibration adjustments, optical
surface cleaning, and optical
realignment may be performed
(optional) only at 24-hour intervals or at
V-Appendix B-6
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
such shorter intervals as the
manufacturer's written instructions
specify. Automatic zero and calibration
adjustments made by the monitoring
system without operator intervention or
initiation are followable at any time. If
the operational test period is interrupted
because of source breakdown, continue
the 168-hour period following
resumption of source operation. If the
test period is interrupted because of
monitor failure, restart the 168-hour
period when the monitor becomes
operational. During the operational test
period, perform the following test
procedures:
8.4.1 Zero Drift Test. At the outset of
the 168-hour operational test period,
record the initial simulated zero and
upscale opacity readings (see example
Figure 1-3). After each 24-hour interval
check and record the final zero reading
before any optional or required cleaning
and adjustment. Zero and upscale
calibration adjustments, optical surface
cleaning, and optical realignment may
be performed only at 24-hour intervals
(or at such shorter intervals as the
manufacturer's written instructions
specify) but are optional. However,
adjustments and/or cleaning must be
performed when the accumulated zero
calibration or upscale calibration drift
exceeds the 24-hour drift specifications
(±2 percent opacity). If no adjustments
are made after the zero check the final
zero reading is recorded as the initial
reading for the next 24-hour period. If
adjustments are made, the zero value
after adjustment is recorded as the
initial zero value for the next 24-hour
period. If the instrument has an
automatic zero compensation feature for
dirt accumulation on exposed lens, and
the zero value cannot be measured
before compensation is entered then
record the amount of automatic zero
compensation for the final zero reading
of each 24-hour period. (List the
indicated zero values of the monitoring
system in parenthesis.)
6.4.2 Upscale Drift Test. At each 24-
hour interval, after the zero calibration
value has been checked and any
optional or required adjustments have
been made, check and record the
simulated upscale calibration value. If
no further adjustments are made to the
calibration system at this time, the final
upscale calibration value is recorded as
the initial upscale value for the next 24-
hour period. If an instrument span
adjustment is made, the upscale value
after adjustment is recorded as the
initial upscale for the next 24-hour
period.
During the operational test period
record all adjustments, realignments and
lens cleanings.
9. Calculation, Data Analysis, and
Reporting
9.1 Arithmetic Mean. Calculate the
mean of a set of data as follows:
- 1 n
X • ; I X,
~° 1-1 1
Equation 2-1
Where:
x = mean value.
n = number of data points.
2x, = algebraic sum of the individual
measurements, x,
9.2 Confidence Interval. Calculate
the 95 percent confidence interval (two-
sided) as follows:
c.!.
95
Equation 2-!
Where:
C.I.,s = 95 percent confidence interval
estimate of the average mean value.
1 975 = '(1—a/2).
Table 1-3— '.975 Values
2
3
4
i
6
12706
4303
3 <82
2776
2571
7
e
8
10
11
2447
2385
2306
2282
2228
12
13
t<
15
16
2201
2179
2160
2145
.2131
The values in this table are already
corrected for n-1 degrees of Freedom.
Use n equal to the number of data
points.
9.3 Conversion of Opacity Values
from Monitor Pathlength to Emission
Outlet Pathlength. When the monitor
pathlength is different than the emisson
outlet pathlength, use either of the
following equations to convert from one
basis to the other (this conversion may
be automatically calculated by the
monitoring system):
log(l-Opa)
,) Log (1-Op,) Equation 1-4
D3 = (L2/Li) Equation 1-5
Where:
Op, = opacity of the effluent based upon L,
Opi = opacity of the effluent based upon L,
Li = monitor pathlength
L2 = emission outlet pathlength
Di = optical density of the effluent based
upon L,
Dz = optical density of the effleunt based
upon Li
9.4 Spectral Response. Using the
spectral data obtained in Section 6.1,
develop the effective spectral response
curve of the transmissometer. Then
determine and report the peak spectral
response wavelength, the mean spectral
response wavelength, and the maximum
response at any wavelength below 400
nm and above 700 nm expressed as a
percentage of the peak response.
9.5 Angle of View. For the horizontal
and vertical directions, using the data
obtained in Section 6.2, calculate the
response of the receiver as a function of
viewing angle (21 centimeters of arc
with a radius of 3 meters equal 4
degrees), report relative angle of view
curves, and determine and report the
angle of view.
9.6 Angle of Projection. For the
horizontal and vertical directions, using
the data obtained in Section 6.3,
calculate the response of the
photoelectric detector as a function of
projection angle, report relative angle of
projection curves, and determine and
report the angle of projection.
9.7 Calibration Error. See Figure 1-1.
If the pathlength is not adjusted by the
measurement system, subtract the
actual calibrated attenuator value from
the value indicated by the measurement
system recorder for each of the 15
readings obtained pursuant to Section
8.1.4. If the pathlength is adjusted by the
measurement system subtract the "path
adjusted" calibrated attenuator values
from the values indecated by the
measurement system recorder the "path
adjusted" calibrated attenuator values
are calculated using equation 1-4 or 1-
5). Calculate the arithmetic mean
difference and the 95 percent confidence
interval of the five tests at each
attenuator value using Equations 1-2
and 1-3. Calculate the sum of the
absolute value of the mean difference
and the 95 percent confidence interval
for each of the three test attenuators;
report these three values as the
calibration error.
9.8 Zero and Upscale Calibration
Drifts. Using the data obtained in
Sections 8.4.1 and 8.4.2 calculate the
zero and upscale calibration drifts. Then
calculate the arithmetic means and the
95 percent confidence intervals using
Equations 1-2 and 1-3. Calculate the
sum of the absolute value of the mean
and the 95 percent confidence interval
and report these values as the 24-hour
zero drift and the 24-hour calibration
drift.
9.9 Response Time. Using the data
collected in Section 8.1.5, calculate the
mean time of the 10 upscale and
downscale tests and report this value as
the system response time.
9.10 Reporting. Report the following
(summarize in tabular form where
appropriate).
9.10.1 General Information.
a. Instrument Manufacturer.
b. Instrument Model Number.
c. Instrument Serial Number.
V-Appendix B-7
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
d. Person(s) responsible for
operational and conditioning test
periods and affiliation.
e. Facility being monitored.
f. Schematic of monitoring system
measurement path location.
g. Monitor pathlength, meters.
h. Emission outlet pathlength, meters.
i. System span value, percent opacity.
j. Upscale calibration value, percent
opacity.
k. Calibrated Attenuator values (low,
mid, and high range), percent opacity.
9.10.2 Design Specification Test
Results
a. Peak spectral response, nm.
b. Mean spectral response, nm.
c. Response above 700 nm, percent of
peak.
d. Response below 400 nm, percent of
peak.
e. Total angle of view, degrees.
f. Total angle of projection, degrees.
9.10.3 Operational Test Period
Results.
a. Calibration error, high-range,
percent opacity.
b. Calibration error, mid-range,
percent opacity.
c. Calibration error, low-range,
percent opacity.
d. Response time, seconds.
e. 24-hour zero drift, percent opacity.
f. 24-hour calibration drift, percent
opacity.
g. Lens cleaning, clock time.
h. Optical alignment adjustment, clock
time.
9.10.4 Statements. Provide a
Statement that the conditioning and
operational test periods were completed
according to the requirements of
Sections 8.3 and 8.4. In this statement,
include the time periods during which
the conditioning and operational test
periods were conducted.
9.10.5 Appendix. Provide the data
tabulations and calculations for the
above tabulated results.
9.11 Retest. If the continuous
monitoring system operates within the
specified performance parameters of
Table 1-1, the operational test period
will be successfully concluded. If the
continuous monitoring system fails to
meet any of the specified performance
parameters, repeat the operational test
period with a system that meets the
design specifications and is expected to
meet the performance specifications.
10. Bibliograpny.
10.1 "Experimental Statistics,"
Department of Commerce, National
Bureau of Standards Handbook 91,1963,
pp. 3-31, paragraphs 3-3.1.4.
10.2 "Performance Specifications for
Stationary-Source Monitoring Systems
for Gases and Visible Emissions,"
Environmental Protection Agency,
Research Triangle Park, N. C., EPA-650/
2-74-013, January 1974. '
V-Appendix B-8
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
Person Con
Affiliation _
riurting Tp^t . , Analyzer Manufacturer
M^Hol/Qorial Mr,
DfltP 1 nratinn
Monitor Pal
Monitoring
Calibrated f
Actual C
Lou
Mid
Higl
Run
Number
1 — Low
2 -Mid
3 - High
4 — Low
5 -Mid
6 - High
7 — Low
8 -Mid
9 - High
10-Low
11-Mid
12-High
13-Low
14-Mid
15-High
System Output Pathlength Corrected? Yes No
Meutral Density Filter Values
Jptical Density (Opacity): Path Adjusted Optical Density (opacity)
j Rangp { ) | ow RflPQP . , { )
Range ( , . ,_J Mid Rangp , ,_( .)
i Rangp (. _ ) H'gh Rf»nge .( )
Calibration Filter
Value
(Path Adjusted Percent Opacity)
Instrument Reading
(Percent Opacity)
Arithmetic Mean (Equation 1 - 2): A
Confidence Interval (Equation 1 - 3): B
Calibration Error |A| + JB|
Arithmetic Difference
(% Opacity)
Low
—
—
—
-
—
—
—
-
-
-
X
Mid
—
-
—
—
-
—
—
—
—
—
X
High
—
—
—
—
-
—
-
—
—
—
—
X
Figure 1 - 1. Calibration error determination
V-Appendix B-9
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
Person Conducting Test Analyzer Manufacturer .
