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3826
2 7 Title 40 — Protection of Environment
CHAPTER I— ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C — AIR PROGRAMS
PART 60 — STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Primary Aluminum Industry
On October 23. 1974 (39 FR 37730),
under sections 111 and 114 of the Clean
Air Act '42 U.S.C. 1857c-6, 1857c-9>. as
amended, the Administrator proposed
standards of performance for new and
modified primary aluminum reduction
plants. Interested persons participated
in the rulemaking by submitting written
comments to EPA. The comments have
been carefully considered and, where de-
termined by the Administrator to be ap-
propriate, changes have been made in
the regulations as promulgated.
These regulations will not, in them-
selves. require control of emissions from
existing primary aluminum reduction
plants. Such control will be required only
after EPA establishes emission guidelines
for existing plants under section lllfd)
of the Clean Air Act. which will trigger
the adoption of State emission standards
for existing plants. General regulations
concerning control of existing sources
under section lll(d) were proposed on
October 7, 1975 (39 FR 3G102) and were
promulgated on November 17, 1975 (40
FR 53339).
The bases for the proposed standards
are presented in the first two volumes of
a background document entitled "Back-
ground Information for Standards of
Performance: Primary Aluminum In-
dustry." Volume 1 'EPA 450/2-74-020a,
October 1974) contains the rationale for
the proposed standards and Volume 2
(EPA 450/2-74-020b, October 1974) con-
tains a summary of the supporting test
data. An inflation impact statement for
the standards and a summary of the
comments received on the proposed
standards along with the Agency re-
sponses are contained in a new Volume 3
(EPA 450/2-74-020C, November 1975) of
the background document. Copies of aJl
three volumes of the background docu-
ments are available on request from the
Emission Standards and Engineering Di-
vision, Environmental Protection Agency,
Research Triangle Park, N.C. 27711, At-
tention: Mr. Don R. Goodwin.
SUMMARY OF REGULATIONS
The standards of performance promul-
gated herein limit emissions of gaseous
and particulate fluorides from new and
modified affected facilities within pri-
mary aluminum reduction plants. The
standard for fluorides limits emissions
from each potroom group within Sodcr-
berg plants to 2.0 pounds of total fluo-
rides per ton of aluminum produced (Ib
TF/TAP) , from each potroom group
within prebake plants to 1.9 Ib TF/TAP,
and from each anode bake plant within
prebake plants to 0.1 Ib TF/TAP. Pri-
mary and secondary emission from pot-
room groups are limited to less than 10
percent opacity, and emissions from
RULES AND REGULATIONS
anode bake plants are limited to less than
20 percent opacity. The regulations re-
quire monitoring of raw material feed
rates, cell or potHne voltages, and daily
production rate of aluminum and an-
odes. Also included with the standards
is Reference Method 14 which specifies
equipment and sampling procedures for
emission testing of potroom roof moni-
tors. Fluoride samples collected during
performance tests will be analyzed ac-
cording to Reference Method 13A or 13B
which were promulgated along with
standards of performance for the phos-
phate fertilizer industry on August 6,
1975 (40 FR 33152).
SIGNIFICANT COMMENTS AND CHANGES
MADE TO THE PROPOSED REGULATIONS
Most of the comment letters received
by EPA contained multiple comments.
Copies of the comment letters received
and a summary of the comments and
Agency responses are available for pub-
lic, inspection and copying at the U.S.
Environmental Protection Agency, Pub-
lic Information Reference Unit. Room
2922 (EPA Library), 401 M Street. S.W.,
Washington, D.C. 20460. In addition.
copies of the issue summary and Agency
responses may be obtained upon written
request from the EPA Public Informa-
tion Center (PM-215), 401 M'street, SW.,
Washington, D.C. 20460 fspecify "Back-
ground Information for Standards of
Performance: Primary Aluminum Indus-
try Volume 3: Supplemental Informa-
tion" (EPA 45/2-74-020O 1. The most
significant comments and changes made
to the proposed regulations are discussed
below.
(1) Designation of Affected Facility.
Several comments questioned the "ap-
plicability and designation of affected
facility" section of the proposed regu-
lations (§ 60.190) in view of regulations
previously proposed by EPA with regard
to modification of existing plants (39
FR 36946, October 15, 1974). In § 60.190
as proposed, the entire primary alumi-
num reduction plant was designated as
the affected facility. The commentators
argued that, as a result of this desig-
nation, addition or modification of a
single potroom at an existing plant
would subject all existing potrooms at
the plant to the standards for new
sources. The commentators argued that
this situation would unfairly restrict ex-
pansion. The Agency considered these
comments and agreed that there would
be an adverse economic impact on ex-
pansion of existing plants unless the
affected facility designation were re-
vised.
To alleviate the problem, a new af-
fected facility designation has been in-
corporated in §60.19Q(a>. The affected
facilities within primary aluminum
plants are now each "potroom group"
and each anode bake plant within pre-
bake plants. This redesignation in turn
required splitting the fluoride standard
for prebake plants into separate stand-
ards for potroom groups and anode bake
plants (see discussion in next section).
As defined in § 60.191 (d). the term "pot-
room group" means an uncontrolled pot-
room, or a potroom which is controlled
individually, or a group of potrooms
ducted to the same control system. Under
this revised designation, addition or
modification of a potroom group at an
existing plant will not subject the entire
plant to the standards (unless the plant
consists of only one potroom group).
Similarly, addition or modification of an
anode bake plant at an exiting prebake
facility will not subject the entire pre-
bake facility to the standards. Only the
new or modified potroom group or anode
bake plant must meet the applicable
standards in such cases.
(2) Fluoride Standard. Many com-
mentators questioned the level of the
proposed standard; i.e.. 2.0 Ib TF/TAP.
A number of industrial commentators
suggested that the standard be relaxed
or that it be specified in terms of a
monthly or yearly emission limit. Some
commentators argued that the test data
did not support the standard and that
statistical techniques should have been
applied to the test data in order to ar-
rive at an emission standard.
Standards of performance under sec-
tion 111 are based on the best control
technology which (taking into account
control costs) has been "adequately
demonstrated." "Adequately demon-
strated" means that the Administrator
must determine, on the basis of all in-
formation available to him (including
but not limited to tests and observations
of existing plants and demonstration
projects or pilot applications) and the
exercise of sound engineering judgment,
that the control technology relied upon
in setting a standard of performance
can be made available and will be ef-
fective to enable sources to comply with
the standards. In other words, test data
for existing plants are not the only bases
for standard setting. As discussed in the
background document, EPA considered
not only test data for existing plants,
but also the expected performance of
newly constructed plants. Some existing
plants tested did average less than 2.0
Ib TF/TAP. Additionally, EPA believes
new plants can be specifically designed
for best control of air pollutants and,
therefore, that.new plant emission con-
trol performance should exceed that of
well-controlled existing plants. Finally,
relatively simple changes in current op-
erating methods (e.g., cell tapping) can
produce significant reductions in emis-
sions. For these reasons. EPA believes
the 2.0 Ib TF/TAP standard is both rea-
sonable and achievable. A more detailed
discussion of the rationale for selecting
the 2.0 Ib TF/TAP standard is contained
in Volume 1 of the background docu-
ment, and EPA's responses to specific
comments on the fluoride standard are
contained in Volume 3.
As a result of the revised affected fa-
cility designation, the 2.0 Ib TF/TAP
standard for prebake plants has been
split into separate standards for potroom,
groups (1.9 Ib TF/TAP) and anode bake
plants (0.1 Ib TF/TAP). The proposed
2.0 Ib'TF/TAP limitation for prebake
plants always consisted of these two
components, but was published as a com-
FEDERAL REGISTER, VOL. 41, NO. 17—MONDAY, JANUARY 26, 1976
V-133
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RULES AND REGULATIONS
3827
bined standard to be consistent with the
original affected facility designation
(i.e., the entire primary aluminum
plant). .At the time of proposal, the
Agency had not foreseen the potential
problems with modification of a two part
affected facility. Data supporting each
component of the standard as proposed
•is contained in the background docu-
ment (Volumes 1 and 2). In support of
the potroom component of the standard,
for example, two existing prebake pot-
rooms tested by the Agency averaged
less than 1.9 Ib TF/TAP. Because no well
controlled inode bake plants existed at
the time of aluminum plant testing, the
components for anode bake plants was
based on a conservatively assumed con-
trol efficiency for technology demonstrat-
ed in the phosphate fertilizer industry.
Using the highest emission rate observed
at two anode bake plants which were not
controlled for fluorides and applying the
assumed control efficiency, it was pro-
jected that these plants would emit ap-
proximately 0.06 Ib TF/TAP (0.12 Ib TF/
ton of carbon anodes produced). In addi-
tion, as indicated in Volume 1 of the
background document, it may be possi-
ble to meet the standard for anode bake
plants simply by better cleaning of anode
remnants. The Agency also has estimates
of emission rates for a prebake facility
to be built in the near future. The esti-
mates indicate that the anode bake plani
at the facility will easily meet the 0.1
TF/TAP standard.
One commentator questioned why the
standard was not more stringent con-
sidering the fact that Oregon has
promulgated the following standards for
new primary aluminum plants: (a) a
monthly average of 1.3 pounds of fluoride
ion per ton of aluminum produced, and
(b) an annual average of 1.0 pound of
fluoride ion per ton of aluminum
produced.
There are several reasons why the
Agency elected not to adopt standards
equivalent to the Oregon standards. Per-
haps most important, EPA believes that
the Oregon standards would require the
installation of relatively inefficient sec-
ondary scrubbing systems at most if not
all new primary aluminum plants. By
contrast, EPA's standard will require use
of secondary control systems only for
vertical stud Soderberg (VSS) plants
(which are unlikely to be built in any
event) and side-work prebake plants. A
standard requiring secondary control
systems on most if not all plants would
have a substantial adverse economic im-
pact on the aluminum industry, as is
indicated in the economic section of the
background document. Accordingly,
EPA has concluded that considerations
of cost preclude establishing a standard
comparable to the Oregon standards.
A second reason for not adopting
standards equivalent to the Oregon
standards stems from the fact that the
latter were based on test data consist-
ing of six monthly averages (calculated
by averaging from three to nine individ-
ual tests each month) from a certain
well controlled plant (which incorporates
both primary and secondary control).
Oregon applied a statistical method to
these data to derive the emission stand-
ards it adopted. As discussed in the com-
ment summary, EPA also performed a
statistical analysis of the Oregon test
data, which yielded results different
from those presented in the Oregon tech-
nical report. If the Agency's results had
been used, less stringent emission stand-
ards might have been promulgated in
Oregon.
A third consideration is that the test
methods used by Oregon were not the
same as those used by the Agency to
collect emission data in support of the
respective standards. Therefore, Ore-
gon's test data and the Agency's test
data are not directly comparable.
Finally, a comment on the standard
for fluorides questioned whether or not
EPA had considered a new, potentially
non-polluting primary aluminum reduc-
tion process developed by Alcoa. The
commentator argued that if the process
had become commercially available, the
standard should be set at a level suffi-
ciently stringent to stimulate the devel-
opment of this new process. In response
to this comment, EPA has investigated
the process and has determined that it
is not yet commercially available. Alcoa
plans to test the process at a small pilot
plant which will begin production early
next year. If the pilot plant performs
successfully, it will be expanded to full
design capacity by the early 1980's. EPA
will monitor the progress of this process
and other processes under development
and will reevaluate the standards of per-
formance for the primary aluminum in-
dustry, as appropriate, in light of the
new technology.
(3) Opacity. Some of the industrial
commentators objected to the proposed.
opacity standards for potrooms and
anode bake plants. They argued that
good control of total fluorides will result
in good control of particulate matter,
and therefore that the opacity standards
are unnecessary. EPA agrees that good
control of total fluorides will result in
good control of particulate matter; how-
ever, the opacity standards are intended
to serve as inexpensive enforcement tools
that will help to insure proper operation
and maintenance of the air pollution
control equipment. Under 40 CFR
60.1 ltd), owners and operators of af-
fected facilities are required to operate
and maintain their control equipment
properly at all times. Continuous moni-
toring instruments are often required to
indicate compliance with 60.11(d), but
this is not possible in the primary
aluminum industry because continuous
total fluoride monitors are not commer-
cially available. The data presented in
the background document indicate that
the opacity standards can be easily met
at well controlled plants that are prop-
erly operated and maintained. For these
reasons, the opacity standards have been
retained in the final regulations.
EPA recognizes, however, that in un-
usual circumstances (e.g., where emis-
sions exit from an extremely wide stack)
a source might meet the mass emission
limit but fail to meet the opacity limit.
In such cases, the owner or operator of
the source may petition the Administra-
tor to establish a separate opacity stand-
ard under 40 CFR 60.11(e) as revised o:
November 12, 1974 (39 FR 39872).
(4) Control of Other Pollutants. O
commentator was concerned that EPA"
did not propose standards for carbon
monoxide (CO) and sulfur dioxide (SO2)
emissions from aluminum plants. The
commentator argued that aluminum
smelters are significant sources of these
pollutants, and that although fluorides
are the most toxic aluminum plant emis-
sions, standards for all pollutants should
have been proposed. As discussed in the
preface to Volume 1 of the background
document, fluoride control was selected
as one area of emphasis to be considered
in implementing the Clean Air Act. In
•turn, primary aluminum plants were
identified as major sources of fluoride
emissions and were accordingly listed as
a category of sources for which standards
of performance would be proposed. Nat-
urally, the initial investigation into
standards for the primary aluminum
industry focused on fluoride control.
However, limited testing of CO and SO2
emissions was also carried out and it was
determined (a) that although primary
aluminum plants might be a significant
source of SO=1 SO- control technology had
not been demonstrated in the industry,
and (b) that CO emissions from such
plants were insignificant. For these rea-
sons, standards of performance were not
proposed for SO2 and CO emissions.
It is possible that SO2 control technol-
ogy used in other industries might be ap-
plicable to aluminum plants, and recent
information indicates that CO emissio
from such plants may be significant.
present, however, EPA has insufflcie
data on which to base SO2 and CO emis-
sion standards for aluminum plants. EPA
will consider the factors mentioned
above and other relevant information in
assigning priorities for future standard
setting and invites submission of perti-
nent information by any interested
parties. Thus, standards for CO and SO,
emissions from primary aluminum plants
may be set in the future.
(5) Reference Methods 13A and 13B.
These methods prescribe sampling and
analysis procedures for fluoride emis-
sions and are applicable to the testing
of phosphate fertilizer plants in addi-
tion to primary aluminum plants. The
methods were originally proposed with
the primary aluminum regulations but
have been promulgated with the stand-
ards of performance for the phosphate
fertilizer industry (published August 6,
1975, 40 FR 33152) because the fertilizer
regulations were promulgated before
those for primary aluminum. Comments
on the methods were received from both
industries and mainly concerned pos-
sible changes in procedures and equip-
ment specifications. As discussed in the
preamble to the phosphate fertilizer reg-
ulations, some minor changes were made
as a result of these comments.
Some commentators expressed a desire
to replace Methods 13A and 13B with
totally different methods of analysis.