Affiliation Model/Serial No
Date Location
High Range Calibration Filter Value: Actual Optical Density (Opacity).
Path Adjusted Optical Density (Opacity).
Upscale Response Value ( 0.95 x filter value) percent opacity
Downscale Response Value (0.05 x filter value) percent opacity
Upscale 1
2 seconds
3 seconds
4 seconds
5 seconds
Downscale 1 seconds
2 seconds
3 seconds
4 seconds
5
Average response seconds
Figure 1-2. Response Time Determination
V-Appendix B-10
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
Person
Affilia
Date
Conducting Tes
tinn
t AD
Mir.
1 n,
alyzer Man
del/ Serial
•atinn
jfacturpr .
Mr,
Monitor Pathlength, L
Monitoring System Oul
Upscale Calibration Va
Date
Time
Begin
End
F
— —
tput Pathlength Corrected
ue : Actual Optical Den
Path Adjusted Opti
mission Ou
:? Yes
sity (Opac
cal Density
tlet Pathler
r>
tv)
(Opacity)
iqth Lo
Jn
I 1
( )
Percent Opacity
Zero Reading*
Initial
A
Final
B
Arithmetic Mean (Eq. 1-2)
Conf dence Interval (Eq. 1-3)
Zero Drift
'without automatic zero compensatic
**if zero was adjusted (manually or a
prior to upscale check, then use c =
Zero
Drift
C = B-A
zero adjusted?
Upscale Calibration
Reading
Initial
D
Final
E
Upscale
Drift
F = E-D
Calibration Drift
Cali-
bration
Drift
G = F-C**
span adjusted?
lens cleaned?
Align-
ment
checked?
adjusted?
n
jtomatically)
0.
Figure 1 • 3. Zero Calibration Drift Determination
V-Appendix B-ll
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10. 1979 / Proposed Rules
Performance Specification 2—
Specifications and Test Procedures for
SOi and NO, Continuous Monitoring
Systems in Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains (a) installation requirements,
(b) instrument performance and
equipment specifications, and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of SOz and NO, continuous
monitoring systems, which may include,
for certain stationary sources, diluent
monitors. The test procedures in item
{c), above, are not applicable to single-
pass, in-situ continuous monitoring
systems; these systems will be
evaluated on a case-by-case basis upon
written request to the Administrator and
alternative test procedures will be
issued separately.
1.2 Principle. Any SO, or NO,
continuous monitoring system that is
expected to meet this Specification is
installed, calibrated, and operated for a
specified length of time. During this
specified time period, the continuous
monitoring system is evaluated to
determine conformance with the
Specification.
2. Definitions
2.1 Continuous Monitoring System.
The total equipment required for the
determination of a gas concentration or
a gas emission rate. The system consists
of the following major sub-systems:
2.1.1 Sample Interface. That portion
of a system that is used for one or more
of the following: sample acquisition,
sample transportation, sample
conditioning, or protection of the
monitor from the effects of the stack
effluent.
2.1.2, Pollutant Analyzer. That
portion of the system that senses the
pollutant gas and generates an output'
that is proportional to the gas
concentration.
2.1.3. Diluent Analyzer (if
applicable). That portion of the system
that senses the diluent gas (e.g., COa or
O2) and generates an output that is
proportional to the gas concentration.
2.1.4 Data Recorder. That portion of
the monitoring system that provides a
permanent record of the analyzer
output. The data recorder may include
automatic data reduction capabilities.
2.2 Types of Monitors. Continuous
monitors are categorized as "extractive"
or "in-situ," which are further
categorized as "point," "multipoint,"
"limited-path," and "path" type
monitors or as "single-pass" or "double-
pass" type monitors.
2.2.1 Extractive Monitor. One that
withdraws a gas sample from the stabk
and transports the sample to the
analyzer.
2.2.2 In-situ Monitor. One that
senses the gas concentration in the
stack environment and does not extract
a sample for analysis.
2.2.3 Point Monitor. One that
measures the gas concentration either at
a single point or along a path which is
less than 10 percent of the length of a
specified measurement line.
2.2.4 Multipoint Monitor. One that
measures the gas concentration at 2 or
more points.
2.2.5 Limited-Path Monitor. One that
measures the gas concentration along a
path, which is 10 to 90 percent of the
length of a specified measurement line.
2.2.6 Path Monitor. One that
measures the gas concentration along a
path, which is greater than 90 percent of
the length of a specified measurement
line.
2.2.7 Single-Pass Monitor. One that
has the transmitter and the detector on
opposite sides of the stack or duct.
2.2.8 Double-Pass Monitor. One that
has the transmitter and the detector on
the same side of the stack or duct.
2.3 Span Value. The upper limit of a
gas concentration measurement range
which is specified for affected source
categories in the applicable subpart of
the regulations.
2.4 Calibration Gases. A known
concentration of a gas in an appropriate
diluent gas.
2.5 Calibration Gas Cells or Filters.
A device which, when inserted between
the transmitter and detector of the
analyzer, produces the desired output
level on the data recorder.
2.6 Relative Accuracy. The degree of
correctness including analytical
variations of the gas concentration or
emission rate determined by the
continuous monitoring system, relative
to the value determined by the reference
method(s).
2.7 Calibration Error. The difference
between the gas concentration indicated
by the continuous monitoring system
and the known concentration of the
calibration gas, gas cell, or filter.
2.8 Zero Drift. The difference in the
continuous monitoring system output
readings before and after a stated period
of operation during which no
unscheduled maintenance, repair, or
adjustment took place and when the
pollutant concentration at the time of
the measurements was zero (i.e., zero
gas, or zero gas cell or filter).
2.9 Calibration Drift. The difference
in the continuous monitoring system
output readings before and after a stated
period of operation during which no
unscheduled maintenance, repair or
adjustment took place and when the
pollutant concentration at the time of
the measurements was a high-level
value (i.e., calibration gas, gas cell or
filter).
2.10 Response Time. The amount of
time it takes the continuous monitoring
system to display on the data recorder
95 percent of a step change in pollutant
concentration.
2.11 Conditioning Period. A
minimum period of time over which the
continuous monitoring system is
expected to operate with no
unscheduled maintenance, repair, or
adjustments prior to initiation of the
operational test period.
2.12 Operational Test Period. A
minimum period of time over which the
continuous monitoring system is
expected to operate within the
established performance specifications
with no unscheduled maintenance,
repair or adjustment.
3. Installation Specifications
Install the continuous monitoring
system at a location where the pollutant
concentration measurement* are
representative of the total emissions
from the affected facility and are
representative of the concentration over
the cross section. Both requirements can
be met as follows:
3.1 Measurement Location. Select an
accessible measurement location in the
stack or ductwork that is at least 2
equivalent diameters downstream from
the nearest control device or other point
at which a change in the pollutant
concentration may occur and at least 0.5
equivalent diameters upstream from the
effluent exhaust. Individual subparts of
the regulations may contain additional
requirements. For example, for steam
generating facilities, the location must
be downstream of the air preheater.
3.2 Measurement Points or Paths.
There are two alternatives. The tester
may choose either (a) to conduct the
stratification check procedure given in
Section 3.3 to select the point, points, or
path of average gas concentration, or (b)
to use the options listed below without a
stratification check.
Note.—For the purpose of this section, the
"centroidal area" is defined as a concentric
area that is geometrically similar to the stack
cross section and is no greater than 1 percent
of the stack cross-sectional area.
3,2.1 SO2 and NO, Path Monitoring
Systems. The tester may choose to
centrally locate the sample interface
(path) of the monitoring system on a
measurement line that passes through
the "centroidal area" of the cross
section.
V-Appendix B-12
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
3.2.2 SOi and NO, Multipoint
Monitoring Systems. The tester may
choose to space 3 measurement points
along a measurement line that passes
through the "centroidal area" of the
stack cross section, at distances of 16.7,
50.0, and 83.3 percent of the way across
it (see Figure 2-1).
POINT
NO.
DISTANCE
(% OF L)
16.7
500
833
"CENTROIDAL
AREA"
Figure 21. Location of an example measurement line (L) and measurement points.
V-Appendix B-13
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Federal Register / Vol. 44. No. 197 / Wednesday, October 10, 1979 / Proposed Rules
The following sampling strategies, or
equivalent, for measuring the
concentrations at the 3 points are
acceptable: (a) The use of a 3-probe or a
3-hole single probe arrangment,
provided that the sampling rate in each
of the 3 probes or holes is maintained
within 10 percent of their average rate
(This option requires a procedure,
subject to the approval of the
Administrator, to demonstrate that the
proper sampling rate is maintained); or
(b) the use of a traversing probe
arrangement, provided that a
measurement at each point is made at
least once every 15 minutes and all 3
points are traversed and sampled for
equal lengths of time within 15 minutes.