They felt that they should not be re-
stricted to using only those methods pub-/
lished by the Agency. In response to th
;ni
it
FEDERAL REGISTER, VOL. 41, NO. 17—MONDAY, JANUARY 26, 1976
V-134
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3828
RULES AND REGULATIONS
comments, an equivalent or alternative
ethod may be used if approved by the
'Administrator under 40 CFR 60.8(b) as
revised on March 8, 1974 (39 FR 9308).
'6> Reference Method 14. Reference
Method 14 specifies sampling equipment
and sampling procedures for measuring
fluoride emissions from roof monitors.
Most comments concerning this method
suggested changes in the prescribed
manifold system. A number of com-
mentators objected to the requirement
that stainless steel be used as the struc-
tural material for the manifold and sug-
gested that other, less expensive struc-
tural materials would work as well. Data
submitted by one aluminum manufac-
turer supported the use of aluminum for
manifold construction. The Agency re-
viewed these data and concluded that an
aluminum manifold will provide satisfac-
tory fluoride samples if the manifold is
conditioned prior to testing by passing
fluoride-laden air through the system.
By using aluminum instead of stainless
steel, the cost of installing a sampling
manifold would be substantially reduced.
Since the Agency had no data on other
possible structural materials, it was not
possible to endorse their use in the meth-
od. However, the following wording ad-
dressing this subject has been added to
the method text (§2.2.1): "Other ma-
terials of construction may be used if it
is demonstrated through comparative
testing that there is no loss of fluorides
in the system."
Some commentators also objected to
the requirement that the mean velocity
easured during fluoride sampling be
ithin ±10 percent of the previous 24-
hour average velocity recorded through
the system. In order to reduce the num-
ber of rejected, sampling runs due to
failure to meet the above criteria, the
requirement has been amended such that
the mean sampling velocity must be
within ±20 percent of the previous 24-
hour average velocity. EPA believes that
the relaxation of this requirement will
not compromise the accuracy of the
method.
(7) Economic Impact. Some comments
raised questions regarding the economic
impact of the proposed regulations. The
Agency has considered these comments
and responded to them in the comment
summary cited above. As indicated pre-
viously, an analysis of the inflationary
and energy impacts of the standards ap-
pears in Volume 3 of the background
document. Copies of these documents
may be obtained as indicated previously.
Effective date. In accordance with sec-
tion 111 of the Act, these regulations are
effective January 26, 1976 and apply to
sources the construction or modification
of which commenced after proposal of
the standards; i.e., after October 23,
1974.
(It Is hereby certified that the economic and
Inflationary Impacts of this regulation have
been carefully evaluated In accordance with
Executive Order 11821)
Dated: January 19,1976.
RUSSELL E. TRAIN,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations, is amended
as follows:
1. The table of sections is amended by
adding a list of sections for Subpart S
and by adding Reference Method 14 to
the list of reference methods in Appen-
dix A as follows:
Subpart S—Standards of Performance for
Primary Aluminum Reduction Plants
Sec.
60.100 Applicability and designation of af-
fected facility.
60.191 Definitions.
60.192 Standard for ituorldes.
60.193 Standard for visible emissions.
60.194 Monitoring of operations.
60.195 Test methods and procedures.
* • * * •
APPENDIX A—REFERENCE METHODS
*****
METHOD 14—DETERMINATION OF FLUORIDE
EMISSIONS FROM POTROOM ROOF MONI-
TORS OF PRIMARY ALUMINUM PLANTS
AUTHORITY: Sees. Ill and 114, Clean Air
Act, as amended by sec. 4(a), Pub. L. 91-604,
84 Stat. 1678, 42 U.S.C. 1857 C-6, C-9.
2. Part 60 is amended by adding sub-
part S as follows:
Subpart S—Standards of Performance for
Primary Aluminum Reduction Plants
§ 60.190 Applicability and designation
of affected facility.
The affected facilities in primary alu-
minum reduction plants to which this
subpart applies are potroom groups and
anode bake plants. . ,
§60.191 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) "Primary aluminum reduction
plant" means any facility manufacturing
aluminum by electrolytic reduction.
(b) "Anode bake plant" means a facil-
ity which produces carbon anodes for use
in a primary aluminum reduction plant.
(c) "Potroom" means a building unit
which houses a group of electrolytic cells
in which aluminum is produced.
(d) "Potroom group" means an uncon-
trolled potroom, a potroom which is
controlled individually, or a group of
potrooms ducted to the same control
system.
(e) "Roof monitor" means that portion
of the roof of a potroom where gases not
captured at the cell exit from the
potroom.
(f) "Aluminum equivalent" means an
amount of aluminum which can be pro-
duced from a ton of anodes produced by
an anode bake plant as determined by
§60.195(e). .
(g) "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) ].
(h) "Primary control system" means
an air pollution control system designed
to remove gaseous and particulate fluo-
rides from exhaust gases which are cap-
tured at the cell.
(i) "Secondary control system" means
an air pollution control system designed
to remove gaseous and particulate fluo-
rides from gases which escape capture by
the primary control system.
§ 60.192 Standard for fluorides.
(a) On and after the date on which
the performance test required to be con-
ducted by 5 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 total
fluorides in excess of:
(1) 1 kg/metric ton (2 Ib/ton) of
aluminum produced for vertical stud
Soderberg and horizontal stud Soderberg
plants;
(2) 0.95 kg/metric ton (1.9 Ib/ton) of
aluminum produced for potroom groups
at prebake plants; and
(3) 0.05 kg/metric ton (0.1 Ib/ton) of
aluminum equivalent for anode bake
plants.
§ 60.193 Standard for visible emissions.
(a) On and after the date on which
' the performance test required to be con-
ducted 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.
§ 60.194 Monitoring of operations.
(a) The owner or operator of any af-
fected facility subject to the provisions
of this subpart shall install, calibrate,
maintain, and operate monitoring devices
v/hich can be used to determine daily
the weight of aluminum and anode pro-
duced. The weighing devices shall have
an accuracy of ±5 percent over their
operating range.
(b) The owner or operator of any af-
fected facility shall maintain a record of
daily production rates of aluminum and
anodes, raw material feed rates, and cell
or potline voltages.
§ 60.195 Test methods and procedures.
(a) Except as provided in §60.8(b),
reference methods specified in Appendix
A of this part shall be used to determine
compliance with the standards prescribed
in 8 60.192 as follows:
(1) For sampling emissions from
stacks:
(i) Method, 13A or 13B for the concen-
tration of total fluorides and the associ-
ated moisture content,
(ii) Method 1 for sample and velocity
traverses.
(iii) Method 2 for velocity and volu-
metric flow rate, and
(iv) Method 3 for gas analysis.
(2) For sampling emissions from roof
monitors not employing stacks or pol-
lutant collection systems:
(i) Method 14 for the concentration of
total fluorides and associated moisture
content.
FEDERAL REGISTER, VOL. 41, NO. 17—MONDAY, JANUARY M, 1976
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RULES AND REGULATIONS
3829
(ii) Method 1 for sample and velocity
traverses,
(ill) Method 2 and Method 14 for ve-
locity and volumetric flow rate, and
f iv) 'Method 3 for gas analysis.
(3) For sampling emissions from roof
monitors not employing stacks but
equipped with pollutant collection sys-
tems, the procedures under § 60.8(b)
shall be followed.
(b) For Method 13A or 13B, the sam-
pling time for each run shall be at least"
eight hours for any potroom sample and
at least four hours for any anode bake
plant sample, and the 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.
(c) The air pollution control system
for each affected facility shall be con-
structed so that volumetric flow rates and
total fluoride emissions can be accurately
determined using applicable methods
specified under paragraph (a) of this
section.
(d) The rate of aluminum production
shall be determined as follows:
(1) Determine the weight of alumi-
num in metric tons produced during a
period from the last tap before a run
starts until the first tap after the run
ends using a monitoring device which
meets the requirements of § 60.194(a).
(2) Divide the weight of aluminum
produced by the length of the period in
hours.
(e) For anode bake plants, the alumi-
num ' equivalent for anodes produced >
shall be determined as follows:
(1) Determine the average weight
(metric tons) of anode produced in the
anode bake plant during a representative
oven cycle using a monitoring device
.which meets the requirements of § 60.-
>194(a).
1 (2) Determine the average rate of
tanode production by dividing the total
weight of anodes produced during the
irepresentative oven cycle by the length
'of the cycle in hours.
I (3) Calculate the aluminum equiv-
alent 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
tons of aluminum produced and the con-
current tons of anode consumed by pot-
rooms.)
(f) For each run, potroom group
emissions expressed in kg/metric ton of
aluminum produced shall be determined
using the following equation:
£w
where:
M~
Ep»=potroom group emissions of total
fluorides In kg/metric ton of
aluminum produced.
C.=concentratlon of total fluorides
In mg/dscm' as determined by
Method 13A' or 13B or by
Method 14, as applicable.
Q.=volumetrlc flow rate of the efflu-
ent eas stream In dscm/hr as
determined by Method 2 and/or
Method 14, as applicable.
10-""converslon factor from mg to kg.
M=rate of aluminum production In
metric ton/hr as determined by
§ 60.195(d).
(C.Q.)7=product of C. and Q. for meas-
urements of primary control
system effluent gas streams.
(CtO.«)i=product °f c- and
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3830
RULES AND REGULATIONS
Locate the manifold along the length of
the roof monitor so that It lies nenr the
mldsectlon of the roof monitor. If the design
of a particular roof monitor makes this im-
possible, the manifold may be located else-
where along the roof monitor, but avoid
locating the manifold near the ends of the
roof monitor or in a section where the
aluminum reduction pot arrangement Is not
typical of the rest of the potroom. Center the
sample nozzles In the throat of the roof
monitor. (See -Figure 14-1.) Construct all
sample-exposed surfaces within the nozzles,
manifold and sample duct of 316 stainless
steel. Aluminum may be used if a new duct-
work system Is conditioned with fKioride-
laden roof monitor air for a period of six
weeks prior to Initial testing. Other materials
of construction may be used If it is demon-
strated through comparative testing that
there is no loss of fluorides In the system. All
connections In the ductwork shall be leak
free.
Locate two sample ports in a vertical sec-
tion of the duct between the roof monitor
and exhaust fan. The sample ports shall be at
least 10 duct diameters downstream and
two diameters upstream from any flow dis-
turbance such as a bend or contraction. The
two sample ports shall be situated 90° apart.
One of the sample ports shall be situated so
that the duct can be traversed In the plane
of the nearest upstream duct bend.
2.2.2 Exhaust /an. An industrial fan or
blower to be attached to the sample duct
at ground level. (See Figure 14-1.) This ex-
haust fan shall have a maximum capacity
such that a large enough volume of air can
be pulled through the ductwork to main-
tain an Isoklnetlc sampling rate in all the
sample nozzles for all flow rates normally en-
countered In the roof monitor.
The exhaust fan volumetric flow rate shall
be adjustable so that the roof monitor air
can be drawn isoklnetically into the sample
nozzles. This control of flow may be achieved
by a damper on the inlet to the exhauster or
by any other workable method.
2.3 Temperature measurement apparatus.
2.3.1 Thermocouple. Installed In the roof
monitor near the sample duct.
2.3.2 Signal transducer. Transducer to
change the thermocouple voltage output to
a temperature readout.
2.3.3 Thermocouple wire. To reach from
roof monitor to signal transducer and
recorder.
2.3.4 Sampling train. Use the train de-
scribed in Methods 13A and 13B—Determi-
nation of total fluoride.emissions from sta-
tionary sources.
3. Reagents.
3.1 Sampling and analysis. Use reagents
described In Method 13A or 13B—Determi-
nation of total fluoride emissions from sta-
tionary sources.
4. Calibration.
4.1 Propeller anemometer. Calibrate the
anemometers so that their electrical signal
output corresponds to the velocity or volu-
metric flow they are measuring. Calibrate
according to manufacturer's instructions.
4.2 Manifold intake nozzles. Adjust the ex-
haust fan to draw a volumetric flow rate
(refer to Equation 14-1) such that the en-
trance velocity Into each manifold nozzle
approximates the average effluent velocity In
the roof monitor. Measure the velocity of the
air entering each no7/le by inserting an S
type pilot tube into a 2.5 cm or less diameter
hole (see Figure 14 2) located in the mani-
fold between each blast gate (or valve) and
nozzle. The pilot tube tip shall be extended
into the center of the manifold. Take care
to Insure that ther? is no leakage around the •
pilot probe which could affect the indicated
velocity in the manifold leg. If the velocity
of air being drawn into each nozzle is not
the same, open or close each blast gate (or
valve) until the velocity In each nozzle is the
same. Fasten each blast gate (or valve) so
that It will remain In this position and close
the pilot port holes. This calibration shall be
performed when the manifold system is in-
stalled. (Note: It is recommended that this
calibration be repeated at least once a year.)
5. Procedure.
5.1 Roof monitor velocity determination.
5.1.1 Velocity value for setting isokinelic
flow. During the 24 hours preceding a test
run, determine the velocity Indicated by the
propeller anemometer in the section of roof
monitor containing the sampling manifold.
Velocity readings shall be taken every 15
minutes or at shorter equal time intervals.
Calculate the average velocity for the 24-hour
period.
5.1.2 Velocity determination during a test
run. During the actual test run, record the
velocity or volume readings of each propeller
anemometer In the roof monitor. Velocity
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 two
hours during the test run.
5.3 Sampling.
5.3.1 Preliminary air flow in duct. During
the 24 hours preceding the test, turn on the
exhaust fan and draw roof monitor air
through the manifold duct to condition the
ductwork. Adjust the fan to draw a volu-
metric flow through the duct such that the
velocity of gas entering the manifold nozzles
approximates the average velocity of the air
leaving the roof monitor.
5.3.2 Isokinetic sample rate adjustment.
Adjust the fan so that the volumetric flow
rate in the duct Is such that air enters into
the manifold sample nozzles at a velocity
equal to the 24-hour average velocity deter-
mined under 5.1.1. Equation 14-1 gives the
correct stream velocity which is needed in the
duct at the sample ports In order for sample
gas to be drawn Isokinetically Into the mani-
fold nozzles. Perform a pitot traverse of the
duct at the sample ports to determine if the
correct average velocity in the duct has been
achieved. Perform the pilot determination
according to Method 2. Make this determina-
tion before the start of a test run. The fan
setting need not be changed dxirlng the run.
8 (Da)- 1 minute
(bd)' 60 sec
where:
V
-------
28
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
IFRL 483-7]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to Washington
Local Agencies
Pursuant to section 111 (c) of the Clean
Air Act, as amended, the Regional Ad-
ministrator of Region X, Environmental
Protection Agency (EPA), delegated to
the State of Washington Department of
Ecology on February 28, 1975, the au-
thority to Implement and enforce the
program for standards of performance
for new stationary sources (NSPS). The
delegation was announced In the FED-
ERAL REGISTER on April 1, 1975 (40 FR
14632). On April 25, 1975 (40 FR 18169)
the Assistant Administrator for Air and
Waste Management promulgated a
change to 40 CFR 60.4, Address to re-
flect the delegation to the State of
Washington.
On September 30 and October 8 and 9,
1975, the State Department of Ecology
requested JSPA's concurrence In the
State's sub-delegation of the NSHS pro-
gram to four local air pollution control
agencies. After reviewing the State's re-
quest, the Regional Administrator de-
termined that the subdelegations meet
all the requirements outlined in EPA's
delegation of February 28, 1975. There-
fore, the Regional Administrator on De-
cember 5, 1975, concurred in the sub-
delegations to the four local agencies
listed below with the stipulation that all
the conditions placed on the original
delegation to the State shall also apply to
the sub-delegations to the local agencies.
EPA is today amending 40 CFR 60.4 to
reflect the State's sub-delegations.
The amended $ 60.4 provides that all
reports, requests, applications, submittals
and communications required pursuant
to Part 60 which were previously to be
sent to the Director of the State of Wash-
ington Department of Ecology (DOE)
will now be sent to the Puget Sound Air
Pollution Control Agency (PSAPCA), the
Northwest Air Pollution Authority (NW
APA), the Spokane County Air Pollution
Authority (SCAPA) or the Southwest Air
Pollution Control Authority (SAPCA) as
appropriate. The amended section Is set
forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective Im-
mediately in that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegations which are reflected by the
administrative amendment were effective
on September 30 to the NWAPA, October
7 to the PSAPCA and October 8 to the
SCAPA and the SAPCA, and it serves no
useful purpose to delay the technical
change of the addition of the local agency
addresses to the Code of Federal Regu-
lations. •
RULES AND REGULATIONS
This rulemaking is effective Immedi-
ately, and Is issued under the authority
of Section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Dated: January 24,1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 5 60.4, paragraph (b) is amended
by revising subparagraph (WW) to read
as follows:
§ 60. i Address.
• * * « »
(b) * * *
• (WW) (i) Washington; State of Washing-
ton, Department of Ecology, Olympia, Wash-
ington 98504.
(11) Northwest Air Pollution Authority, 207
Pioneer Building, Second and Pine Streets,
Mount Vernon, Washington 98273.
(Ill) Puget Sound Air Pollution Control
Agency, 410 West Harrison Street, Seattle,
Washington 98119.
(Iv) Spokane County Air Pollution Control
Authority, North 811 Jefferson, Spokane,
Washington 99201.
(v) Southwest Air Pollution Control Au-
thority, Suite 7601 H, NE Hazel Dell Avenue,
Vancouver, Washington 98665.
|FR Doc.76-2673 Piled l-28-76;8:45 am)
FEDERAL REGISTER. VOL 41, NO. 20-
-THURSDAY, JANUARY 29, 1976
29
Title 40—Protection of Environment
IFRL 492-3)
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Oregon
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of Oregon on November 10, 1975,
EPA is today amending 40 CFR 60.4,
Address, to reflect tills delegation. A No-
tice announcing this delegation is pub-
lished today at 41 FR 7750 in the
FEDERAL REGISTER. The amended § 60.4
which adds the address of the State of
Oregon Department of Environmental
Quality to which all reports, requests,
applications, submittals, and communi-
cations pursuant to this part must be
addressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
November 10, 1975 and it serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
Tliis rulemaking is effective immedi-
ately, and is issued under the authority
of Section ill of the Clean Air Act, as|
amended. 42 U.S.C. 1857c-6.
Dated: February 11,1976.
STANLEY W. LEGRO,
Assista?it Administrator for
Enforcement.
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 (MM) to read
as follows:
§ 60.4 Address.
* * « • •
(b) * * *
(A)-(LL) • • •
(MM)—State of Oregon. Department
of Environmental Quality, 1234 SW
Morrison Street, Portland, Oregon 97205.
|FB Doc.76-4964 Piled 2-19-76:8:46 amj
FEDERAL REGISTER, VOL. 41, NO. 35-
-FRIDAV, FEBRUARY 20, 1976
V-138
-------
RULES AND REGULATIONS
Title 40—Protection of EnvironmenJ
fFRL 494-3]
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
PART SO—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Primary Copper, Zinc, and Lead Smelters;
Correction
In FR Doc. 76-733 appearing at page
2331 in the FEDERAL REGISTER of January
15, 1976, the ninth line of paragraph (a)
In 8 60.165 is corrected to read as follows:
"total smelter charge and the weight."
Dated: February 20, 1976.
ROGER STRELON.
Assistant Administrator
lor Air and Waste Management.
|FR Doc.76-5398 Filed 2-25-76:8:45 am |
[FBL 495-4]
PART 60—STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Delegation of Authority to Commonwealth
of Virginia
Pursuant to the delegation of authority
for the standards of performance for
new stationary sources (NSPS) to the
Commonwealth of Virginia on December
30, 1975, EPA is today amending 40 CFR
60.4, Address, to reflect this delegation.
A Notice announcing this delegation is
published today at 41 FR 8416 in the
FEDERAL REGISTER. The amended § 60.4,
which adds the address of the Virginia
State Air Pollution Control Board 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 im-
mediately In that It is ap administrative
change and not one of .substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
December 30, 1975, and it serves no pur-
pose to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority of
section 111 of the Clean Air Act, en
amended. 42 U.S.C. 1857c-6.
42 U.S.C. 1857C-6.
Dated: February 21, 1976.
STANLEY W. LEUF.O.
Assistant Administrator
for Enforcement.
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 (W) to read
as follows:
§ 60.4 Address.
(A)-(UU) • ' °
(VV) Commonwealth of Virginia, Vir-
ginia State Air Pollution Control Board,
Room 1106, Ninth Street Office Building,
Richmond, Virginia 23219.
|FR Doc.76-5604 Filed 2-25-76:8:45 am)
FEDERAL REGISTER, VOL. 4), NO. 39-
-THURSDAY. FEBRUARY 26, 1976
SUBCHAPTER C—AIR PROGRAMS
[FBL 507-4]
PART SO—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of
Connecticut
Pursuant to the delegation of authority
for the standards of performance for new
stationary sources (NSPS) to the Stats
of Connecticut on December 9,1975, EPA
is today amending 40 CFR 60.4, Address,
to reflect this delegation. A Notice an-
nouncing this delegation is published to-
day at (41 FR 11874) in the FEDERAL REG-
ISTER. The amended § 00.4, which adds
the address of the Connecticut Depart-
ment of Environmental Protection 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 Imme-
diately in that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which Is reflected by this ad-
ministrative amendment was effective on
December 9. 1975. and it serves no pur-
pose to delay the technical change of this
addition to the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is Issued under the authority
of section ill of the Clean Ai? Act, sa
amended,
(43 UB.C. 1867C-6)
Dated: March 15.1976.
STANLEY W. LEGHO,
'Assistant Administrator
for Enforcement.
(H) State of Connecticut, Department
of Environmental Protection, State Of-
fice Building. Hartford, Connecticut
06115.
O 0 O o 0
[FR Doc.76-7967 Filed 3-19-76:8:46 amj
FEDIBAl REGISTER. VOL. 41, NO. 56-
-MONDAV, AflAQCW 28, J976
Title 40—Protection of Environment
CHAPTER (—ENVIRONMENTAL
PROTECTION AGENCY
| FBL 529-3)
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY. SOURCE
Delegation of Authority to State of
South Dakota
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of South Dakota on March 25,1976,.
EPA is today amending 40 CFR 60.4, Ad-
dress, to reflect this delegation. A Notice
announcing this delegation Is published
today at 41 FR 17600. The amended
§ 60.4, which adds the address of Depart-
ment of Environmental Protection 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 imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive "burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
March 25, 1976, and it serves no purpose
to delay the technical change of this ad-
dition of the State address to the Code of
Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
42 U.S.C. 18570-6.
Date: April 20, 1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In I 60.4 paragraph (b) is amended
by revising subparagraph QQ to read as-
follows:
Part 60 of Chapter I, Title 40 of the § 60.4 Address.
Code of Federal Regulations Is amended » o
as follows:
1. In § 30.4 paragraph (b) is amended
by revising subparagraph (H) to read as
follows:
Address.
(b)
(b),° « •
(A)-(Z) ooo
(AA)-(PP) ooo
(QQ) State of South Dakota, Depart-
ment of Environmental Protection, Joe
Foss Building, Pierre, South Dakota
57501.
FEDERAL REGISTER, VOL 41, NO. 02-
—TUESDAY< APRIL 27, 1976
V-139
-------
18498
33
TttlaAO—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
[PBL 509-3)
PART 60—STANDARDS O? PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Ferroalloy Production Facilities
On October 21, 1974 (39 FR 37470).
under section 111 of the Clean Air Act,
as amended, the Environmental Protec-
tion Agency (EPA) proposed standards of
'performance for new and modified fer-
roalloy production facilities. Interested
persons participated in the rulemaking
by submitting comments to EPA. The
comments have been carefully consid-
ered, and where determined by the Ad-
ministrator to be appropriate, changes
have been made to the regulations as
promulgated.
The standards limit emissions of par-
tlculate matter and carbon monoxide
from ferroalloy electric submerged arc
furnaces. The purpose of the standards is
to require effective capture and control
of emissions from the furnace and tap-
ping station by application of best sys-
tems of emission reduction. For ferro-
alloy furnaces the best system of emis-
sion reduction for partlculate matter is
a well-designed hood in combination
with a fabric filter collector or venturl
scrubber. For some alloys the best system
Is an electrostatic preclpitator preceded
by wet gas conditioning or a venturl
scrubber. The standard for carbon mon-
oxide requires only that the gas stream be
flared or combusted in some other
manner.
The environmental Impact of these
standards Is beneficial since the Increase
In emissions due to growth of the In-
dustry will be minimized. Also, the stand-
ards will remove the incentive for plants
to locate in areas with less stringent
regulations.
Upon evaluation of the costs asso-
ciated with the standards and their eco-
nomic Impact, EPA concluded that the
costs are reasonable and should not bar
entry into the market or expansion of
facilities. Tn addition, the standards will
require at most a minimal Increase in
power consumption over that required to
comply with the restrictions of most
State regulations.
SUMMARY OF REGULATION
The promulgated standards limit par-
tlcula-te matter and carbon monoxide
emissions from the electric submerged
arc furnace and. limit particulate matter
emissions from dust-handling equip-
ment. Emissions of partlculate matter
from the control device are limited to
less than 0.45 kg/MW-hr (0.99 Ib/MW-
hr) for furnaces producing high-silicon
alloys (in general) and to less than 0.23
kg/MW-hr (0.51 Ib/MW-hr) for fur-
naces producing chrome and manganese
alloys. For both product groups, emis-
sions from the control device must be
less than 15 percent opacity. The regu-
lation requires that the collection hoods
capture all emissions generated within
the furnace and capture all tapping emis-
sions for at least 30 percent of the tap-
RULES AND REGULATIONS
ping time. The concentration of carbon
monoxide In any gas stream discharged
to the atmosphere must be less than 20
volume percent. Emissions from dust-
handling equipment may not equal or ex-
ceed 10 percent opacity. Any owner or •
operator of a facility subject to this regu-
lation must continuously monitor volu-
metric flow rates through the collection
system and must continuously monitor
the opacity of emissions from the control
device.
SUMMARY OF COMMENTS
Eighteen comment -letters were re-
ceived on the proposed standards of per-
formance. Copies of the comment letters
and a report which contains a summary
of the issues and EPA's responses are
available for public inspection and copy-
ing at the U.S. Environmental Protec-
tion Agency, Public Information Refer-
ence Unit (EPA Library), Room 2922,
401 M Street, S.W., Washington, D.C.
Copies of the report also may be ob-
tained upon written request froui the'
EPA Public Information Center (PM-
215), 401 M Street, S.W., Washington,
D.C. 20460 (specify—Supplemental In-
formation on Standards of Performance
for Ferroalloy Production Facilities). In
addition to the summary of the Issues
and EPA's responses, the report contains
a revaluation of the opacity standard
in light of revisions to Reference Method
9 which were published in the FEDERAL
REGISTER November 12, 1974 (39 FR
39872).
The bases for the proposed standards
are presented in "Background Informa-
tion for Standards of Performance: Elec-
tric Submerged Arc Furnaces for Pro-
duction of Ferroalloys" (EPA 450/2-74-
018a, b). Copies of this document are
available on request from the Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, North Carolina
27711, Attention: Mr. Don R. Goodwin.
SIGNIFICANT COMMENTS AND CHANGES TO
THE PROPOSED REGULATION
Most of the comment letters contained
multiple comments. The more significant
comments and the differences between
the proposed and the final regulations
are discussed below. In addition to the
discussed changes, several paragraphs
were reworded and some sections were
reorganized.
(1) Mass standard. Several commen-
ters questioned the representativeness of the
data used to demonstrate the achlevabil-
Ity of the^a kg/MW-hr (0.51 Ib/MW-
hr) standard proposed for facilities pro-
ducing chrome and manganese alloys.
Specifically, the commenters were con-
cerned that sampling only a limited num-
ber of compartments or control devices
serving a furnace, nonisokinetic sam- .
pling of some facilities, and the proce-
dures used to determine the total gas
volume flow from open fabric filter col-
lectors would bias the data low. For these
reasons, the commenters argued that the
standard should be 0.45 kg/MW-hr (0.99 '.
Ib/MW-hr) for all alloys. As additional j
support for their position, they claimed
that control equipment vendors will not
guarantee that their equipment will
achieve 0.23 kg/MW-hr (0.51 Ib/MW-
hr). «
Because of these comments, EPA
thoroughly reevaluated the bases for the
two mass standards of performance and
concluded that the standards are achiev-
able by best systems of emission reduc-
tion. For open ferroalloy electric sub-
merged arc furnaces, the best system of
emission reduction is a well-designed
canopy hood that minimizes the volume
of Induced rir and a well-designed and
properly operated fabric filter collector
or high-energy venturi scrubber. In a
few cases, an electrostatic precipitator
preceded by a venturi scrubber or wet
gas conditioning is a b3st system. In
EPA's opinion, revising the standard up-
ward to 0.45 kg/MW-hr (0.99 Ib/MW-hr)
would allow instPll'ticn of systems other
than the best. Therefore, the promul-
gated standard- of performance for fur-
naces producing chrome and manganese
alloys is 0.23 kg/MW-hr (0.51 Ib/MW-
hr). The standard for furnaces produc-
ing-the specified high-silicon alloys is
0.45 kg/MW-hr CV99 Ib/MW-hr). The
rationale for establishing the standards
at these levels is summarized below.
Ths revaluation of the data bases for
the standards showed that the emission
test procedures u.'ed did not significantly
bias the results. Therefore, contrary to
the commenter's concerns, the proce-
dures did not result in emission limita-
tions lower than those achievable by best
systems of emls-Ion reduction. The de-
viations and assumptions made in the
test procedures w?re fcased on considera-
tion of the particle size of the emissions,
an evaluation of the rerformance of the
control systems, and factors affecting the
induction of air into open fabric filter
collectors.
EPA tests, and allows testing of, a rep-
resentative number of stacks or compart-
ments in a control device because sub-
sections of a well-designed and properly
operating control device will perform
equivalently. Evaluation of the control
system and the condition of the control
device by EPA engineers at the time of
the emission test showed that sections
not tested were of equivalent design and
in operating condition equivalent to or
better than the tested sections. Thus, the
performance of the non-tested portions
of the control device are considered to be
equivalent to or better th"n the per-
formance of the sections emission tested.