3.2.3 SOj Single-Point and Limited-
Path Monitoring Systems. Provided that
(a) no "dissimilar" gas streams (i.e.,
having greater than 10 percent
difference in pollutant concentration
from the average) are combined
upstream of the measurement location,
and (b] for steam generating facilities, a
COa or O2 cotinuous monitor is installed
in addition to the SO2 monitor,
according to the guidelines given in
Section 3.1 or 3.2 of Performance
Specification 3, the tester may choose to
monitor SO2 at a single point or over a
limited path. Locate the point in or
centrally locate the limited path over the
"centroidal area." Any other location
within the inner 50 percent of the stack
cross-sectional area that has been
demonstrated (see Section 3.4) to have a
concentration within 5 percent of the
concentration at a point within the
"centroidal area" may be used.
3.2.4 NO, Single-Point and Limited-
Path Monitoring Systems. For NO,
monitors, the tester may choose the
single-point or limited-path option
described in Section 3.2.3 only in coal-
burning steam generators (does not
include oil and gas-fired units) and nitric
acid plants, which have no dissimilar
gas streams combining upstream of the
measurement location.
3.3 Stratification Check Procedure.
Unless specifically approved in Section
3.2., conduct a stratification check and
select the measurement point, points, or
path as follows:
3.3.1 Locate 9 sample points, as
shown in Figure 2-2, a or b. The tester
may choose to use more than 9 points,
provided that the sample points are
located in a similar fashion as in Fgure
2-2.
3.3.2 Measure at least twice the
pollutant and, if applicable (as in the
case of steam generators), CO, or Oa
'concentrations at each of the sample
points. Moisture need not be determined
for this step. The following methods are
acceptable for the measurements: (a)
Reference Methods 3 (grab-sample), 6 or
7 of this part; (b) appropriate
instrumental methods which give
relative responses to the pollutant (i.e.,
the methods need not be absolutely
correct), subject to the approval of the
Administrator; or (c) alternative
methods subject to the approval of the
Administrator. Express all
measurements, if applicable, in the units
of the applicable standard.
3 3.3 Calculate the mean value and
select a point, points, limited-path, or
path which gives an equivalent value to
the mean. The point or points must be
within, and the limited-path or path
must pass through, the inner 50 percent
of the stack cross-sectional area. All
other locations must be approved by the
Administrator.
V-Appendix B-14
-------
1.9
2.8
C
3,7
4.6
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
POINT DISTANCE
NO. (%OFD)
10.0
30.0
50.0
70.0
90.0
(a)
•
2
(b)
•
6
•
9
Figure 22. Location of 9 sampling points for stratification check.
V-Appendix B-15
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
3.4 Acceptability of Single Point or
Limited Path Alternative Location. Any
of the applicable measurement methods
mentioned in Section 3.3.2, above, may
be used. Measure the pollutant and, if
applicable, CC>2 or O2 concentrations at
both the centroidal area and the
alternative locations. Moisture need not
be measured for this test. Collect a 21-
minute integrated sample or 3 grab-
samples, either at evenly spaced (7 ± 2
min.) intervals over 21 minutes or all
within 3 minutes, at each location. Run
the comparative tests either
concurrently or within 10 minutes of
each other. Average the results of the 3
grab-samples.
Repeat the measurements until a
minimum of 3 paired measurements
spanning a minimum of 1 hour of
process operation are obtained.
Determine the average pollutant
concentrations at the centroidal area
and the alternative locations. If
applicable, convert the data in terms of
the standard for each paired set before
taking the average. The alternative
sampling location is acceptable if each
alternative location value is within ± 10
percent of the corresponding centroidal
area value and if the average at the
alternative location is within 5 percent
of the average of the centroidal area.
4. Performance and Equipment
Specifications
The continuous monitoring system
performance and equipment
specifications are listed in Table 2-1. To
be considered acceptable, the
continuous monitoring system must
demonstrate compliance with these
specifications using the test procedures
of Section 6.
5. Apparatus
5.1 Continuous Monitoring System.
Use any continuous monitoring system
of SO, or NO, which is expected to meet
the specifications in Table 2-1. For
sources which are required to convert
the pollutant concentrations to other
emission units using diluent gas
measurements, the diluent gas
continuous monitor, as described in
Performance Specification 3 of this
Appendix, is considered part of the
continuous monitoring system. The data
recorder may be an analog strip chart
recorder type or other suitable device
with an input signal range compatible
with the analyzer output.
5.2 Calibration Gases. For
continuous monitoring systems that
allow the introduction of calibration
gases to the analyzer, the calibration
gases may be SO, in air or N,, NO in Na,
and NOs in air or N». Two or more
calibration gases may be combined in
the same gas cylinder, except do not
combine the NO and air. For NO,
monitoring systems that oxidize NO to
NOa, the calibration gases must be in the
form of NO. Use three calibration gas
mixtures as specified below:
5.2.1 High-Level Gas. A gas
concentration that is equivalent to 80 to
90 percent of the span value.
Table 2-1.—Continuous Monitoring System
Performance and Equipment Specifications
Parameter
Specification
1 Conditioning
penod'
2 Operational lest
period-
3 Calibration error •
4 Response time. ..
5 Zero drift 12-
hour) »•
6 Zero dntt (24-
hour)"
7 Calibration drift
(2-hour)*.
6 Calibration drift
(24-hour)'
0 Relative
accuracy *
10 Calibration gas
cells or filters
1 \ Data recorder
chart resolution
12 Extractive
systems with diluent
monitors
3168 hours
9166 hours.
« 5 pet of each mid-level and high-
level calibration value
* 15 minutes (5 minutes for 3-pomt
traversing probe arrangement).
e 2 pet ol span value
«2 pet of span value.
« 2 pet of span value.
« 2 5 pet of span value.
* 20 pet of the mean value of
reference methodXs) test data in
terms of emission standard or 10
percent of the applicable :
standard, whichever is greater
Must provide a check of all analyzer
internal mirrors and lenses and aH
electronic circuitry including the
radiation source and detector
assembly which are normally us0
m sampling and analysts
Chart scales must be readable to
within « 0 50 pet of full-scale
Must use the same sample interface
to sample both the pollutant and
diluent gases Place m series
(diluent after pollutant analyzer) or
use a "T "• Dunng the
conditioning and operational test
periods, the continuous momlonng
system shaH not require any
corrective maintenance, repair.
replacement, or adjustment other
than that clearly specified as
routine and required m the
operation and maintenance
manuals • Expressed as the sum
of the absolute mean value plus
the 95 percent confidence interval
ol a series of tests divided by a
reference value * A low-level (5-
15 percent of span value) drift lest
may be substituted for the zero
Dnft tests
5.2.2 Mid-Level Gas. A gas
concentration that is equivalent to 45 to
55 percent of the span value.
5.2.3 Zero Gas. A gas concentration
of less than 0.25 percent of the span
value. Ambient air may be used for the
zero gas.
5.3 Calibration Gas Cells or Filters.
For continuous monitoring systems
which use calibration gas cells or filters,
use three certified calibration gas cells
or filters as specified below:
5.3.1 High-Level Gas Cell or Filter.
One that produces an output equivalent
to 80 to 90 percent of the span value.
5.3.2 Mid-Level Gas Cell or Filter.
One that produces an output equivalent
to 45 to 55 percent of the span value.
5.3.3 Zero Gas Cell or Filter. One
that produces an output equivalent to
zero. Alternatively, an analyzer may
produce a zero value check by
mechanical means, such as a movable
mirror.
5.4 Calibration Gas—Gas Cell or
Filter Combination. Combinations of the
above may be used.
6. Performance Specification Test
Procedures.
6.1 Pretest Preparation.
6.1.1 Calibration Gas Certification.
The tester may select one of the
following alternatives: (a) The tester
may use calibration gases prepared
according to the protocol defined in
Citation 10.5, i.e. These gases may be
used as received without reference
method analysis (obtain a statement
from the gas cylinder supplier certifying
that the calibration gases have been
prepared according to the protocol); or
(b) the tester may use calibration gases
not prepared according to the protocol.
In case (b), he must perform triplicate
analyses of each calibration gas (mid-
level and high-level, only) within 2
weeks prior to the operational test
period using the appropriate reference
methods. Acceptable procedures are
described in Citations 10.6 and 10.7.
Record the results on a data sheet
(example is shown in Figure 2-3). Each
of the individual analytical results must
be within 10 percent (or 15 ppm,
whichever is greater) of the average;
otherwise, discard the entire set and
repeat the triplicate analyses. If the
average of the triplicate reference
method test results is within 5 percent of
the calibration gas manufacturer's tag
value, use the tag value; otherwise,
conduct at least 3 additional reference
method test analyses until the results of
6 individual runs (the 3 original plus 3
additional) agree within 10 percent or 15
ppm, whichever is greater, of the
average. Then use this average for the
cylinder value.
V-Appendix B-16
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10. 1979 / Proposed Rules
Figure 2-3. Analysis of Calibration Gases
Date (Must be within 2 weeks prior to the
operational test period)
Reference Method Used
Sample Run
1
2
3
Werage
laximum % Deviation
Mid-lever
ppm
High-level0
PPm
used
a Not necessary if the protocol in Citation 10.5 is
to prepare the gas cylinders.
Average must be 45 to 55 percent of span value.
c Average must be 80 to 90 percent of span value.
-Must be < + 10 percent of applicable average or 15 ppm,
whichever" Ts greater.
6.1.2 Calibration Gas Cell or Filter
Certification. Obtain (a) a statement
from the manufacturer certifying that the
calibration gas cells or filters (zero, mid-
level, and high-level) will produce the
stated instrument responses for the
continuous monitoring system, and (b) a
description of the test procedure and
equipment used to calibrate the cells or
filters. At a minimum, the manufacturer
must have calibrated the gas cells or
filters against a simulated source of
known concentration.
6.2 Conditioning Period. Prepare the
monitoring system for operation
according to the manufacturer's written
instructions. At the outset of the
conditioning period, zero and span the
system. Use the mid-level calibration
gas (or gas cell or filter) to set the span
at 50 percent of recorder full-scale. If
necessary to determine negative zero
drift, offset the scale by 10 percent. (Do
not forget to account for this when using
the calibration curve.) If a zero offset is
not possible or is impractical, a low-
level drift mav be substituted for the
zero drift, by using a low-level (5 to 15
percent of span value) calibration gas
(or gas cell or filter). This low-level
calibration gas (or gas cell or filter) need
not be certified. Operate the continuous
monitoring system for an initial 168-hour
period in the manner specified by the
manufacturer. Except during times of
instrument zero, calibration checks, and
system backpurges, the continuous
monitoring system shall collect and
condition the effluent gas sample (if
applicable), analyze the sample for the
appropriate gas constituents,-and
produce a permanent record of the
system output. Conduct daily zero and
mid-level calibration checks and, when
drift exceeds the daily operating limits,
make adjustments. The data recorder
shall reflect these checks and
adjustments. Keep a record of any
instrument failure during this time. If the
conditioning period is interrupted
because of source breakdown (record
the dates and times of process
shutdown), continue the 168-hour period
following resumption of source
operation. If the conditioning period is
interrupted because of monitor failure,
restart the 168-hour conditioning period
when the monitor becomes functional.
6.3 Operational Test Period. Operate
the continuous monitoring system for an
additional 168-hour period. The
continuous monitoring system shall
monitor the effluent, except during
periods when the system calibration and
response time are checked or during
system backpurges; however, the system
shaTT produce a permanent record of all
operations. Record any system failure
during this time on the data recorder
output sheet.
It is not necessary that the 168-hour
operational test period immediately
follow the 168-hour conditioning period.
During the operational test period,
perform the following test procedures:
6.3.1 Calibration Error
Determination. Make a total of 15
nonconsecutive zero, mid-level, and
high-level measurements (e g., zero, mid-
level, zero, high-level, mid-range, etc.).
V-Appendix B-17
-------
Federal Register / Vol. 44, No. 197 / Wednesday. October 10, 1979 / Proposed Rules
This will result in a set of 5 each of zero,
mid-level, and high-level measurements.
Convert the data output to concentration
units, if necessary, and record the
results on a data sheet (example is
shown in Figure 2-4). Calculate the
differences between the reference
calibration gas concentrations and the
measurement system reading. Then
calculate the mean, confidence interval,
and calibration errors separately for the
mid-level and high-level concentrations
using Equations 2-1, 2-2, and 2-3. In
Equation 2-3, use each respective
calibration gas concentration for R.V.
Figure 2-4. Calibration Error Determination
Run
no.
i1
T_
"V
4
5
! 6
I
j 7
' 8
9
10
11
12
13
14
15
Calibration gas
concentration3
PPtn_
A
Measurement system
reading
ppm
B
Arithmetic Mean (Eq. 2-1) »
Confidence Interval (Eq. 2-?) =
Calibration
Error (Eq. 2-3)D =
Arithmetic
differences
.ppm
A-B
Mid
High
—
a Calibration Data from Section 6.1.1 or 6.1.2
Mid-level: C = ppm
High-level: D - ppm
b Use C or D as R.V. 1n Eq. 2-3
Date
Figure 2-5. Response Time
High-level
Average
Upscale
min.
Downscale
min.
..PPm
B =
System Response Time (slower of A and B)
min.
V-Appendix B-18
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules 58621
6.3.2 Response Time Test Procedure.
At a minimum, each response time test
shall provide a check of the entire
sample transport line (if applicable), any
sample conditioning equipment (if
applicable), the pollutant analyzer, and
the data recorder. For in-situ systems,
perform the response time check by
introducing the calibration gases at the
sample interface (if applicable), or by
introducing the calibration gas cells or
filters at an appropriate location in the
pollutant analyzer. For extractive
monitors, introduce the calibration gas
at the sample probe inlet in the stack or
at the point of connection between the
rigid sample probe and the sample
transport line. If an extractive analyzer
is used to monitor the effluent from more
than one source, perform the response
time test for each sample interface.
To begin the response time test,
introduce zero gas (or zero cell or filter)
into the continuous monitor. When the
system output has stabilized, switch to
monitor the stack effluent and wait until
a "stable value" has been reached.
Record the upscale response time. Then,
introduce the high-level calibration gas
(or gas cell or filter). Once the system
has stabilized at the high-level
concentration, switch to monitor the
stack effluent and wait until a "stable
value" is reached. Record the downscale
response time. A "stable value" is
equivalent to a change of less than 1
percent of span value for 30 seconds or 5
percent of measured average
concentration for 2 minutes. Repeat the
entire procedure three times. Record the
results of each test on a data sheet
(example is shown in Figure 2-5).
Determine the means of the upscale and
downscale response times using
Equation 2-1. Report the slower time as
the system response time.
6.3.3 Field Test for Zero Drift and
Calibration Drift. Perform the zero and
calibration drift tests for each pollutant
analyzer and data recorder in the
continuous monitoring system.
6.3.3.1 Two-hour Drift. Introduce
consecutively zero gas (or zero cell or
filter) and high-level calibration gas (or
gas cell or filter) at 2-hour intervals until
15 sets (before and after) of data are
obtained. Do not make any zero or
calibration adjustments during this time
unless otherwise prescribed by the
manufacturer. Determine and record the
amount that the output had drifted from
the recorder zero and high-level value
on a data sheet (example is shown in
Figure 2-6). The 2-hour periods over
which the measurements are conducted
need not be consecutive, but must not
overlap. Calculate the zero and
calibration drifts for each set. Then
calculate the mean, confidence interval,
and zero and calibration drifts (2-hour)
using Equations 2-1, 2-2, and 2-3. In
Equation 2-3, use the span value for R.V.
6.3.3.2 Twenty-Four Hour Drift. In
addition to the 2-hour drift tests, perform
a series of seven 24-hour drift tests as
follows: At the beginning of each 24-
hour period, calibrate the monitor, using
mid-level value. Then introduce the
high-level calibration gas (or gas cell or
filter) to obtain the initial reference
value. At the end of the 24-hour period,
introduce consecutively zero gas (or gas
cell or filter) and high-level calibration
gas (or gas cell or filter); do not make
any adjustments at this time. Determine
and record the amount of drift from the
recorder zero and high-level value on a
data sheet (example is shown in Figure
2-7). Calculate the zero and calibration
drifts for each set. Then calculate the
mean, confidence interval, and zero and
calibration drifts (24-hour) using
Equations 2-1, 2-2, and 2-3. In Equation
2-3, use the span value for R.V.
V-Appendix B-19
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
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V-Appendix B-20
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
Note.—Automatic zero and calibration
adjustment? made by the monitoring system
without operator intervention or initiation are
allowable a! any time Manual adjustments,
however, are allowable only at 24-hour
intervals, unless a shorter time is specified by
the manufacturer
6.4 System Relative Accuracy.
Unless otherwise specified in an
applicable subpart of the regulations,
the reference methods for SO2, NO,,
diluent (O2 or CO2), and moisture are
Reference Methods 6, 7, 3, and 4,
respectively. Moisture may be
determined along with SO2 using
Method 6. See Citation 10.8. Reference
Method 4 is necessary only if moisture
content is needed to enable comparison
between the Reference Method and
monitor values Perform the accuracy
test using the following guidelines:
641 Location of Pollutant Reference
Method Sample Points. The following
specifies the location of the Reference
Method sample points which are on the
same cross-sectional plane as the
monitor's. However, any cross-sectional
plane within 2 equivalent diameter of
straight runs may be used, by using the
projected image of the monitor on the
selected plane in the following criteria.
6 4.1.1 For point monitors, locate the
Reference Method sample point no
further than 30 cm (or 5 percent of the
equivalent diameter of the cross section,
whichever is less) from the pollutant
monitor sample point.
641.2 For multipoint monitors
locate each Reference Method sample
traverse point no further than 30 cm (or
5 percent of the equivalent diameter of
the cross section, whichever is less)
from each corresponding pollutant
monitor sample point.
64.1.3 For limited-path and path
monitors, locate 3 sample points on a
line parallel to the monitor path and no
further than 30 cm (or 5 percent of the
equi\alent diameter of the cross section,
whichever is less) from the centerlme of
the monitor path The three points of the
Reference Method shall correspond to
points in the monitor path at 16.7, 50 0,
and 83 3 percent of the effective length
of the monitor path
642 Location of Diluent and
Moisture Reference Method Sample
Pomls.