In addition, the particle size of emissions
from well-controlled ferroalloy furnaces
was investigated bv EPA and was found
to consist of parti-les of less than two
micrometers aerodynamic diameter for
all alloys. The mass and, hence, inertia
of these particles are negligible; there-
fore, they follow the motion of the gas
stream. For emissions of this size distri-
bution, concentrations determined by
nonisokinetic sampling would not be sig-
nificantly different than those measured
by isokinetic sampling.
EPA determined the total gas volume
flow rate from the open fabric filter col-
lectors by measuring the inlet volume
flow rate and the volume of air Induced
into the collector. The inlet gas volumes
FEDERAL REGISTER, VOL. 41, NO. 87—TUESDAY, MAY 4, 1976
V-140
-------
BOLES AND I3E6UCATTONS
to the collectors were measured during
each run of each test; but the volume
of air Induced Into the collector was de-
termined once during the emission test.
The total gas volume flow from the col-
lector was calculated as the sum of the
inlet gas volume and the induced air vol-
ume. Although the procedures used were
not ideal, the reported gas volumes are
considered to be reasonably representa-
tive of the total gas volumes from the
facility. This conclusion is based on the
fact that the quantity of air induced
around the bags in an open collector is
primarily dependent on the open area
and the temperature of the inlet gas
stream and the ambient air. Therefore,
equivalent air volumes are drawn into the
collector under similar meteorological
and Inlet gas conditions. During the pe-
riods of emission testing at the facilities.
meteorologies! conditions were uniform
and the volume of Induced air was ex-
pected to be constant. Consequently,
measurement of the induced air volume
once during the emission test was ex-
pected to be sufficient for calculating the
total gas volume flow from the collector.
Since conducting the test in question,
EPA has gained fdditional experience
and has concluded that in general it is
preferable to measure the total gas vol-
ume flow during each run of a perform-
anco test. This conclusion, however,
does not invalidate the use of the test
data obtained by the less optimum pro-
cedure of a single .determination of in-
duced air volume. EPA evaluated pos-
sibje variations in the amount of air in-
duced into the collector by performing
enthalpy balances using reported tem-
perature data. The Induced air volumes
were calculated assuming adiabatic mix-.
Ing (no heat transfer by inlet gases to
collector) and, hence, are conservatively
high' estimates. The calculated induced
air volumes did differ from the single
measured values; however, the effect on
the mass emission rate for the collectors
was not significant. EPA. therefore, con-
cluded that the use of single measure-
ments of the induced air volume did not
affect the level of the standards.
Another issue of concern to com-
menters is the reluctance of control
equipment vendors to guarantee reduc-
tion of emissions to less than 0.23 kg/
MW-hr. (0.51 Ib/MW-hr). It is EPA's
opinion- that this reluctance does not
demonstrate the unachievability of the
standard. The vendors' reluctance to
guarantee this level is not surprising con-
sidering the variables which are beyond
their control. Specific?lly, they rarely
have any control over the design of the
fume collection systems for the furnace
and tapping station. Fabric filter collec-
tors tend to control the concentration of
particiulate matter in the effluent The
mass rate of emissions from the collec-
tor Is determined by the total volumetric
flow rate from the control device, which
Is not determined by vendors. Further,
because of limited experience with emis-
0ion testing to evaluate the performance
of open fabric filter collectors, vendors
cannofc effectlvelr evaluate the perform-
ance of these systems over the guarantee
period. For vendors, establishment of thq
performance guarantee level is also com-
plicated by the fact that the performance
0f the collector is contingent upon its
beins properly operated and maintained.
Standards of performance are neces-
sarily based on data from a limited
number of best-controlled facilities and
on engineering- Judgments regarding
performance of the control systems. For
this reason, there is a possibility of ar-
riving at different conclusions regarding
the performance capabilities of these
systems. Consequently, the question of
vendors' reluctance to guarantee their
equipment to achieve 0.23 kg/MW-hr
(0.51 Ib/MW-hr) was considered along
with the results of atiuitlonal resent
emission tests on fabric filter collectors.
Recognizing that the data base for the
standards was limited and that a num-
ber of well-controlled facilities had
started operation since completion of the
original study, EPA obtained additional
data to better evaluate the performance
of emission control systems of Interest.
Under the authority of section 114 of
the Clean Air Act, EPA requested copies
of all emission data for well-controlled
furnaces operated by 10 ferroalloy pro-
ducers. Data were received for five well-
controlled facilities. In general, the-e
facilities had close fitting water cooled
canopy hoods, and tapping fumes were
collected and sent to the control device
along with the furnace emissions.
The emission data submitted by the
Industry show that properly operating
compartments of open fabric filter col-
lectors have effluent concentrations of
less than 0.009 g/dscm (0.004 gr/dscf).
For these recently constructed facilities,
the reported mass emission rates were
less than 0.12 kg/MW-hr (0.24 Ib/Mw-
hr) for 15 MW capacity silicon metal
furnaces. Evaluation of possible errors
in the data and uncertainties in the test
procedures showed that-emissions may
have been as high as 0.20 kg/MW-hr
(0.45 Ib/MW-hr) In some cases. These
emission rates were achieved by desien
of the collection hood to minimize the
quantity of Induced air. The data sub-
mitted by the industry showed that gas
volumes from well-hooded large silicon
metal furnaces can be reduced to 50 per-
cent of the volumes from typically hood-
ed large silicon furnaces. Based on the
data obtained from the industry, a large
weU-hdoded and well-controlled silicon
metal furnace is expected to have an
emission rate of less than 0.45 kg/MW-
hr (0.99 Ib/MW-hr).
In EPA's study of the ferroalloy In-
dustry, it was determined that emissions
from production of high-siUjon alloys
would be more difficult to control than
chrome and manganese emissions due
to the finer size distribution of the par-
ticles and significantly larger gas vol-
umes from the furnace. Comparison of
the gas volumes reported by the Industry
from silicon metal production with gas
volumes from typically hooded furnaces
producing chrome and manganese alloys
-shows that the original conclusion Is
still valid. Due to the lower gas volumes
associated with their production, a lov-
er mass emission rate Is still expected for
chrome and manganese alloys. In addi-
tion, EPA emission tests in the original
study on a-number of tightly hooded
open furnaces demonstrated emissions
can be controlled to less than 0.23 kg/
MW-hr (0.51 Ib/MW-hr). Emissions
were reduced to these levels by control
of induced air volumes and by use of a
well-designed and properly operated
fabric filter collector or venturl scrub-
ber.
Just before promulgation of the
standard?, members of the Ferroalloy
Association informed EPA that future
supplier of chrome and manganese ores
T'll1 be finer and more friable than those
in use during development of the stand-
ard. The industry representatives.
claimed that use of finer ores will affect
furnace operations and prevent new fur-
naces from complying with the 0.23 kg/
MW-hr (0.51 Ib/MW-hr) standard. Al-
though the representatives submitted
statements concerning the effect of finer
ores on furnace operating conditions, no
data were provided to show the effect of
ore *i?e x>n emissions. EPA evaluated the
material submitted and concluded that
furnrce operating rrob'ems associated
with use of fine ores can be contro'led by
o^eratign and maintenance procedure-;.
With rroper operation of the furnace, ure
of finer ore^ rhou'd not affect the achfer-
ability of the standard, and relaxation
of the 0.23 kg/MW-hr (0.51 Ib/MW-hr)'
standard is not justified. This evaluation
is discussed in detail in Chapter II of the
supplements! information document. If
and when factual information is pre-
sented to EPA wh'ch clearly demon-
strates that use of finer chrome and
manganese ores floes prevent a property
operated new furnace, which Is equipped
with the best demonstrated system of
emission reduction (considering, costs),
from meeting the 0.23 kg/MW-hr (0.51
Ib/MW-hr) standard, EPA will propose a
revision to the standard. The best system
of e-nis^lon reduction (considering costs)
is considered to be a well-designed col-
lection hood in combination with a well-
designed fabric filter collector or high-'
energy venturi scrubber.
• The emission data obtained by EPA
and the data provided by the industry
show that the standards of performance
for both product groups are achievable
and the required control system clearly
is adequately demonstrated. The ques-
tion of the achievabllity of and the va-
lidity of the data basis for both the 0.23:
kg/MW-hr (0.51 Ib/MW-hr) and 0.45
kg/MW-hr (0.99 Ib/MW-hr) standards
Is discussed In more detail in Chapter II
of the supplemental information docu-
ment.
(2) Control device opacity standard.
On November 12. 1974 (39 FR 39872).
after proposal of the standards for fer-
roalloy facilities. Method 9 was revised to
require that compliance with opacity
standards be determined by averaging
sets of 24 consecutive observations taken
at 15-second Intervals (sis-minute av-
erages). The proposed opacity standard
which limited emissions from the confer®!
FEDERAl REGISTER, VOL 41. NO. 87—TUTiSDAY, MAY 4, 1976
V-141
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18500
RULES AND REGULATIONS
device to less than 20 percent has been
revised In the regulation promulgated
herein to require that emissions be less
than 15 percent opacity In order to retain
the Intended level of control.
(3) Control system capture require-
ments. Ten commenters criticized fume
capture requirements for the furnace and
tapping station control systems on two
.basic points. The arguments were: (1)
EPA lacks the statutory authority .to
(regulate emissions within the building,
'and (2) the standards are not technical-
ly feasible at all times.
EPA has the statutory authority un-
der section 111 of the Act to regulate any
•new stationary source which "emits or
may emit any air pollutant." EPA does
not agre-i with the opinion of the com-
menters that section 111 of the .Act ex-
pressly or implicitly limits the Agency to
regulation only of pollutants which are
emitted directly into the atmosphere.
Partlculate matter emissions escaping
capture by the furnace control ey-tern
'ultimately will be discharged to the at-
mosphere outside of the shop; therefore,
they may be regulated under section 111
of the Act. Standards which regulate
pollutants at the point of emission' inside
;the building allow assessment.of the con-
trol system without interference from
-nonregulated sources located in the same
.building. In addition, by requiring evalu-
ation of emissions before their dilution,
the standards will resuU in better con-
trol of the furnace emissions and will
regulate affected ferroalloy fac'Ut'ps
more uniformly than would standards
limiting emissions from the shop.
' EPA believes the standards on the fur-
nace and tapping station collection
hoods are achievable because the stand-
ards are based on observations of normal
operations at well-controlled facilities.
The commenters who argued that the
standards are not technically feasible at
all times cited examples of abnormal op-
erations which would preclude achiev-
ing the standards. For example, several
commenters cited the fact that violent
reactions due to im'ia'ances in the alloy
chemistry occasionally can generate more
emissions than the hood was designed to
capture. If the capture system Is well-
designed, well-maintained, and properly
operated, only failures of the process to
operate in the normal or usual manner
would cause the capacity of the system to
'be exceeded. Such operating perio-ls are
malfunctions, and, therefore, compliance
with the standards of performance
would not be determined during these
periods. Performance tests under 40 CFR
60.8(c) are conducted only during rep-
resentative conditions, and periods of
start-up, shutdown, and malfunctions
are not considered representative condi-
tions.
Five commenters discussed other op-
erating conditions which they believed
would preclude a source from complying
with the tapping station standard. These
conditions Included blowing taps, period
of poling the tarhole, and periods of re-
moval of metal and slag from the spout.
The commenters argued that blowing
taps should be exempted from the stand-
ard and the tapping station standard
should be replaced with an opacity
standard or emissions from the shop. The
comments v.erc revi:wed and EPA con-
cluded that exemption of blowing taps is
justified. The regulation promulgated
herein exempts blowing taps from the
tcpr.lng station standard and includes.a
definition of blowing tap. EPA believes
that conditions which result in plugging
of the ta"hol: and metal in the spout are
malfunctions because they are unavoid-
able failures of the process to operate
in the normal or usual manner. Discus-
sions with experts in the ferroalloy In-
dustry, revealed that these conditions are
not predictable conditions for which a
preventative maintenance or operation
program could be established. As mal-
functions, th-F- periods are not subject
to the standards, and a performance test
would not be conducted during such
periDds. Therefore, the suggested revision
to the standard to exempt these periods
is not necessary because of the existing
provisions of 40 CFR 60.8(c) and 60.11.
In EPA's judgment, both the furnace and
tapping station standards are achievable
for all normal process operations at fa-
cilities with well-designed, weU-main-
taincc'. a"d ^ro^erly operated emission
collection systems.
The promulgated regulation retains
the proposed fume capture requirements,
but the regulation has been revised to
be more enforceable than the proposed
capture requirements, which could have
been enforced only on an infrequent
basis. The regulation has been reorga-
nized to clarify that unlike the opacity
standards, the collection system capture
requirements (visible emission limita-
tions) are subject to demonstration of
compliance during the performance test.
To provide a means for routine enforce-
ment of the capture requirements, con-
tinuous monitoring of the volumetric
flow rate(s) through the collection sys-
tem is required for each affected fur-
nace. An owner or operator may comply
with this requirement either by install-
ing a flow rate monitoring device in an
appropriate location in the exhaust duct
or by calculating the flow rate through
the system from fan operating data. Dur-
ing the performance test, the baseline
operating flow rate(s) will be established
for the affected electric submerged arc
furnace. The regulation establishes emis-
sion capture standards which are appli-
cable only during the performance test
of the affected facility. At all other times,
. the operating volumetric flow rate(s)
shall be maintained at or greater than
the established baseline values for the
furnace load. Use of lower volumetric
flow rates than the established values
constitutes unacceptable operation and
maintenance .of the affected facility.
These provisions of the promulgated
regulation will ensure continuous mon-
itoring of the operations of the emission
capture system and will simplify enforce-
ment of the emission capture require-
ments.
The requirements for monitoring volu-
metric flow rates will add negligible ad-
ditional costs to the total costs of
complying with the standards of per-
formance. Flow rate monitoring devices
of sufficient accuracy to meet the re-
quirements of 5 60.265(c) can be installed
for $600-$4000 depending on the flow
profile of the area being monitored and
the complexity of the monitoring device.
A suitable strip chart recorder can be
Installed for less than $600. The alter-
native provisions allowing calculation of
the volumetric flow rate(s) through the
control system from continuous monitor-
Ing of fan operations will result in no
additional costs because the Industry
presently monitors fan operations.
(4) Monitoring of operations. The
promulgated regulation requires report-
ing to the Administrator any product
changes that wi'l result in a change in
the applicable standard of performance
for the affected electric submerged arc
furnace. This requirement Is necessary
because electric submerged arc furnaces
may be converted to production of alloys
other than the original design alloys by
physical alterations to the furnace,
changes to the electrode spacing,
changes in the transformer capacity, and
changes in the materials charged to the •
furnace. Thus, the emission rate from
the electric submerged arc furnace and
the standard of performance (which is
dependent on the alloy produced) may
change during the lifetime of the facil-
ity. Conversion of the furnace to pro-
duction of alloys with significantly dif-
ferent emission rates, such as changes
between the product grouns for the two
standards, may result in the facility ex-
ceeding the applicable standard. Conse-
quently, the reporting requirement was
added to ensure continued compliance
with the applicable standards of per-
formance. These re-orts of product
changes will afford the Administrator an
opportunity to determine whether a per-
formance test should be conducted and
will simplify enforcement of the regu-
lation. As with the requirements appli-
cable under the proposed regulation, the
performance test still must be conducted
while the electric submersed arc furnace
is producing the design alloy whose'emis-
sions are the most difficult to control of
the product family. Subsequent product
changes within the product family will
not cause the facility to exceed the stand-
ard.