6421 For sources which require
diluent monitors in addition to pollutant
monitors, locate each of the sample
points for the diluent Reference Method
measurements within 3 cm of the
corresponding pollutant Reference
Method sample point as defined in
Sections 64.1.1. 6.4.1.2. or 6.4.1.3. In
addition, locate each pair of diluent and
pollutant Reference Method sample
points no further than 30 cm (or 5
percent of the equivalent diameter of the
cross secticr,, whichever is less) from
both the diluent and pollutant
continuous monitor sample points or
paths
6 4.2.2 If it is necessary to convert
pollutant and/or diluent monitor
concentrations to a dry basis for
comparison with the Reference data,
locate each moisture Reference Method
sample point within 3 cm of the
corresponding pollutant or diluent
Reference Method sarrlple point as
defined in Sections 6.4.1.1, 6.4.1.2, 6.4.1.3,
or 6 4 2.1.
6.4 3 Number of Reference Method
Tests.
6.4.3.1 For NO, monitors, make a
minimum of 27 NO, Reference Method
measurements, divided into 9 sets.
6.4.3.2 For SO2 monitors, make a
minimum of 9 SO2 Reference Method
tests.
6.4.3.3 For diluent monitors, perform
one diluent Reference Method test for
each SO2 and/or NO, Reference Method
test(s).
6 4.3.4 For moisture determinations,
perform one moisture Reference Method
test for each or each set of pollutant(s)
and diluent (if applicable) Reference
Method tests.
Note.—The tester may choose to perform
more than 9 sets of NO, measurements or
more than 9 Sd reference method diluent, or
moisture tests If this option is chosen, the
tester ma>, at his discretion, reject up to 3 of
'the set or test results, so long as the total
number of set or test results used to
determine the relative accuracy is greater
than or equal to 9 Report all data including
rejected data.
6.4.4 Sampling Strategy for
Reference Method Tests. Schedule the
Reference Method tests so that they will
not be in progress when zero drift.
calibration drift, and response time data
are being taken, Within any 1-hour
period, conduct the following tests: (a)
one set, consisting of 3 individual
measurements, of NO, and/or one SO2;
(b) one diluent, if applicable; and (c) one
moisture (if needed). Whenever two or
more reference tests (pollutant, diluent,
and moisture) are conducted, the tester
may choose to run all these reference
tests within a 1-hour period. However, it
is recommended that the tests be run
concurrently or consecutively within a
4-minute interval if two reference tests
employ grab sampling techniques. Also
whenever an integrated reference test is
run together with grab sample reference
tests, it is recommended that the
integrated sample be started one-sixth
the test period before the first grab
sample is collected.
In order to properly correlate the
continuous monitoring system and
Reference Method data, mark the
beginning and end of each Reference
Method test period (including the exact
time of day) on the pollutant and diluent
(if applicable) chart recordings Use one
of the following strategies for the
Reference Method tests:
6.4.4.1 Single Point Monitors For
single point sampling, the tester may (a)
take a 21-minute integrated sample (e.g.
Method 6, Method 4, or the integrated
bag sample technique of Method 3); (b)
take 3 grab samples (e.g. Method 7 or
the grab sample technique of Method 3),
equally spaced at 7-minute (±2 min)
intervals (or one-third the test period);
or (c) take 3 grab samples over a 3-
minute test period.
6.442 Multipoint or Path Monitors.
For multipoint sampling, the tester may
either: (a) make a 21-mmute integrated
sample traverse, sampling for 7 minutes
(±2 min) (or one-third the test period) at
each point; or (b) take grab samples at
each traverse point, scheduling the grab
samples to that they are an equal
interval (7±2 minutes) of time apart (or
one-third the test period).
Note.—If the number of sample points is
greater than 3, make appropriate adjustments
to the induidudl sampling time intervals At
times NSPS performance test data may be
used as part of the data base of the
continuous monitoring relative accuracy
tests In these cases, other test periods as
specified in the applicable subparts of the
regulations may be uspd
6.4.5 Correlation of Reference
Method and Continuous Monitoring
System Data. Correlate the continuous
monitoring system data with the
Reference Method test data, as to the
time and duration of the Reference
Method tests. To accomplish this, first
determine from the continuous
monitoring system chart recordings, the
integrated average pollutant and diluent
(if applicable) concentration(s) for each
Reference Method test period. Be sure to
consider system response time. Then,
compare each integrated average
concentration against the corresponding
average concentration obtained by the
Reference Method, use the following
guidelines to make these comparisons-
6.4.5.1 If the Reference Method is an
integrated sampling technique (e g ,
Method 6), make a direct comparison of
the Reference Method results and the
continuous monitoring system integrated
average concentration.
6452 If the Reference Method is a
grab-sampling technique (e.g.. Method
7), first average the results from all grab-
samples taken during the test period,
and then compare this average value
against the integrated value obtained
from the continuous monitoring system
chart recording.
V-Appendix B-21
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Federal Register / Vol. 44. No. 197 / Wednesday, October 10, 1979 / Proposed Rules
6.5 Data Summary for Relative
Accuracy Tests. Summarize the results
on a data sheet; example is shown in
figure 2-8. Calculate the arithmetic
differences between the reference
method and the continuous monitoring
output sets. Then calculate the mean,
confidence interval, and system relative
accuracy, using Equation 2-1, 2-2, and
2-3. In Equation 2-3, use the average of
the reference method test results for
R.V.
7. Equations
7.1 Arithmetic Mean. Calculate the
mean of a data set as follows:
-"I
Equation 1-2
Where:
x = arithmetic mean.
n = number of data points.
2x, = algebraic sum of the individual
values, x,.
When the mean of the differences of
pairs of data is calculated, be sure to
correct the data for moisture.
7.2 Confidence Interval. Calculate
the 95 percent confidence interval (two-
sided) as follows:
C.I.95 - -^ /HEX z - O )2 Equation 1-3
*
Where:
C.I.w = 95 percent confidence interval
estimate of mean value.
t tr. = t(,-./,) (see Table 2-2)
BILLING CODE 8S8O-01-M
Table 2-2.—1= Values
rf '975 rf '975 n" '
2
3
4
5
6
12706
4303
3 182
2776
2571
7
e
9
10
11
2447
2365
2306
2262
2228
12
13
14
15
16
220t
2179
2160
2145
2131
' The values in this table are already corrected for n-1 de-
grees of freedom Use n equal to the number of ndwdual
values
V-Appendix B-22
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
1
1
X
o
to
sT
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10
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4->
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3
O>
•o
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s-
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10. 1979 / Proposed Rules
7.3 Relative Accuracy. Calculate the relative accuracy of a set of data as
follows:
R.A.
Where:
R. A.
1*1
|C.I.
R.V.
95'
« relative accuracy
«= absolute value^pf the arithmetic ««an
(from Equation 2-1).
- absolute value of the 95 percent confi-
dence Interval (from Equation 2-2).
* reference value, as defined in Sections
6.3.1, 6.3.3.1, 6.3.3.2, and 6.5.
8. Reporting _
At a minimum (check with regional
offices for additional requirements, if
any) summarize the following results in
tabular form: calibration error for mid-
level and high-level concentrations, the
slower of the upscale and downscale
response times, the 2-hour and 24-hour
zero and calibration drifts, and the
system relative accuracy. In addition.
provide, for the conditioning and
operational test periods, a statement to
the effect that the continuous monitoring
system operated continuously fjr a
minimum of 168 hours each, except
during times of instrument zero,
calibration checks, system backpurges,
and source breakdown, and that no
corrective maintenance, repair,
replacement, or adjustment other than
that clearly specified as routine and
required in the operation and
maintenance manuals were made. Also
include the manufacturer's certification
statement (if applicable) for the
calibration gas. gas cells, or filters.
Include all data sheets and calculations
and charts (data outputs), which are
necessary to substantiate that the
system met the performance
specifications.
9. Retest
If the continuous monitoring system
operates within the specified
performance parameters of Table 2-1.
the operational test period will be
successfully concluded. If the
continuous monitoring system fails to
meet any of the specifications, repeat
that portion of the testing which is
related to the failed specification.
10. Bibliography
10.1 "Monitoring Instrumentation for
the Measurement of Sulfur Dioxide in
Stationary Source Emissions,"
Environmental Protection Agency,
Research Triangle Park, N.C., February
1973.
10.2 "Instrumentation for the
Determination of Nitrogen Oxides
Content of Stationary Source
Emissions," Environmental Protection
Agency, Research Triangle Park, N.C.,
Volume 1, APTD-0847, October 1971;
Volume 2, APTD-0942, January 1972.
10.3 "Experimental Statistics,"
Department of Commerce, Handbook 91,
1963, pp. 3-31, paragraphs 3-3.1.4.
10.4 "Performance Specifications for
Stationary-Source Monitoring Systems
for Gases and Visible Emissions,"
Environmental Protection Agency,
Research Triangle Park, N.C., EPA-650/
2-74-013, January 1974.
10.5 Traceability Protocol for
Establishing True Concentrations of
Gases Used for Calibration and Audits
of Continuous Source Emission Monitors
(Protocol No. 1). June 15,1978.
Environmental Monitoring and Support
Laboratory; Dffice of Research and
Development, U.S. EPA, Research
Triangle Park, N.C. 27711.