(5) Test methods and procedures. Sec-
tion 60.266(d) of the promulgated regu-
lation requires the owner or operator to
design and construct the control device
to allow measurement of emissions and
flow rates using applicable test methods
and procedures. This provision permits
the use of open pressurized fabric filter
collectors (and other control devices)
whose emissions cannot be measured by
reference methods currently in Appendix
A to this part, if. compliance with the
promulgated standard can be demon-
strated by an alternative procedure. EPA
has not specified a single test procedure
for emission testing of open pressurized
fabric filter collectors because of the
large variations in the design of these
collectors. Test procedures can be de-
veloped on a case-by-case basis, however.
Provisions in 40 CFR 60.8 (b) allow the
owner or operator upon approval by the
Administrator to use an "alternative" or
FEDERAL REGISTER, VOL. 41, NO. 87—TUESDAY, MAY 4, 1976
V-142
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RULES AMD • REGULATIONS
18501
"equivalent" test procedure to show com-
pliance with the. standards. EPA would
like to emphasize that development of
.the "alternative" or "equivalent" test
procedure is the responsibility of any
owner or operator who elects to use a
control device not amenable to testing by
Method 5 of Appendix A to this part. The
procedures of. an "alternative" test
method for demonstration of compliance
are dependent on specific design features
and condition of the collector and the
capabilities of the sampling equipment.
Consequently, procedures acceptable for
demonstration of compliance will vary
with specific situations. General guid-
ance on possible approaches to sampling
of emissions from pressurized fabric filter
collectors is provided in Chapter IV of
the supplemental information document.
Due to the costs of testing, the owner
or operator should obtain EPA approval
for a specific test procedure or othe'r
means for determining compliance be-
fore construction of a new source. Under
the provisions of ? 60 6, the owner or
operator of a new facility may request
review of the acceptability of proposed
plans for construction and testing of con-
trol systems which are not amenable to
sampling by Reference Method 5. If an
acceptable "alternative" test procedure is
not developed by the owner or operator,
then total enclosure of the pressurized
fabric filter collector and testing by
Method 5 is reo.uired.
Effective date. In accordance with sec-
tion 111 of the Act, these regulations
prescribing standards of performance for
ferroalloy production facilities are effec-
tive May 4, 1976, and apply to electric
submerged arc furnaces and their asso-
ciated dust-handling equipment, the
construction or modilcation of which
was commenced after October 21, 1974.
(Sees. Ill and 114 of the Clean Air Act,
amended by Sec. 4(a) of Pub. L. 91-604, 84
Btat. 1678 (42 U.S.C. 1857C-6, 1867C-9).)
Dated: April 23,1976.
RUSSELL E. TRAIN,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. The table of sections is amended by
adding subpart Z as follows:
Subpart Z—Standards of Performance) for Ferro-
alloy Product.on Facll.tieo
Sec.
80.260- Applicability and designation of
affected facility.
80.361 Definitions.
80.282 Standard for participate matter.
60.263 Standard for carbon monoxide,
60.264 Emission monitoring.
60.285 Monitoring of operations.
60.266 Test methods and procedures.
2. Part 60 Is amended by adding sub-
part Z as follows:
Subpart 2—Standards of Performance for
Ferroalloy Pro .faction
§ 60.260 Applicability and ilcsignnlion
of affected facility.
The provisions of this subpart are ap-
plicable to the following affected facili-
ties: Electric submerged arc furnaces
which produce silicon metal, ferrosillcon.
calcium silicon, silicomanganese zirco-
nium, ferrochrome silicon, silvery iron,
. hich-carbon ferrochrome, charge chrome
standard ferromanganese, sllimanga-
. nese, ferrcmanganese silicon, or calcium
carbide; and dust-handling cquipmsnt.
§60.261 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) "Electric submerged arc furnace"
means any furnace wherein electrical
energy is converted to heat energy by
transmission of current between elec-
trodes partially subm:rged in the furnace
charge.
(b) "Furnace charge" me?ns any ma-
terial introduced into the electric.sub-
merged arc furnace and may consist of,
but is not limited to, orss, slag, carbo-
naceous mateilal, and limestone.
(c) "Product change" means any
change in the composition of the furnace
charge that would cause the electric sub-
merged arc furnace to tecorr.e subject
to a different mass standard applicable
under this subpart.
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18502
RULES AND REGULATIONS
(5) Escape- the capture system at the
tapping station and are visible without
the aid of Instruments for more than 40
percent of each tapping period. There are
no limitations on visible emissions under
this subnaragraph when a blowing tap
occurs. The requirements under this sub-
paragraph apply only during periods
when Sow rates are being established
under 5 60.265 (d).
(b> On and after the date on which
the performance test required to be con-
ducted by 9 60.8 Is completed, no owner
or .operator subject to the provisions of
thh subpart shall cause to be discharged
into the atmosphere from any dust-han-
dling equipment any gases which exhibit
10 percent opacity or greater.
§ 60.263 Standard for carbon monoxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 Is completed, no owner
or operator sub.lect to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any electric
submerged arc furnace any gases which
contain, on a dry basis, 20 or greater
volume percent of carbon monoxide.
Combustion of such gases under condi-
tions acceptable to the Administrator
constitutes compliance with this section.
Acceptable conditions Include, but are
not limited to, flaring of gases or use of
gases as fuel for other processes.
§ 60.264 Envssion monitoring.
fa> The owner or operator subject to
the provisions of this subpart shall In-
stall, calibrate, maintain and operate a
continuous monitoring system for meas-
urement of the opacity of emissions dis-
charged Into the atmosphere from the
control device(s).
(b) For the purpose of .reports re-
quired under § 60.7(c), the owner or op-
erator shall report as excess emissions
all six-minute periods "in which the av-
erage onacity is 15 percent or greatir.
(c) The owner or operator subject to
the provisions of this subnart shall sub-
mit a written report of any product
change to the Administrator. Reports of
product changes must be postmarked
not later than 30 days after Implemen-
tation of the product change.
$ 60.265 Monitoring of operations.
-• tai .The owner or operator of any elec-
tric submerged arc furnace subject to the
provisions of this subpart shall main-
tain daily records of the following in-
formation:
(1> Product befog;'produced.
(21 Description of constituents of fur-
nace charge. Including, the quantity, by
weight.
(31 Time and duration of each tap-
ping period and the Identification of ma-
terial tapped (slag or product.)
(4) All furnace power input data ob-
tained under paragraph (b) of this sec-
tion,
f5) AS flow- rate data obtained under
paragraph (c) of this section or all fan
motor power consumption and pressure
drop data obtained under paragraph (e)
of this section.
(b) The owner or operator subject to
the provisions of this subpart shall In-
stall, calibrate, maintain, and operate a
device to measure and continuously re-
cord the furnace power input. The fur-
nace power input may be measured at the
output or input side of the transformer.
The device must have an accuracy of ±5
percent over its operating range.
(c) The owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, and maintain a monitor-
ing device that continuously measures
and records the volumetric flow rate
through each separately ducted hood of
the capture system, except as p'-wided
under paragraph (e) of this section. The
owner or operator of an electric sub-
merged arc furnace th?t is equipped with
a water cooled cover which is designed
to contain and prevent escape of the
generated gas and particulate matter
shall monitor only the volumetric flow
rate through the capture system for con-
trol of emissions from the tapping sta-
tion. The owner or operator may install
the monitoring device(s) in any appro-
priate location in the exhaust duct such
that reproducible flow rate monitoring
will result. The flow rate monitoring de-
vice must have an accuracy of ±10 per-
cent over its normal operating range and
must be calibrated According to the
manufacturer's instructions. The Ad-
ministrator may require the owner or
operator to demonstrate the accuracy of
the monitoring device relative to Meth-
ods 1 and 2 of Anpendix A tc this part.
(d) When performance tests are con-
ducted under the provisions of § 60.8 of
this part to demonstrate compliance
with the standards under §§60.262(a)
(4) and (5). the volumetric flow rate
through each separately ducted hood of
the capture system must be determined
using the monitoring device required
under paragraph (c) of this section. The
volumetric flow rates must be determined
for furnace power input levels at 50 and
100 percent of the nominal rated capacity
of the electric submerged arc furnace.
At all times the electric submerged arc
furnace is operated, the owner or oper-
ator shall maintain the volumetric flow
rate at or above the appropriate levels
for that furnace power input level de-
termined during the most recent per-
formance test If emissions due to tap-'
ping are captured and ducted separately
from emissions of the electric submerged
arc furnace, during each tapping period
the owner or operator shall maintain
the exhaust flow rates through the cap-
ture system over the tapping station at
or above the levels established during
the most recent performance test. Oper-
ation at lower flow rates may be consid-
ered by the Administrator to be unac-
ceptable operation and maintenance of
the affected facility. The owner or oper-
ator may request that these flow rates be
reestablished by conducting new per-
formance tests under § 60.8 of this part.
(e) The owner or operator may as an
alternative to paragraph (c) of this sec-
tion determine the volumetric flow rate
through each fan of the capture system
from the fan power consumption, pres-
sure drop across the'fan and the fan per-
formance curve. Only data specific to the
operation of the affected electric sub-
merged arc furnace are acceptable for
demonstration of compliance with the
requirements of this paragraph. The
owner or operator shall maintain on file
a permanent record of the fan per-
formance curve 'prepared for a specific
temnerature) and shall:
(1) Install, c° librate, maintain* and
operate a device to continuously measure
and record the power consumption of the
fan motor fme^siTed in kilowatts), and
(2) Install, calibrate, maintain, and
operate a device to continuously meas-
ure ?nd re-ord the pressure dron across
the fan. The fan rower consumption and
pressure dron measurements must be
synchronised to allo-v real time compar-
isons of the data. The monitoring de-
vices must h»ve an accuracv of ±5 per-
cent over the'r normal operating ranges.
(f) The vol'imetric flow rate through
each ff>n of the capture system must be
determined from the fan power con-
sumntion, fan pressure drop, and fan
performance curve sneciPed under para-
pra^h (e) of thi.i section, during anv per-
formance test required under § 60.8 of
this p?rt to demonstrate comnlipnce with
the standards under §§ 60.262(a) (4) and
<5). The o«'ner or orerator shall deter-
mine the volumetric flow rate at a repre-
sentative temnerature for furnace power
.input leve's of 50 and 100 percent of the
nominal rated capacity of the electric
submersed arc furnace. At all times the
e'ectric submerged arc furnace is op-
erated, the owner or operator shall main-
tain the fan power consumntion and fan
pressure dror> at leve's such that the vol-
umetric flow rate is at or above the levels
established during the most recent per-
formnnce te?t for that furnace power in-
put level. If emissions due to tapping are
captured and ducted separately from
emissions of the electric submerged arc
furnace, during each tapping period the
owner or operator shall maintain the fan
power consumption and fan pressure
drop at levels such that the volumetric
flow rate is at or above the levels estab-
lished during the most recent perform-
ance test. Operation at lower flow rates
may be considered bv the Administrator
to be unacceptable operation and main-
tenance of the affected facility. The own-
er or operator may request th
-------
(1) Method 5 for the concentration of
participate matter and the associated
moisture content except that the heating
systems specified in paragraphs 2.1.2 and
2.1.4 of Method 5 are not to be used when
the carbon monoxide content of the gas
stream exceeds 10 percent by volume,
' dry basis.
(2) Method 1 for sample and velocity
traverses.
(3) Method 2 for velocity and volumet-
ric flow rate.
(4) Method 3 for gas analysis, Includ-
ing carbon monoxide.
(b) For Method 5, the sampling time
for each run Is to Include an integral
number of furnace cycles. The sampling
time for each run must be at leist 60
minutes and the minimum sample vol-
ume must be 1.8 dscm (64 dscf) when
sampling emissions from open electric
submerged arc furnaces with wet scrub-
ber control devices, sealed electric sub-
merged arc furnaces, or semi-enclosed
electric submerged arc furnaces. When
sampling emissions from other types of
Installations, the sampling time for each
run must be at least 200 minutes and the
minimum sample volume must be 5.7
dscm (200 dscf). Shorter sampling times
or smaller sampling volumes, when ne-
cessitated by process variables or other
factors, may be approved by the Admin-
istrator.
(c) During the performance test, the
owner or operator shall record the maxi-
mum open hood area (In hoods with
segmented or otherwise irioveable sides)
under which the process Is expected to
be operated and remain in compliance
with all standards. Any future operation
of the hooding system with open areas in
excess of the maximum Is not permitted.
(d) The owner or operator shall con-
struct the control device so that volu-
metric flow rates and particulate matter
emissions can be accurately determined
by applicable test methods and proce-
dures.
(e) During any performance' test re-
quired under § 60.8 of this part, the
owner or operator shall not allow gaseous
diluents to be added to the effluent gas
stream after the fabric In an open pres-
surized fabric .filter collector unless the
total gas volume flow from the collector
Is accurately determined and considered
in the determination of emissions.
(f) When compliance with § 60.263 Is
to be attained by combusting the gas
stream In a Hare, the location of the
sampling site for particulate matter Is
to be upstream of the flare.
(g) For each run, particulate matter
emissions, expressed in kg/hr (Ib/hr),
must be determined for each exhaust
stream at which emissions are quantified
using the following equation:
where:
£»=Emissions of particulate naaiia? iffl
kg/hr (Ib/hr).
C. = Concentration of particulate EaoStez? In
kg/dscm (Ib/dscf) as determined b;
Method 6.
Q, = Volumetric flow rate of the effluont (jog
stream in dBcm/hr (dscf/hr) oo de-
termined by Method 2.
(h) For Method 5, particulate matter
emissions from the affected facility, ex-
pressed in frs/MW-hr (lb/MW-h?) musfe
be determined for each nut using the
following equation:
where:
S=Emissions of portlculato feoBm USso ef-
fected facility.' In Kc/MW-to (H>/
MW-hr).
W=Total number of exhaust streams at
which emissions are quantified.
E»=Emission of particulate matter from
V each exhaust stream In ftg/hr (lb/
hr), as determined In paragraph (g)
of this section.
p=Average furnace power Input during
the sampling period. In megawatts
as determined according to § 60.265
(b).
(Sees. Ill and 114 of the Clean Air Act, as
amended by seo.
-------
RULES AND REGULATIONS
This rulemaklng is effective immedi-
ately, and is Issued under the authority
of Section 111 of the Clean Air Act, as
amended.
42 UB.0.18670-6.
Da ted: May 3,1976.
STANLEY W. LEGRO,
Assistant Administrator
of Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In 8 60.4 paragraph (b) is amended
by revising subparagraph (EE) to read
as follows:
§ 60.4 Address.
* • • • •
(b) • • •
(EE) New Hampshire Air Pollution
Control Agency, .Department of Health
and Welfare. State Laboratory Building,
Razen Drive, Concord, New Hampshire
03301.
[FB Doc.76-13821 Filed 6-12-76;8:45 am]
FEDEtAL REGISTER, VOL. 41. NO. 94-
-THUXSDAY, MAY 13, 1976
35 1FRL 509-31
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Ferroalloy Production Facilities
Correction
In PR Doc. 76-12814 appearing at paga
18498 in the FEDERAL REGISTH of Tues-
day, May 4, 1976 the following correc-
tions should be made:
1. On page 18498, second column, last
paragraph designated "(1)", second line,
fourth word should read "representa-
tiveness".
2. On page 18501, first column, the sub-
part heading immediately preceding tha
text, should read "Subpart Z—Standard*
of Performance for Ferroalloy Produc-
tion Facilities".
3. On page 18501, m 2 60.260, second
column, fourth line from the top, tha
third word should read "sillcomanga-".
4. On page 18501, second column. In
g 60.261 (i>, second line, third word
should read "evolution".
ft. On page 18503. third column, ta
{ 60.266 (h> the equation should hare ap-
peared as follows:
36
|OPP—260019; FBI, 646-8)
FEDERAL REGISTER, VOL 41, NO. 99-
-TMU8SDAY, MAY 20, 1976
Title 40—Protection of Environment
[FRL 548-4)
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Ventura County and
Northern Sonoma County Air Pollution
Control Districts
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Ventura County Air Pollution Control
District and the Northern Sonoma
County Air Pollution Control District,
dated February 2, 1976, EPA is today
amending 40 CFR 60.4, Address, to re-
flect this delegation. A Notice announcing
this delegation is published today in
the Notice section of this issue. The
amended § 60.4 is set forth below. It adds
the addresses of the Ventura County and
Northern Sonoma County Air Pollution
Control Districts, to which must be ad-
dressed all reports, requests, applica-
tions, submittals, and communications
pursuant to this part by sources subject
to the NSPS located within these Air
Pollution Control Districts.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
Febraury 2, 1976, and it serves no pur-
poses to delay the technical change of
this addition of the Air Pollution Con-
trol District addresses to the Code of
Federal Regulations.
This rulemaking is effective imme-
diately.
(6ec. Ill of the Clean Air Act, as amended
[42 U.S.C. 1857C-6]).
Dated: May 3,1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.4 (b) is amended by
revising subparagraph F to read as fol-
lows:
8 60.4 Addreso.
(b) • • •
P California— -
Bay Area Air Pollution Control District,
939 Ellis St., San Francisco, CA 94109.
Del Norte County Air Pollution Control
District, Courthouse, Crescent City. CA 95531.
Bumboidt County Air Pollution Control
District. 5600 a Broadway, Eureka, CA 95501.
Kern County Air PoUutton Control District.
1700 Flower St. (P.O. Bos 997), Bakersfleld,
OA 99303.
Monterey Bay Unified Air Pollution Control
District, 420 Church St. (P.O. Box 487),
Salinas. CA 93901.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate'Hd.. Santa'
Rosa, CA 95404.
Trinity County Air Pollution Control Dis-
trict, Box AJ, Weaverville, CA 96093.
Ventura County Air Pollution Control Dis-
trict. 625 E. Santa Clara St., Ventura. CA
93001.
FEDERAL UGISTER, VOL 41. NO. 103-
-WEDNESDAY, MAY 26. 1976
37,
Title 40—Protection of Environment
[FRL 562-81
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Utah
Pursuant to the delegation of author-
ity for the standards of performance for
twelve (12) categories of new stationary
sources (NSPS) to the State of Utah on
May 13, 1976, EPA is today amending 40
CFR 60.4, Address, to reflect this delega-
tion. A Notice announcing this delega-
tion is published today in the FEDERAL
REGISTER. The amended § 60.4, which
adds the address of the Utah Air Con-
servation Committee to which all re-
ports, requests, applications, submlttals,
and communications to the Administra-
tor 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 im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
May 13. 1976, and it serves no purpose
to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended, 42 U.S.C. 1857c-6.
Dated: June 10, 1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In I 60.4 paragraph (b) Is amended
by revising subparagraph (TT) to read
as follows:
S 60.4 Addrcs*
(b) • • *
(TT)—State of Utah, Utah Air Con-
servation Committee, State Division of
Health, 44 Medical Drive, Salt Lake City,
Utah 84113.
* * * • *
[FB Doc.76-17433 Filed 6-14-78;8:45 am]
FEDERAL REGISTER, VOl. 41, NO. 116-
-TUESOAY, JUNE 15, 1976
V-146
-------
RULES AND REGULATIONS
3 8 Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[FRL 664-61
NEW SOURCE REVIEW
Delegation of Authority to the State of
Georgia
The amendments below Institute cer-
tain address changes for reports and ap-
plications required from operators of new
sources. EPA has delegated to the State
of Georgia authority to review new and
modified sources. The delegated author-
ity Includes the reviews under 40 CPB
Part 52 for the prevention of significant
deterioration. It also Includes the review
under 40 CFR Part 60 for the standards
of performance for new stationary
sources and review under 40 CFR Part
61 for national emission standards for
hazardous air pollutants.
A notice announcing the delegation of
authority Is published elsewhere In the
Notices section this Issue of the FEDERAL
REGISTER. These amendments provide
that all reports, requests, applications,
submlttals, and communications previ-
ously required for the delegated reviews
will now be sent instead to the Envi-
ronmental Protection Division, Georgia
Department of Natural Resources, 270
Washington Street SW.. Atlanta, Georgia
30334, instead of EPA's Region'IV.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
Immediately in that it Is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are Imposed on the parties affected.
The delegation which Is reflected by this
administrative amendment was effective
on May 3, 1976, and It serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal regulations.
This rulemaking Is effective immedi-
ately, and Is Issued under the authority
of Sections 101, 110. 111. 112 and 301 of
the Clean Air Act. as amended 42 \JS.C.
1657,1857C- 5. 6. 7 and 1857s,
Dated: June 11.1076.
JACK E. RAVAN,
Regional Administrator.
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
DELEGATION OF AUTHORITY TO THE
STATE or GEORGIA
Part 60 of Chapter I, Title 40, Code of
Federal Regulations, is amended as fol-
lows:
2. In § 60.4, paragraph (b) (L) Is re-
vised to read as follows:
§ 60.4 Address.
• • • • *
(b) • • •
(L) State of Georgia, Environmental Pro-
tection Division, Department of Natural Re-
sources, 270 Washington Street, S.W., At-
lanta, Georgia 30334.
FEDERAL REGISTER, VOL. 41, NO. 120-
-MONDAY, JUNE 21, 1976
39
SUBCHAPTER C—AIR PROGRAMS
[FRL 674-3]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Fresno, Mendoclno,
San Joaquin, and Sacramento County
Air Pollution Control Districts
pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Fresno County Air Pollution Control
District, the Mendoclno County Air Pol-
lution Control District, the San Joaquin
County Air Pollution Control District,
and the Sacramento County Air Pollu-
tion Control District, dated March 29,
1976, EPA Is today amending 40 CFR
60.4, Address, to reflect this delegation.
A Notice announcing this delegation Is
published today In the Notice Section of
this issue. The amended § 60.4 is set forth
below. It adds the addresses of the Fres-
no County, Mendocino County, San Joa-
quin County, and Sacramento County
Air Pollution Control Districts, to which
must be addressed all reports, requests,
applications, submittals, and communi-
cations pursuant to this part by sources
subject to the NSPS located within these
Air Pollution Control Districts.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective imme-
diately in that It Is an administrative
chenge and not one of substantive eon-
tent. No additional substantive burden*
are Imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
March 29, 1976, and it serves no purpose
to delay the technical change of this ad-
dition of the Air Pollution Control Dis-
trict addresses to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and Is Issued under the authority
of section 111 of the Clean Air Act, as
amended [42 TJjS.C. 1857C-6).
Dated: June 15,1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement^
Part 60 of Chapter I, Title 40, of the
Code of Federal Regulations, Is amended
as follows:
1. In S 60.4, paragraph (b) is amended
by revising subparagraph F to read as
follows:
§ 60.4 Address.
• • • « •
(b) * • •
(A)-(E) • • •
(F) California:
Bay Area Air Pollution Control District, 939
HHlis St.. San Francisco. CA 04109
Del, Norte County Air Pollution Control Dis-
trict, Courthouse, Crescent City, CA 96031
Fresno County Air Pollution Control District,
615 B. Cedar Ave.. Fresno, CA 93703
Humboldt County Air Pollution Control Dis-
trict. 6600 S. Broadway, Eureka, CA 96601
Kern County Air Pollution Control District,
1700 Flower St. (P.O. Box 997), Bakersfleld.
CA 93303
Mendoclno County Air- Pollution Control
District, County Courthouse, TJklah. CA
95463
Monterey Bay Unified Air Pollution Control
District, 430 Church 8h (P.O. Box 487),
Salinas, CA 93901
Northern Sonoma County-Air Pollution Con-
trol District, 3313 Chanate Rd.. Santa Boss,
CA 95404
Sacramento County Air Pollution Control
District, 2231 Stockton Blvd., Sacramento,
CA 96827
San Joaquin County Air Pollution Control
District, 1601 B. Hazel ton St. (P.O. Box
3009), Stockton, CA 95301
Trinity County Air Pollution Control Dis-
trict, Box AJ. Weavervllle. CA 96093
Ventura County Air Pollution Control Dis-
trict. 636 E. Santa Clara St, Ventura, OA
93001
FEDERAL REGISTER, VOL 41, NO. 1)2-
-THURSDAY. JULY 8, 1976
V-147
-------
RULES AND REGULATIONS
40 Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
IFRL 597-1)
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Madera County Air
Pollution Control District
Pursuant to the delegation of authority
for the standards of performance for new
stationary sources (NSPS) to the State
of California on behalf of the Madera
County Air Pollution Control District,
dated May 12,1976, EPA is today amend-
ing 40 CFR 60.4 Address, to reflect this
delegation. A Notice announcing this del-
egation is published in the Notices Sec-
tion of this issue of the FEDERAL REGISTER,
Environmental Protection Agency, FRL
596-4. The amended 5 60.4 is set forth be-
low. It adds the address of the Madera
County Air Pollution Control District, to
which must be addressed all reports, re-
quests, applications, submittals, and
communications pursuant to this part by
sources subject to the NSPS located
within this Air Pollution Control District.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaklng effective immed-
iately In that It Is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
May 12, 1976. and it serves no purpose to
delay the technical change of this addi-
tion of the Air Pollution Control District
address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended [42U.S.C. 1857c-6).
Dated: July 27, 1976.
PAUL DEFALCO.
Regional Administrator.
Region IX. EPA.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 5 60.4 paragraph
-------
42
|FRL 698-2)
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Revision to Emission Monitoring
Requirements
On October 6, 1975 (40 PR 46250),
under section 111 of the Clean Air Act,
as amended, the Environmental Protec-
tion Agency (EPA) promulgated emis-
sion monitoring requirements and revi-
sions to the performance testing methods
In 40 CFR Part 60. The provisions of
{60.13(1) allow the Administrator to
approve alternatives to monitoring pro-
cedures or requirements only upon writ-
ten application by an owner or operator
of an affected facility; monitoring equip-
ment manufacturers would not be al-
lowed to apply for approval of alternative
monitoring equipment. Since EPA did
not Intend to prevent monitoring equip-
ment manufacturers from applying for
approval of alternative monitoring
equipment, § 60.13(1) Is being revised. As
revised, any person will be allowed to
make application to the Administrator
for approval of alternative monitoring
procedures or requirements.
This revision does not add new require-
ments, rather it provides greater flexi-
bility for approval of alternative equip-
ment and procedures. This revision is
effective (date of publication).
(Sections 111, 114, and 301 (a) of the Clean
Air Act, as amended by sec. 4(a) of Pub'. L.
81-604, 84 Stat. 1678 and by sec. 16(c)(2) of
Pub. L. 91-604. 84 Stat. 1713 (43 U3.C. 1857O-
6, 1857C-9, and 1857g(a)).)
Dated: August 13,1976.
RUSSELL E. TRAIN,
Administrator.
In 40 CFR Part 60, Subpart A Is
amended as follows:
1. Section 60.13 is amended by revising
paragraph (1) aa follows:
§ 60.13 Monitoring requirement*.
• • • • •
(i) After receipt and consideration of
written application, the Administrator
may approve alternatives to any moni-
toring procedures or requirements of this
part Including, but not limited to the
following:
• • • • •
|FR Doc.76-24868 Filed 8-19-78; 8:45 am)
FEDERAL REGISTER, VOL 41, NO. 163
•FRIDAY, AUGUST 20, 1976
43
RULES AND REGULATIONS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
5. By revising § 60.9 to read as follows:
§ 60.9 Availability of information.
The availability to the public of In-
formation provided to, or otherwise ob-
tained by, the Administrator under this
Part shall be governed by Part 2 of this
chapter. (Information submitted volun-
tarily to the Administrator for the pur-
poses of §§ 60.5 and 60.6 is governed by,
§ 2.201 through § 2.213 of this chapter
and not by § 2.301 of this chapter.)
FEDERAL REGISTER, VOL. 41, NO. 171
WEDNESDAY, SEPTEMBER 1, 1976
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[FRL 617-2]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Stanislaus County.
Air Pollution Control District; Delegation
of Authority to State of California on Be-
half of Sacramento County Air Pollution
Control District; Correction
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Stanislaus County Air Pollution Control
District, dated July 2, 1976, EPA is today
amending 40 CPR 60.4 Address, to reflect
this delegation. A notice announcing
this delegation is published today at 41
FR 40108. The amended $ 60.4 Is set forth
below. It adds the address of the Stanis-
laus County Air Pollution Control Dis-
trict, to which must be addressed all re-
ports, requests, applications, submittals,
and communications pursuant to this
part by sources subject to the NSPS lo-
cated within this Air Pollution Control
District.
On July 8, 1976, EPA amended 40 CPR
60.4. Address to reflect delegation of au-
thority for NSPS to the State of Cali-
fornia on behalf of. the Sacramento
County Air Pollution Control District.
By letter of July 30.1976, Colin T. Green-
law, M.D., Sacramento County Air Pol-
lution Control Officer, notified EPA that
the address published at 41 FR. 27967
was Incorrect. Therefore, EPA is today
also amending 40 CFR 60.4, Address to
reflect the correct address for the^Sac-
ramento County Air Pollution Control
District. ' ;
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaklng effective Im-
mediately in that it Is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegations which are reflected by tills
administrative amendment were effec-
tive on July 2, 1976 and March 29, 1076.
and it serves no purpose to delay the
technical change of these additions of the
Air Pollution Control Districts addresses
to the Code of Federal Regulations.
This rulemaklng Is effective Immedi-
ately, and Is Issued under the authority of
Section 111 of the Clean Air Act, aa
amended (42 U.S.C. 1857C-4)
Dated: September 8, 1976.