10.6 Westlm. P. R. and J. W. Brown.
Methods for Collecting and Analyzing
Gas Cylinder Samples. Emission
Measurement Branch, Emission
Standards and Engineering Division,
Office of Air Quality Planning and
Standards, U.S. EPA, Research Triangle
Park. N.C.. July 1978.
10.7 Curtis. Foston. A Method for
Analyzing NOX Cylinder Gases—
Specific Ion Electrode Procedure.
Emission Measurement Branch,
Emission Standards and Engineering
Division, Office of Air Quality and
Standards, U.S. EPA, Research Triangle
Park. N.C.. October 1978.
10.8 Stanley, Jon and P. R. Westlin.
An Alternative Method for Stack Gas
Moisture Determination. Emission
Measurement Branch, Emission
Standards and Engineering Division,
Office of Air Quality Planning and
Standards, U.S. EPA, Research Triangle
Park, N.C., August 1978.
Performance Specification 3—
Specifications and Test Procedures for
COi and O, Continuous Monitors in
Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains (a) installation requirements,
(b) instrument performance and
equipment specifications, and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of continuous CO2 and O»
monitors that are used as diluent
monitors. The test procedures are
primarily designed for systems that
introduce calibration gases directly into
the analyzer; other types of monitors
(e.g.. single-pass monitors, as described
in Section 2.2.7 of Performance
Specification 2 of this Appendix) will be
evaluated on a case-by-case basis upon
written request to the Administrator,
and alternative procedures will be
issued separately.
1.2 Principle. Any COi or O,
continuous monitor, which is expected
to meet this Specification, is operated
for a specified length of time. During this
specified time period, the continuous
monitor is evaluated to determine
conformance with the Specification.
2. Definitions
The definitions are the same as those
listed in Section 2 of Performance
Specification 2.
3. Installation Specifications
3.1 Measurement Location and
Measurement Points or Paths. Select and
install the continuous monitor at the
same sampling location used for the
pollutant monitor(s). Locate the
measurement points or paths as shown
in Figure 3-1 or 3-2.
3.2 Alternative Measurement
Location and Measurement Points or
Paths The diluent monitor may be
V-Appendix B-24
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
installed at a different location from that
of the pollutant monitor, provided that
the diluent gas concentrations at both
locations differ by no more than 5
percent from that of the pollutant
monitor location for CO2 or the quantity,
20.9-percent O2, for O,. See Section 3.4
of Performance Specification 2 for the
demonstration procedure.
4. Continuous Monitor Performance and
Equipment Specifications
The continuous monitor performance
and equipment specifications are listed
in Table 3-1. To be considered
acceptable, the continuous monitor must
demonstrate compliance with these
specifications, using the test procedures
in Section 6.
5. Apparatus
5.1 CO2 or Oa Continuous Monitor.
Use any continuous monitor, which is
expected to meet this Specification. The
data recorder may either be an analog
strip-chart recorder or other suitable
device having an input voltage range
compatible with the analyzer output.
5.2 Calibration Gases. Diluent gases
shall be air or N2 for CO2 mixtures, and
shall be N2 for O2 mixtures. Use three
calibration gases as specified below
GEOMETRICALLY
SIMILAR
AREA
(<1%OF STACK
CROSS-SECTION)
(a)
GEOMETRICALLY
SIMILAR
AREA
( «t1%OF STACK
CROSS-SECTION)
(b)
Figure 3-1. Relative locations of pollutant (P) and diluent (D) measurement points in (a) circular
and (b) rectangular ducts. P is located at the centroid of the geometrically similar
area. Note: The geometrically similar area need not be concentric.
V-Appendix B-25
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10,1979 / Proposed Rules
PARALLEL
MEASUREMENT
LINES
GEOMETRICALLY
SIMILAR
AREAS
( <1%OF STACK
CROSS-SECTION)
GEOMETRICALLY
SIMILAR
AREAS
( <1%OF STACK
CROSS-SECTION)
(a)
PARALLEL
MEASUREMENT
LINES
(b)
Figure 3-2. Relative locations of pollutant (P) and diluent (D) measurement paths for (a) circular
and (b) rectangular ducts. P is located at the centroid of both the geometrically simi
lar areas and the pollutant monitor path cross-sectional areas. D is located at the cen-
troid of the diluent monitor path cross-sectional area.
V-Appendix B-26
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
Table 3-1.—Performance and Equipment
Specifications
Parameter
Specification
1 Conditioning •
period'
t Operational test \
penodv
1. Calibration error'...
4 ReponsetJme
f Zero dntt 12-
hour)"
6 Zero dntl (24-
hour)".
7 Calibration drift 12-
hour)».
t Calibration dntl
(24-hour) >.
• Data recorder chart
mokitlon
10 Extractive monitors
» 168 hours
f 168 hours
C 5 pel of each (mid-range and
high-range, only) calibration ga»
value
« 15 minutes
* 0 4 pet CO, or 0,
< 10 5 pet CO, or O,
« 0 4 pet CO, or O,
« 0 5 pet CO, or O,
Chart scales must be readable to
within « 0 50 pet of M-scale
Must use the same interface as the
pollutant monitor Place m a series
(diluent after pollutant analyzer) or
use a "T"
• Ounng the conditioning and operational test periods, the
contnuous monitor Shan not require any corrective mainte-
nance, repair, replacement, or adjustment other than thai
etearty specified as routine and required m the operation and
maintenance manuals.
* Expressed as the sum of the absolute mean value plus
(M 95 percent confidence interval of a series of tests
•A low-level (5-)5 percent of span value) drift tests may b*
•utxtrtuled for the zero dntt tests
B.2.1 High-Level Gas. A CO, or O,
concentration of 20.0 to 22.5 percent. For
Oi analyzers, ambient air (20.9 percent
Oi) may be used as the high-range
calibration gas; lower high-level O*
concentration may be used, subject to
the approval of the Administrator.
6.2.2 Mid-Level Gas. A CO, or O,
concentration of 11.0 to 14.0 percent; for
Oi analyzers, concentrations in the
operational range may be used.
5.2.3 Zero Gas. A CO, or Ot
concentration of less than 0.05 percent.
For CO, monitors, ambient air (0.03
percent CO2) may be used as the zero
gas.
8. Performance Specification Test
Procedures.
6.1 Calibration Gas Certification.
Follow the procedure as outlined in
Section 6.1.2 of Performance
Specification 2, except use 0.5 percent
CO, or O, instead of the 15 ppm. Figure
3-3 is provided as an example data
sheet.
6.2 Conditioning Period. Follow the
same procedure outlined in Section 6.2
of Performance Specification 2.
6.3 Operational Test Period. Follow
the same procedures outlined in Section
6.3 of Performance Specification 2, to
evaluate the calibration error, response
time, and the 2-hour and 24-hour zero
and calibration drifts. See example data
sheets (Figures 3-4 through 3-7).
6.4 System Relative Accuracy. (Note:
The relative accuracy is not determined
separately for the diluent monitor, but is
determined for the pollutant-diluent
system.) Unless otherwise specified in'
an applicable subpart of the regulations,
the Reference Methods for the diluent
concentration determination shall be
Reference Method 3 for CO2 or Oa. For
this test, Fyrite analyses may be used
for CO, and O, determinations. Perform
the measurements using the guidelines
below (an example data sheet is shown
in Figure 2-8 of Performance
Specification 2):
6.4.1 Location of Reference Method 3
Sampling Points. Locate the diluent
Reference Method sampling points
according to the guidelines given in
Section 6.4.2.1 of Performance
Specification 2.
6.4.2 Number of Reference Method
Tests. Perform one Reference Method 3
test according to the guideline in
Performance Specification 2.
6.4.3 Sampling Strategy for
Reference Method Tests. Use the basic
Reference Method sampling strategy
outlined in Section 6.4.4 (and related
sub-sections) of Performance
Specification 2.
6.4.4 Correlation of Reference
Method and Continuous Monitor Data.
Use the guidelines given in Section 6.4.5
of Performance Specification 2.
7. Equations, Reporting, Retest, and
Bibliography. The procedure and
citations are the same as in Sections 7
through 10 of Performance Specification
2.
|FR Doc 79-31033 Filed 10-9-79 8 45 am]
V-Appendix B-27
-------
Date
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
Figure 3-3. Analysis of Calibration Gases*
(Must be within 2 weeks prior to the opera-
tional test period)
Reference Method Used
Sample run
Average
Maximum %
deviation£
Mid-range0
ppm
High-range
ppm
a Not necessary 1f the protocol in Citation 10.5 of Perfor-
mance Specification 2 is used to prepare the gas cylinders.
c Average must be 11.0 to 14.0 percent; for 09, see Section
5.2.2. e-
Average must be 20.0 to 22.5 percent; for 09, see Section
5.2.1. '
e Must be ^ + 10 percent of applicable average or 0.5 percent,
whichever Ts greater.
V-Appendix B-28
-------
Federal Register / Vol. 44, No. 197 / Wednesday. October 10.1979 / Proposed Rules
Figure 3-4. Calibration Error Determination
Run
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Calibration Gas
Concentration8
ppm
A
Measurement System
Reading
ppm
B
Arithmetic Mean (Eq. 2-1 )b *
Confidence Interval (Eq. 2-2) =
Calibration Error (Eq. 2-3)b)C =
Arithmetic
D1 f f erences
pom
A-B
Mid
High
Calibration Data from Section 6.1
Mid-level: C = ppm
High-level: D = ppm
See Performance Specification 2
c Use C or D as R. V.
V-Appendix B-29
-------
Federal Register / Vol. 44. No. 197 / Wednesday. October 10,1979 / Proposed Rules
Figure 3-5. -Response Time
Date
High-Range =
ppm
Test Run
1
2
3
Average
Upscale
min
A =
Downscale
min
B =
System Response Time (slower of A and B) =
mm.
V-Appendix B-30
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10,1979 / Proposed Rules
Data
set
no
Date
Time
Begin
End
Zero Rd.
Init.
A
Fin.
B
Arithmetic Mean (Eq. 2-l)a
Confidence Interval (Eq. 2-2)a
Zero drift
Zero
drift
C=B-A
Hi -Range
Rdq.
Init.
D
Fin.
E
Span
drift
F=E-D
Calibration driftb
Calib.
drift
G=F-C
From Performance Specification 2.
Use Equation 2-3 of Performance Specification 2 and 1.0 for R. V,
Figure 3-6. Zero and Calibration Drift (2 hour)
V-Appendix B-31
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10.1979 / Proposed Rules
Data
set
no.
Date
Time
Begin
End
Zero Rdg
Init.
A
Fin.
B
Arithmetic Mean (Eq. 2-l)a
Confidence Interval (Eq. 2-2)a
Zero drift b
Zero
drift
C=BW\
Hi -Range
Rdq
Init.
D
Fin.
E
Span
drift
F=E-D
Calibration drift b
Calib.
drift
G=F-C
From Performance Specification 2.
Use Equation 2-3 of Performance Specification 2, with 1.0 for R. V.
Figure 3-7. Zero and Calibration Drift (24-hour)
V-Appendix B-32
-------
Federal Register / Vol. 44, No. 246 / Thursday, December 20, 1979 / Proposed Rules
40 CFR Part 60
[FRL 1378-3]
Standards of Performance for New
Stationary Sources Continuous
Monitoring Performance
Specifications; Extension of Comment
Period
AGENCY: Environmental Protection
Agency (EPA).
ACTION-. Extension of Comment Period.
SUMMARY: The deadline for submittal of
comment on the proposed revisions to
the continuous monitoring performance
specifications, which were proposed on
October 10,1S79 (44 FR 58G02), is being
extended from December 10,1979, to
February 11,1930.
DATES: Written comments and
information must be received on or
before February 11,1980.
ADDRESSES: Comments. Written
comments and information should be
submitted (in duplicate, if possible) to:
Central Docket Section (A-130),
Attention: Docket Number OAQPS-79-
4, U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 204CO.
Docket. Docket Number OAQPS-79-4,
containing material relevant to this
rulemaking, is located in the U.S.
Environmental Protection Agency
Central Docket Section, Room 2903B, 401
M Street, S.W., Washington, D.C. 20460.
The docket may be inspected between
8:00 a.m. and 4:00 p.m. on weekdays,
and a reasonable fee may be charged for
copying.
FOR fljf. rKEH INFORMATION CONTACT:
Mr. Don R. Goodwin (MD-13), U.S.
Environmental Protection Agency,
Research Tiiangle Park, N.C. 27711;
telephone (919) 541-5271.
SUPPLEMENTARY INFORMATION: On
October 10,1979 (44 FR 58602), the
Environmental Protection Agency
proposed revisions to the Continuous
Monitoring Performance Specifications
1, 2, and 3. The notice of proposal
requested public comments on the
standards by December 10,1979. Due to
delay in the shipping of copies of the
performance specifications publication,
a sufficient number of copies have been
unavailable for distribution to all
interested parties in time to allow their
meaningful review and comment by
December 10,1979. An extension of this
period is justified as this delay has
resulted in about a 5-week delay in
processing requests for the document.
Dated: December 12,1979.
Edward F. Tuerk,
Acting Assistant Administrator for Air, Noise,
and Radiation.
[FR Doc 7»-39002 Filed 12-19-79, B 45 am]
V-Appendix B-33
-------
Federal Register / Vol. 45. No. 35 / Wednesday. February 20, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1389-2}
Standards of Performance for New
Stationary Sources Continuous
Monitoring Performance
Specifications
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Advance notice of proposed
rulemaking.
SUMMARY: This notice sets forth draft
Performance Specification 4—
Specifications and Test Procedures for
Carbon Monoxide Continuous
Monitoring Systems in Stationary
Sources, which EPA is considering to
propose as an addition to Appendix B of
40 CFR Part 60. The intent of this
advance notice is to solicit comments on
the specifications and testing
procedures EPA is considering
This advance notice of proposed
rulemaking is issued under the authority
of Sections 111, 114, and 301(a) of the
Clean Air Act as amended (42 U.S.C
7411, 7414, and 7601(a)).
DATES: Written comments and
information should be post-marked on
or before May 20,1980.
ADDRESSES: Comments. Written
comments and information should be
submitted (in duplicate, if possible) to-
Central Docket Section (A-130),
Attention: Docket Number A-79-03, U.S.
Environmental Protection Agency, 401 M
Street, SW., Washington, D.C. 20460
Docket. Docket Number A-7.9-03.
containing material relevant to this
rulemaking, is located in the U.S.
Environmental Protection Agency
Central Docket Section, Room 2903B, 401
M Street, SW., Washington, D.C. 20460
The docket may be inspected between
8:00 a.m. and 4:00 p.m. on weekdays,
and a reasonable fee may be charged for"
copying.
FOR FURTHER INFORMATION CONTACT:
Mr. Don Goodwin (MD-13), U.S
Environmental Protection Agency.
Research Triangle Park, N.C. 27711.
telephone (919) 541-5271.
SUPPLEMENTARY INFORMATION: EPA
promulgated standards of performance
for new stationary sources pursuant to
Section 111 of the Clean Air Act, as
amended, on March 8,1974 (39 FR 9308)
for petroleum refineries and six other
stationary sources. New or modified
sources in these categories are required
to demonstrate compliance with the
standards of performance by means of
performance tests that are conducted at
the rime a new source commences
operation orshortly thereafter. To
ensure that these sources are properly
operated and maintained so as to
remain in compliance, provisions were
included in the standards that esquire
sources to install and operate a
continuous emission monitoring system.
One such requirement was for carbon
monoxide (CO) from petroleum
refineries.
When the standards were initially
proposed, EPA had limited knowledge
about the operation of continuous
monitors on such sources; thus, the
continuous emission monitoring
requirements were specified in general
terms. Additional guidance on the
selection and use of such instruments
was to be provided at a later date-
On October 6,1975 (40 FR 46259), the
Environmental Protection. Agency
amended Part 60 of the regulations by
adding Appendix B—Performance
Specifications 1, 2, and 3 for continuous
monitoring of (1) opacity, (2) sulfur
dioxide and nitrogen oxide, and (3)
oxygen or carbon dioxide, respectively
Performance specifications for CO
monitors were not published at that
time.
EPA has conducted short-term
evaluations of the applicability of
several continuous monitoring
instruments and has published the
results in the following documents:
Guidelines for Development of a Quality
Assurance program: Volume VUI—
Determination of CO Emissions from
Stationary Sources by NDIR
Spectrometry, EPA-650/4-74-OQ5-h
(February 1975); and Evaluation of
Continuous Monitors for Carbon
Monoxide in Stationary Sources. EPA-
600/2-77-063) March 1977). Both are
available through the National
Technical Information Service,
Springfield, Virginia 22161.
Based on the above documents,
specifications and test procedures were
drafted for continuous CO monitoring-
instruments, the format of the draft
Performance Specification 4 follows
closely that of the most recent proposed
revisions to Performance Specification 2
(44 FR 58602 dated Oct. 10,1979).
Several references are made in
Performance Specification 4 to>specific
sections of the Performance
Specification 2 revisions.
The Environmental Monitoring and
Support Laboratory of EPA is adso
presently conducting a laboratory and
long-term field study of CO continuous
monitoring systems. Results of this
study will provide essential background
and technical information in support of
or improvement to Performance
Specification 4. The completion date is
scheduled for mid-1981. For this reason.
Performance Specification 4 for CO is
published as an advance notice.
Specific Requests
EPA is requesting comments on the
attached draft Performance
Specification 4—Specifications and Test
Procedures for CO Monitoring Systems
in Stationary Sources. EPA is interested
in comments on alternatives to the
performance specifications and is
particularly interested in information
that could lead to the development of
improved or alternative procedures. EPA
is also interested in comments on the
following aspects of CO continuous
monitoring and Performance
Specification 4: (1) Estimates of
installation and operation costs
including equipment costs, manpower
requirements, data reduction options,
and maintenance costs, (2) procedures
applicable for the evaluation of single-
pass, in-situ monitoring system; (3)
laboratory testing procedures that are
necessary for determining monitoring
system performance acceptability and
those laboratory tests that can be
recommended as indications of the
quality of equipment operation; (4) the
specifications and limits set forth in
Section 4; (5) the applicability of
Reference Method 10 or other methods
for determining relative accuracy of
continuous CO monitoring systems
Dated: February 12,1980.
Barbara Blum,
Acting Administrator.