L. RUSSELL FREEMAN,
Acting Regional Administrator,
Region IX, EPA.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In {60.4 paragraph
vised to read as follows:
§60.4 Address.
(b) (f ) Is re-
(F) California:
Bay Area Air Pollution Control District, 639
Ellis St., San Francisco, CA 94109
Del Norte Count; Air Pollution Control Dis-
trict, Courthouse, Crescent City, CA 96531
Fresno County Air Pollution Control District,
615 S. Cedar Avenue. Fresno, CA 93702
Humboldt County Air Pollution Control Dis-
trict, 6600 S. Broadway, Eureka, CA 95501
Kern County Air Pollution Control District,
1700 Flower St. (P.O. Box 997), Bakers-
field. CA 93302
Madera County Air Pollution Control Dis-
trict, 135 W. Yosemlte Avenue, Madera, CA
93637
Mendoclno County Air Pollution Control Dis-
trict, County Courthouse, Uklah, CA 95482
Monterey Bay Unified Air Pollution Control
District, 420 Church St. (P.O. Box 487).
Salinas, CA 93901
Korthern Sonoma County Air Pollution Con-
trol District, 3313 Chanato Rd., Santa
Rosa, CA 95404
Sacramento County Air Pollution Control
District. «701 Branch Center Road, Sacra-
mento, CA 95827
San Joaquln County Air Pollution Control
District. 1601 E. Hazelton St. (P.O. Box
2009) . Stockton, CA 95201
Stanislaus County Air Pollution Control Dis-
trict, 820 Scenic Drive. Modesto. CA 95360
Trinity County Air Pollution Control Dis-
trict. Box AJ. Weavervllle, CA 96093
Ventura County Air Pollution Control Dis-
trict, 625 E. Santa Clara St., Ventura, CA
93001
• • • • •
[FR Doc.76-27175 Filed 9-16-76;8:45 am]
FEDERAL REGISTER, VOL 41, NO. 182
FRIDAY, SEPTEMBER 17, 197*
V-149
-------
Title 4O — Protection of Environment
CHAPTER I — ENVIRONMENTAL
PROTECTION AGENCY
[FRL 819-1 J
SUBCHAPTER C— AIR PROGRAMS
PART 60 — STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61— NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Reports and Applications From Operators
of New Sources; Address Changes
DELEGATION OP AUTHORITY TO THE STATS
OF ALABAMA
The amendments below Institute cer-
tain address changes for reports and ap-
plications required from operators of new
sources. EPA has delegated to the State
of Alabama authority to review new and
modified sources. The delegated author-
ity Includes the review under 40 CPB Part
60 for the standards of performance for
new stationary sources and review under
40 CFB Part 61 for national emission
standards for hazardous air pollutants.
A notice announcing the delegation of
authority is published elsewhere In this
issue of the FEDERAL REGISTER. These
amendments provide that all reports, re-
quests, applications, submlttals, and
communications previously reulred for
the delegated reviews will now be sent
instead to the Air Pollution Control Divi-
sion. Alabama" Air Pollution Control
Commission, 645 South McDonough
Street, Montgomery, Alabama 36104, In-
stead of EPA's Region IV.
Thp Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegation which Is reflected by this
administrative amendment was effective
on August 5, 1976, and it serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
This rulemaking Is effective Immedi-
ately, and is Issued under the authority
of sections 111, 112, and 301 of the Clean
Air Act, as amended 42 U.S.C. 1857,
1857C-5, 6, 7 and 1857g.
Dated: September 9, 1976.
JACK E. LA VAN,
Regional Administrator.
Part 60 of Chapter I, Title 40, Code of
Federal Regulations, Is amended as fol-
lows:
1. In } 60.4, paragraph (b) Is amended
by revising subparagraph (B) to read a*
follows :
§ 60.4 Address.
46
RULES AND REGULATIONS
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[FRL 623-7]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Indiana
Pursuant to the delegation of authority
to Implement the standards of perform-
ance for new stationary sources (NSPS)
to the State of Indiana on April 21, 1976,
EPA Is today amending 40 CFR 60.4,
Address, to reflect this delegation. A
notice announcing this delegation is pub-
lished Thursday, September 30, 1976 (41
FR 43237). The amended §60.4, which
adds the address of the Indiana Air Pol-
lution Control Board to that list of ad-
dresses to which all reports, requests, ap-
plications, submittals, and communica-
tions to the Administrator pursuant to
this part must be sent, is set forth below.
The Administrator finds good cause for
foregoing prior notice and for making
this rulemaking effective immediately in
that it is an administrative change and
not one of substantive content. No addi-
tional substantive burdens are imposed
on the parties affected. The delegation
which is reflected by this administrative
amendment was effective on April 21,
1976, and it serves no purpose to delay
the technical change of this addition of
the State address to the Code of Fed-
eral Regulations. .
This rulemaking is effective immedi-
ately.
(Sec. Ill of the Clean Air Act, as amended,
42 U.S.C. 1857C-6.)
Dated: September 22, 1976.
, GEORGE R. ALEXANDER, Jr.,
Regional 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 P, to read as
follows:
g 60.4 Address.
* * * * •
(b) * • •
(A)-(O) • • •
(P) State of Indiana, Indiana Air Pollu-
tion Control Board, 1330 West Michigan
Street, Indianapolis, Indiana 4620C.
*****
|FR Doc.76-28507 Piled 9-29-76;8:45 am)
FEDERAL REGISTER, VOL. 41, NO. 191
THURSDAY, SEPTEMBER 30, 1976
4 ' Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
(FRL 629-81
PART 60—STANDARDS OF PERFORM-
ANCE FOR STATIONARY SOURCES
PART 61—NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLU-
TANTS
Delegation of Authority to State of
North Dakota
Pursuant to the delegation of author-
ity for the standards of performance for
new sources (NSPS) and national emis-
sion standards for hazardous air pol-
lutants (NESHAPS) to the State of
North Dakota on August 30. 1976, EPA
Is today amending respectively 40 CFR
60.4 and 61.04 Address, to reflect this
delegation. A notice announcing this del-
egation Is published today in the notices
section. The amended 65 60.4 and 61.04
which add the address of the North Da-
kota State Department of Health to
which all reports, requests, applications.
submittals, and communications to the
Administrator pursuant to these parts
must also be addressed, are set forth
below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which Is reflected by this ad-
ministrative amendment was effective on
August 30, 1976, and it serves no purpose
to delay the technical change of this
addition to the State address to the Code
of Federal Regulations.
This rulemaking Is effective immedi-
ately, and Is issued under the authority
of sections 111 and 112 of the Clean Air
Act, as amended, (42 U.S.C. 1857c-6 and
-7).
Dated: October 1.1976.
JOHN A. GREEN,
Regional Administrator.
Parts 60 and 61 of Chapter I, Title 40
of the Code of Federal Regulations are
respectively amended as follows:
1. In 5 60.4, paragraph (b) Is amended
by revising subparagraph (JJ) to read
as follows:
§ 60.1 Address.
* • • • •
(b) • ' •
(A)-(Z) • • •
(AA)-(II) • • •
(JJ)—State of North Dakota, State De-
partment of Health, State Capitol, Bismarck.
North Dakota BBS01.
(b) • • •
(B) State of Alabama. Air Pollution Con-
trol Division. Air Pollution Control Commte-
tlaa. 645 a McDonough Street, Montgomery.
Alabama 3010*.
FEDERAL REGISTER, VOL. 41, NO. 113
MONDAY, SEPTEMSa 20, 197*
FEDERAL REGISTER, VOL. 41, NO. 199
WEDNESDAY, OCTOBER 13, 1974
V-150
-------
RULES AND KE©ULMB©W§
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[PEL 638-4]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia On Behalf of Santa Barbara
County Air Pollution Control District
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS> to the
State of California on behalf of the
Santa Barbara County Air Pollution
Control District, dated September 17,
1976, EPA is today amending 40 CFR
60.4 Address, to reflect this delegation.
A Notice announcing this delegation is
published in the Notices section of this
issue of the FEDERAL REGISTER. The
amended § 60.4 is set forth below. It adds
theb address of the Santa Barbara
County Air Pollution Control District, to
which must be addressed all reports, re-
quests; applications, submrttals, and
communications pursuant to this part
by sources subject to the NSPS located
within this Air Pollution Control
District.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected this admin-
istrative amendment was effective on
September 17, 1978 and it serves no pur-
pose to delay the technical change on
this addition of the Air Pollution Control
District's address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended (42 U.S.C. 1857c-6).
Dated: October 20,1976.
PAUL DE FALCO, Jr.,
Regional Administrator,
EPA, Region IX.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 560.4 paragraph (b)(3) is
amended by revising subparagraph F to
read as follows:
§ 60.4 Addross.
(3)
Humboldt County Air Pollution Control
District. 5600 a. Broadway, Eureka. CA 95601.
Kern County Air Pollution Control Dis-
trict. 1700 Flower 8t. (P.O. Box 997), Bakers-
field. CA 93302.
Madera County Air Pollution Control Dis-
trict, 135 W. Yosemlte Avenue, Madera, CA
93637.
Mendoclno County Air Pollution Control
District, County Courthouse, Ublofa, CA
95482.
Monterey Bay Unified Air Pollution Con-
trol District, 420 Church St. (P.O. BOB 487).
Salinas. CA 93901.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate Rd., Santa
Rosa. CA 95404.
Sacramento County Air Pollution Control
District. 3701 Branch Center Road, Sacra-
mento, CA 95827.
San Joaquln County Air Pollution Control
District, 1601 E. Hazelton St. (P.O. Box 2008).,
Stockton. CA 96201.
Santa Barbara County Air Pollution Con-
trol District. 4440 Calle Real. Santa Barbara,
CA93110.
Stanislaus County Air Pollution Control
District. 830 Scenic Drive, Modesto. CA 96360.
Trinity County Air Pollution Control Dis-
trict. Box AJ, Weavervllle. CA 98093.
Ventura County Air Pollution Control Dis-
trict. 625 E. Santa Clara St., Ventura, OA
93001. '
|FR Doc.76-32104 Piled 11-3-76:8:46 am)
F2DEKAS. REGISTER, VOL. 41, NO. 213
WEDNESDAY, NOVEMBER S, W6
(A)-(E)
F—CALIFORNIA
Bay Area Air Pollution Control District.
939 Ellis St.. San Francisco. CA 94109.
Del Norte County Air Pollution Control
District, Courthouse, Crescent City. CA 95531.
Fresno County Air Pollution Control Dis-
trict. 515 8. Cedar Avenue, Fresno, CA 93703.
Title 40—Projection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[FRL 639-3)
PART SO—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to Subpart D
Standards of performance for fossil
fuel-fired steam generators of more than
73 megawatts (250 million Btu per hour)
heat input rate are provided under Sub-
part D of 40 CFR Part 60. Subpart D is
amended herein to revise the application
of the standards of performance for fa-
cilities burning wood residues in combi-
nation with fossil fuel.
Subpart D contains standards for par-
ticulate matter, sulfur dioxide, nitrogen
oxides, and visible emissions from steam
generators. These standards, except for
the one applicable to visible emissions,
are based on heat input. For sulfur di-
oxide, there are separate standards for
liquid fossil fuel-fired and solid fossil
fuel-fired facilities with provisions for &
prorated standard when combinations of
different fossil fuels are fired. There is
no sulfur dioxide standard for gaseous
fossil fuel-fired facilities since they emit
negligible amounts of sulfur dioxide.
To date, there have been two ways for
a source owner or operator to comply
with the sulfur dioxide standard: (1) By
firing low sulfur fossil fuels or (2) by
using flue gas desulfurlzation systems.
Complying with the standard by firing
low sulfur fossil fuel requires an ade-
quate supply of fuel with a sulfur con-
tent low enough to meet the standard.
However, it would be possible for the
owner or operator to fire, for example. Q
relatively high sulfur fossil fuel with &
very low sulfur fossil fuel (e.g. natural
gas) to obtain a fuel mixture which
would meet the standard. The low sulfur
fuel adds to the heat input but not to
the sulfur dioxide emissions and, thereby,
has an overall fuel sulfur reduction ef-
fect. In the past, the application of Sub-
part D permitted the heat content of
fossil fuels but not wood residue to tea
used in determining compliance with the
standards for particulate matter, sulfur
dioxide and nitrogen oxides: the amend-
ment made herein will allow the heat
content of wood residue to be used for
determining compliance with the stand-
ards. The amendment does not change
the scope of applicability of Subpart D;
all steam generating units constructed
after August 17, 1971. and capable of fir-
ing fossil fuel at a heat input rate of
more than 73 megawatts (250 million Btu
per hour) are subject to Subpart D.
RATIONALE FOR THE AMENDMENTS
Wood residue, which includes bark,
sawdust, chips, etc., is not a fossil fuel
and thus has not been allowed for use as
a dilution agent in complying with the
sulfur dioxide standard for steam gener-
ators. Several companies have requested
that EPA revise Subpart D to permit
blending of wood residue with high sulfur
fossil fuels. This would enable them to
obtain a fuel mixture low enough in sul-
fur to comply with the sulfur dioxide
standard. Since Subpart D allows the
blending of high and low sulfur fossil
fuels, EPA has concluded that it is rea-
sonable . to extend application of this
principle to wood residue which, although
not a fossil fuel, does have low sulfur
content.
Several companies have expressed in-
terest in constructing steam generators
which continuously fire wood residue in
combination with fossil fuel. New facili-
ties will comply with the standards for
less cost than at present because they0
will be able to use wood residue, a valu-
able source of energy, as an alternative to
expense low sulfur fossil fuels. Also.
using wood residue as a fuel supplement
instead of low sulfur fossil fuels will re=
V-151
-------
•SUIES AND REGULATIONS
suit in substantial savings In the con-
sumption of scarce natural gas and oil
resources, and will relieve what would
otherwise be a substantial solid waste
disposal problem. Consumption of energy
and raw material resources will be re-
duced further by minimizing the need
for flue gas desulfurization systems at
new facilities. There will be no adverse
environmental impact: neither sulfur di-
oxide nor nitrogen oxides emissions will
Increase as a result of this action. Con-
sidering the beneficial, environmental,
energy, and economic impacts, it is rea-
sonable to permit wood residue to be fired
as a low sulfur fuel to aid In compliance
with the standards for fossil fuel-fired
steam generators.
In making this amendment, EPA rec-
ognizes that affected facilities which
burn substantially more wood residue
than fossil fuel may have difficulty com-
plying with the 43 nanogram per Joule
standard for participate matter (0.1
pound per million Btu). There is not
sufficient information available at this
time to determine what level of particu-
late matter emissions is achievable; how-
ever, EPA Is continuing to gather Infor-
mation on this question. If EPA deter-
mines that the particulate matter stand-
ard Is not , achievable, appropriate
changes will be made to the standard.
Any change would be proposed for pub-
lic comment; however, in the Interim,
owners and operators will be subject to
the 43 nanogram per joule standard.