Performance Specification 4—
Specifications and Test Procedures for
Carbon Monoxide Continuous
Monitoring Systems in Stationary
Sources
I. Applicability and Principle
1.1 Applicability. This specification
contains (a) installation requirements.
(b) instrument performance and
equipment specifications, and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of carbon monoxide (CO)
continuous monitoring systems. The test
procedures are not applicable to single-
pass, in-situ monitoring systems; these
systems will be evaluated on a case-by-
case basis upon application to the
Administrator, and alternative
procedures will be issued separately
1.2 Principle. A CO continuous
monitoring system that is expected to
meet this specification is installed,
calibrated, and operated for a specified
length of time. During the specified time
period, the continuous monitoring
V-Appendix B-34
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Federal Register / Vol. 45, No. 35 / Wednesday, February 20, 1980 / Proposed Rules
system is evaluated to determine
conformance with the specification.
2. Definitions
The definitions are the same as those
listed in Section 2 of Performance
Specification 2.
3. Installation Specifications
Install the continuous monitoring
system at a location where the pollutant
concentration-measurements are
representative of the total emissions
from the affected facility. Use a point,
points, or a path that represents the
average concentration over the cross
section. Both requirements can be met
as follows:
3.1 Measurement Location. Select an
accessible measurement location in the
stack or ductwork that is at least two (2)
equivalent diameters downstream from
the nearest CO control device or other
point at which a change in the pollutant
concentration may occur and at least 0.5
equivalent diameter upstream from the
exhaust. Individual subparts of the
regulations may contain additional
requirements.
3.2 Measurement Points»or Paths.
The tester may choose to use the
following measurement point, points, or
path without a stratification check or he
may choose to conduct the stratification
check procedure given in Section 3.3 of
Performance Specification 2 to select the
point, points, or path of average gas
concentration.
3.2.1 CO Path Monitoring Systems.
Same as in Performance Specification 2,
Section 3.2.2.
3.2.3 Single-Point and Limited-Path
Monitoring Systems. Same as in
Performance Specification 2, Section
3.2.3.
4. Performance and Equipment
Specifications
The continuous monitoring system
performance and equipment
specifications are listed in Table 4-1. To
be considered acceptable, the
continuous monitoring system must
demonstrate compliance with these
specifications using the test procedures
of Section 6.
5. Apparatus
5.1 Continuous Monitoring System.
Use any continuous monitoring system
for CO, which is expected to meet the
specifications in Table 4-1. The data
recorder may be an analog strip-chart
recorder or other suitable device with an
input signal range compatible with the
analyzer output.
Table 4-1.—Continuous Monitoring System
Performance and Equipment Specifications
Parameter
Specrfication
1 Conditioning period •
2 Operational test
period1.
3, Calibration error'
4 Response time
5 Zero drift, 2 hours •....
6 Zero dnrt. 24 hours •..
7 Calibration drift, 2
hours'
8 Calibration drift, 24
hours'
9 Relative accuracy'
10 Calibration gas cells
or filters.
11 Data recorder chart
resolution.
> 168 hours.
? 168 hours
< 5 percent of each mid-level and
high-level calibration value
< 10 minutes.
Z_ 1 percent of span value.
< 2 percent of span varue
< 2 percent of span value.
525 percent of span value.
< 10 percent of Mean Ref value.
Must provide a check of all ana-
lyzer internal mirrors and lenses,
and all electronic circuitry in-
cluding the radiation source and
detector assembly, which are
normally used in sampling and
analysis.
Chart scales must be readable to
within ± 0.5 percent of full-
scale
' During the conditioning and operational test periods, the
continuous monitoring system shall not require any corrective
maintenance, replacement, or adjustment other than that
clearly specified as routine and required in the operation and
maintenance manuals
* Expressed as sum of absolute mean value plus 95 per-
cent confidence interval of a series tests divided by a refer-
ence value
5.2 Calibration Gases. For
continuous monitoring systems that
allow the introduction of calibration
gases to the analyzer, the calibration
gases must be CO in N». Use three
calibration gas mixtures as specified
below;
5.2.1 High-Level Gas. A gas
concentration that is equivalent to 80 to
90 percent of the span value.
5.2.2 Mid-Level Gas. A gas
concentration that is equivalent to 45 to
55 percent of the span value.
5.2.3 Zero Gas. A gas concentration
of less than 0.25 percent of the span
value. Prepurified nitrogen should be
used.
5.3 Calibration Gas Cells or Filters.
For continuous monitoring systems
which use calibration gas cells or filters,
use three certified calibration gas cells
or filters as specified below:
5.3.1 High-Level Gas Cell or Filter.
One that produces an output equivalent
to 80 to 90 percent of the span value.
5.3.2 Mid-Level Gas Cell or Filter.
One that produces an output equivalent
to 45 to 55 percent of the span value.
5.3.3 Zero Gas Cell or Filter. One
that produces an output equivalent to
zero. Alternatively, an analyser may
produce a zero value check by
mechanical means, such as a movable
mirror.
6. Performance Specification Test
Procedures
6.1 Pretest Preparation.
6.1.1 Calibration Gas Analyses. Use
calibration gas prepared according to
the protocol defined in Reference 10.2.
6.1.2 Calibration Gas Cell or Filter
Certification. Obtain from the
manufacturer a statement certifying that
the calibration gas cells or filters (zero,
mid-level, and high-level) will produce
the stated instrument response for the
continuous monitoring system, and a
description delineating the test
procedure and equipment used to
calibrate the cells or filters. At a
minimum, the manufacturer must have
calibrated the gas cells or filters against
a simulated source of known
concentration.
6.2 Continuous Monitoring System
Preparation.
6.2.1 Installation. Install the
continuous monitoring system according
to the measurement location procedures
outlined in Section 3 of this
specification. Prepare the system for
operation according to the
manufacturer's written instructions.
6.2.2 Conditioning Period. Follow the
procedure in Performance specification
2, Section 6.2.
6.3 Operational Test Period. Follow
the procedure in Performance
Specification 2, Section 6.3 and the
following subsections:
6.3.1 Calibration Error
Determination. Follow the procedures in
Performance Specification 2, Section
6.3.1.
6.3.2 Response Time Test Procedure.
Follow the procedures in Performance
Specification 2, Section 6.3.2.
6.3.3 Field Test for Zero Drift and
Calibration Drift. Follow the procedures
in Performance specification 2, Section
6.3.3.
6.4 System Relative Accuracy.
Follow the procedures in Performance
Specification 2, Section 6.4 and all the
accompanying subsections. The
reference method is Reference Method
10.
6.5 Data Summary for Relative
Accuracy Tests. Follow the procedures
in Performance Specification 2, Section
6.5.
7. Equations and Reporting
Follow the procedures in Performance
Specification 2, Section 7 and all the
accompanying subsections.
8. Reporting
Follow the procedures in Performance
Specification 2, Section 8.
9. Retest
Follow the procedures in Performance
Specification 2, Section 9.
V-Appendix B-35
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Federal Register / Vol. 45, No. 35 / Wednesday, February 20, 1980 / Proposed Rules
10. Bibliography
10.1 Repp, Mark. Evaluation of
Continuous Monitors for Carbon
Monoxide in Stationary Sources. U.S.
Environmental Protection Agency.
Research Triangle park, NC. Publication
No. EPA-600/2-77-063. March 1977.
10.2 Traceability Protocol for
Establishing True Concentrations of
Gases Used for Calibration and Audits
of Continuous Source Emission Monitors
(Protocol No. 1). June 15,1978.
Environmental Monitoring and Support
Laboratory, Office of Research
Development, U.S. Environmental
Protection Agency. Research Triangle
Park, NC 27711.
10.3 Department of Commerce.
Experimental Statistics. Handbook 91.
Ubrary of Congress No. 63-60072. U.S.
Government Printing Office,
Washington, DC.
|FR Doc 80-5289 Filed 2-19-80: 8:45 am|
V-Appendix B-36
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-340/1-80-001 a
3 RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Standard? of Performance for New Stationary Sources
A Compilation as of July 1, 1980
5 REPORT DATE
July 1980
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
PN 3570-3-S
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
11 CONTRACT/GRANT NO.
68-01-4147, Task 136
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Division of Stationary Source Enforcement
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Supplement, Jan 80 to July 80
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
DSSE Project Officer:
Kirk Foster, MD-7, Research Triangle Park, NC 27711;
(919) 541-4571
16. ABSTRACT
This document contains those pages necessary to update Standards of Performance for
New Stationary Sources - A Compilation, published by the U.S. Environmental Protec-
tion Agency, Division of Stationary Source Enforcement in November 1977 (EPA-340/1-
77-015) and other supplements published in 1979 and 1980. It is only an update and
must be used in conjunction with the original compilation and previous supplements.
Included in this update, with complete instructions for filing are: a title page
and table of contents; a new summary table; all rev.ised and new Standards of Per-
formance; the full text of all revisions and standards promulgated since January
1980; and all newly proposed standards or revisions.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution Control
Regulations; Enforcement
New Source Performance
Standards
13B
14B
18. DISTRIBUTION STATEMENT
Unlimited
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Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
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22. PRICE
EPA Form 2220-1 (9-73)
U.S. GOVERNMENT PRINTING OFFICE 1981-735-000/3025 REGION NO. 4
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