'P' FACTOR DETERMINATION
New facilities firing wood residue in
combination with fossil fuel will be sub-
ject to the emission and fuel monitoring
requirements of § 60.45 (as revised on
October 6, 1975, 40 PR 46250). The 'F'
factors listed in 5 60.45(f) (4), which are
used for converting continuous monitor-
ing data and performance test data into
units of the standard, presently apply
only to fossil fuels. Therefore, 'F' fac-
tors for bark and wood residue have been
added to § 60.45(f) (4). Any owner or op-
erator who elects to calculate his own
'P' factor must obtain approval of the
Administrator.
INTERNATIONAL SYSTEM OF UNITS
In accordance with the objective to
Implement national use of the metric sys-
tem, EPA presents numerical values In
both metric units and English units In
Its regulations and technical publica-
tions. In an effort to simplify use of the
metric units of measurements. EPA now
uses the International System of Units
(SD as set forth in a publication by the
American Society for Testing and Ma-
terials entitled "Standard tor Metric
Practice" (Designation: E 380-76). The
following amendments to Subpart D re-
Sect the use of SI units.
MISCELLANEOUS
Since these amendments are expected
to have limited applicability, no environ-
mental impact statement is required for
this rulemaking pursuant to section 1 (b)
of the "Procedures for the Voluntary
Preparation of Environmental Impact
Statements" (39 FR 37419).
This action is effective on November 22,
1976. The Agency finds that good cause
exists for not publishing this action as a
notice of proposed rulemaking and for
making it effective immediately upon
publication because:
1. The action is expected to have lim-
ited applicability.
2. The action will remove an existing
restriction on operations without in-
creasing emissions and will have benefi-
cial environmental, energy, and eco-
nomic effects.
3. The action Is not technically con-
troversial and does not alter the overall
substantive content of Subpart D.
4. Immediate effectiveness of the action
will enable affected parties to proceed
promptly and with certainty in conduct-
ing their affairs.
(Sees. Ill, 114 and 301 (a) of the Clean Air
Act, as amended by section 4(a) of Pub.L.
91-604, 84 Stat. 1878, and by section 16(c) (2)
of Pub.L. 91-604, 84 Stat;. 1713 (42 Ufi.C.
1857C-6, 1857C-9, 1857g(a)).)
Date: November 15,1976.
JOHN QUARLES,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.40 is amended by revising
the designation of affected facility and
by substituting the International System
(SI) of Units as follows:
§ 60.40 Applicability and designation of
affected facility.
(a) The affected facilities to which the
provisions of this subpart apply are:
(1) Each fossil fuel-fired steam gener-
ating unit of more than 73 megawatts
heat input rate (250 million Btu per
hour).
<2> Each fossil fuel and wood residue-
fired steam generating unit capable of
firing fossil fuel at a heat input rate of
more than 73 megawatts (250 million Btu
per hour).
(b) Any change to an existing fossil
fuel-fired steam generating unit to ac-
commodate the use of combustible mate-
rials, other than fossil fuels as defined in
this subpart, shall not bring that unit
under the applicability of this subpart.
2. Section 60.41 is amended by adding
paragraphs (d) and (e) as follows:
§ 60.41 Definitions.
o o o a o
-------
RULES AND REGULATIONS
.*(86)+y(130)+«.(300)
-
where :
PSNO, is the prorated standard for nitro-.
gen oxides when burning different
fuels simultaneously, in nanograms
per joule heat input derived from all
fossil fuels fired or from all fossil fuels
and wood residue fired,
x is the percentage of total heat input
derived from gaseous fossil fuel,
y is the percentage of total heat input
derived from liquid fossil fuel, and
f is the percentage of total heat input
derived from solid fossil fuel (except
lignite or a solid fossil fuel containing
25 percent, by weight, or more of coal
refuse).
When lignite or a solid fossil fuel con-
taining 25 percent, by weight, or more
of coal refuse is burned in combination
with gaseous, liquid, other solid fossil
fuel, or wood residue, the standard for
nitrogen oxides does not apply.
6. Section 60.45 is amended by sub-
stituting SI units in paragraphs (e),
(f)U>, (f)(2), (f)(4)(i), (f)(4)(li), (f)
(4) (ill), (f)(4)(lv), (f)(5), and (f) (5)
(U), by adding paragraphs (f)(4)(v)
and (f)(5)(LU), and by revising para-
graph (f ) (6) as follows:
§ 60.45 Emission and fuel monitoring.
.....
(e) An owner or operator required to
install continuous monitoring systems
under paragraphs (b) and (c) of this
section shall for each pollutant moni-
tored use the applicable conversion pro-
cedure for the purpose of converting
continuous monitoring data into units of
the applicable standards (nanograms
per joule, pounds per million Btu) as
follows:
(f) * * •
(1) E=pollutant emissions, ng/J (lb/
million Btu) .
(2) C=pollutant concentration, ng/
dscm (Ib/dscf ) , determined by multiply-
ing the average concentration (ppm) for
each one-hour period by 4.15x10* M ng/
dscm per ppm (2.59x10-' M Ib/dscf
per ppm) where Af=pollutant molecu-
lar weight, g/g-mole (Ib/lb-mole). Jf=
64.07 for sulfur dioxide and 46.01 for ni-
trogen oxides.
(i) For anthracite coal as classified
according to A.S.T.M. D 388-66, F=
2.723x10-' dscm/J (10,140 dscf/million
Btu) and Fc=0.532xlO-7 scm CO,/J
(1,980 scf COj/million Btu).
(ii) For subbitumlnous and bituminous
coal as classified according to A.S T.M D
388-66, F=2.637X10-' dscm/J (9820
dscf/million Btu) and Fc=0 486X10'7
scm C02/J (1,810 scf COz/million Btu).
(hi) For liquid fossil fuels including
crude, residual, and distillate oils,
F=2.476xlO-' dscm/J (9,220 dscf/mil-
lion Btu) and Fc=0.384 scm COi/J
(1,430 scf CO2/million Btu).
(iv) For gaseous fossil fuels, F=2.347
dscm/J 8,740 dscf /million Btu).
For natural gas, propane, and butane
fuels, Fc=0.279xlO-' scm COj/J (1,040
scf COj/million Btu) for natural gas,
0.322X10-' scm COa/J (1,200 scf COj/
million Btu) for propane, and 0.338X 10-'
scm COa/J (1.260 scf COa/million Btu)
for butane.
(v) For bark F=1.078 dscm/J (9,575
dscf/million Btu) and Fc=0.217 dscm/J
(1,927 dscf/million Btu). For wood resi-
due other than bark F—1.038 dscm/J
(9.233 dscf/million Btu) and Fc=0.207
dscm/J (1,842 dscf/million Btu).
(5) The owner or operator may use the
following equation to determine an P
factor (dscm/J or dscf/million Btu) on
a dry basis (if it is desired to calculate f
on a wet basis, consult the Administra-
tor) or Fc factor (scm COi/J, or scf COi/
million Btu) on either basis in lieu of the
F or Fc factors specified in paragraph
(f) (4) of this section:
227.0(%g) +95.7(%C) +35A(%S) + 8.6 (% AQ -28.5 (%0)
GCV
"(SI units)
10«[3.64(%g)+1.53(%C)+0.57(%S)+0.14(%Ar)--0.46(%Q)l
r~ GCV
(English units)
_ _20.0(%C)
GCV
(SI units)
_321X10J(%C)
GCK
(English units)
(I)*'*
(ii) GCV is the gross calorific value
(kJ/kg, Btu/lb) of the fuel combusted.
determined by the A.S.T.M. test methods
D 2015-66(72) for solid fuels and D 1826-
64(70) for gaseous fuels as applicable.
(ill) For affected facilities which fire
both fossil fuels and nonfossil fuels, the
F or F, value shall be subject to the
Administrator's approval.
(6) For affected facilities firing com-
binations of fossil fuels or fossil fuels and
wood residue, the F or F. factors deter-
mined by paragraphs (f ) (4) or (f ) (5) of
this section shall be prorated in accord-
ance with the applicable formula as fol-
lows:
variables or other factors, may be ap-
proved by the Administrator. The probe
and filter holder heating systems' in the
sampling train shall be set to provide a
gas temperature no greater than 433'K
(320°F).
.....
(f) For each run using the methods
specified by paragraphs (a) (3), (a) (4),
and (a) (5) of this section, the emissions
expressed in ng/J (Ib/million Btu) shall
be determined by the following pro-
cedure :
E=CP
20.9
20.9 —percent Ot
where:
Xi = the fraction of total heat Input
derived from each type of fuel
(e.g. natural gas, bituminous
coal, wood residue, etc.)
Fi or (Ft) i = the applicable F or Fc factor for
each fuel type determined In
accordance with paragraphs
(f)(4) and (f)(5) of this
section.
n=the number of fuels being
burned In combination.
* » » * *
7. Section 60.46 is amended by sub-
stituting SI units in paragraphs (b) and
(f ) and paragraph (g) is revised as fol-
lows :
§ 60.46 Test methods and procedures.
* . . . . '
'b> For Method 5. Method 1 shall be
used to select the 'sampling site and the
number of traverse sampling points. The
sampling time for each run shall be at
least 60 minutes and the minimum
sampling volume shall be 0.85 dscm (30
dscf) except that smaller sampling times
or volumes, when necessitated by process
where: '
(l) E = pollutant emission ng/J (lb/
million Btu).
(2) C = pollutant concentration, ng/
dscm (lb/ dscf), determined by method 5, 8,
or 7.
(3) Percent O.=oxygen content by vol-
ume (expressed as percent), dry basis. Per-
cent oxygen shall be determined by using the
Integrated or grab sampling and analysis
procedures of Method 3 as applicable.
The sample shall be obtained as follow*:
(g) When combinations of fossil fuels
or fossil fuel and wood residue are fired,
the heat input, expressed in watts (Btu/
hr). is determined during each testing
period by multiplying the gross calorific
value of each fuel fired (in J/kg or
Btu/lb) by the rate of each fuel burned
(In kg/sec or Ib/hr). Gross calorific
values are determined in accordance with
A.S.T.M. methods D 2015-66(72) (solid
fuels). D 240-64(73) (liquid fuels), or D,
1826-64(7) (gaseous fuels) as applicable.
The method used to determine calorific
value of wood residue must be approved
by the Administrator. The owner or oper-
ator shall determine the rate of fuels
burned during each testing period by
suitable methods and shall confirm the
FEDERAL REGISTER, VOL 41, NO. 226—MONDAY, NOVEMBER 22, 1976
V-153
-------
rate by a mv. -t/.ial balance over the steam
generation system.
(Sections 111. 114, and 301 (a) of the Clean
Al Act as amended by section 4(a) of Pub. L.
91-304, 84 Stat. 1678 and by section 15(ct (2)
Of Pub. L. 91-604. 84 Stat. 1713 (42 U.S.C.
1857C-6, 1857C-9, 1857g(a)).
|PR Doc.76-33966 Filed 11-19-76:8:45 am]
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
(FRL 639-2]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to Reference Methods 13A
and,138
On August 0. 1975 (40 FR 33151), the
Environmental Protection Agency (EPA)
Promulgated Reference Methods 13A and
13B In Appendix A to 40 CPR Part 60.
Methods 13A and 13B prescribe testing
and analysis procedures for fluoride
emissions from stationary sources. After
promulgation of the methods, EPA con-
tinued to evaluate them and as a result
has determined the need for certain
amendments to Improve the accuracy
and precision of the methods.
Methods ISAand 13B require assembly
of the fluoride sampling train so that
the filter Is located either between the
third and fourth impingers or in an
optional location between the probe and
first Implnger. They also specify that a
fritted glass disc be used to support the
filter. Since promulgation of the meth-
ods. EPA has found that when a glass
frit filter support is used in the optional
filter location, some of the fluoride
sample is retained on the glass. Although
no tests have been performed, it Is be-
lieved that fluoride retention may also
occur if a sintered metal frit filter sup-
port is used. However, In tests performed
using a 20 mesh stainless steel screen
as a filter support no fluoride retention
was noted. Therefore, to eliminate the
possibility of fluoride retention, sections
5.1.5 and 7.1.3 of Methods 13A and 13B
are being revised to require the use of
a 20 mesh stainless steel screen niter
support if the filter Is located between
the probe and first implnger. If the filter
is located In the normal position between
the third and fourth Impingers, the glass
frit filter support may still be used.
In addition to the changes to sections
5.1.5 and 7.1.3, a few corrections are also
being made. The amendments promul-
gated herein are effective on November
29, 1976. EPA flnus that good cause exists
for not publishing this action as a notice
of proposed rulemaking and for making
it effective immediately upon publication
because:
RULES AND REGULATIONS
1. The action is Intended to Improve
the accuracy and precision of Methods
13A and 13B and does not alter the
overall substantive content of the meth-
ods or the stringency of standards of
performance for fluoride emissions.
2. The amended methods may be used
immediately in source testing for fluoride
emissions.
Dated: November 17,1976.
JOHN QUARLES.
Acting Administrator.
In Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations, Appendix
A is amended as follows:
1. Reference Method 13A is amended
as follows:
(a) In section 3., the phrase "300
jig/liter" Is corrected to read "300 mg/
liter" and the parenthetical phrase "(see
section 7.3.6)" is corrected to read "(see
section 7.3.4)".
(b) Section 5.1.5 is revised to read as
follows:
5.1.6 Filter holder—If located between the
probe and first Implnger, boroslllcate glass
with a 20 mesh stainless steel screen filter
support and a slllcone rubber gasket: neither
a glass frit filter support nor a sintered metal
filter support may be used If the filter U In
front of the Impingers. If located between
the third and fourth Impingers, boroslllcate
glass with a glass frit filter support and a
slllcone rubber gasket. Other materials of
construction may be used with approval from
the Administrator, e.g., If probe liner Is stain*
less steel, then filter holder may be stainless
steel. The holder design shall provide a posi-
tive seal against leakage from the outside ot
around the filter.
(c) Section 7.1.3 is amended by re-
vising the first two sentences of the sixth
paragraph to read as follows:
7.1.3 Preparation of collection train. • • •
Assemble the train as shown In Figure
13A-1 with the filter between the third and
fourth Impingers. Alternatively, the filter
may be placed between the probe and first
Implnger If a 20 mesh stainless steel screen
Is used for the filter support. • • •
• • • • •
(d) In section 7.3.4, the reference In
the first paragraph to "section 7.3.6" Is
corrected to read "section 7.3.5".
2. Reference Method 13B Is amended
as follows:
(a) In the third line of section i, the
phrase "SOOMg/liter" is corrected to read
"300 mg/liter".
(b> Section 5.1.5 is revised to read as
follows:
5.1.5 Filter holder—If located between the
probe and first Implnger, boroslllcate glass
with a 20 mesh stainless steel screen filter
support and a sillcone rubber gasket: neither
a glass (rlt filter support nor a sintered metal
filter support may bejused If the filter Is In
front of the impingers. If located between
the third and fourth Impingers, boroslUcate
glass with a glass frit filter support and a
slllcone rubber gasket. Other materials of
construction may be used with approval from
the Administrator, e.g.. If probe liner Is stain-
less steel, then filter holder may be stainless
steel. The holder design shall provide a posi-
tive seal against leakage from the outside or
around the filter.
(c) Section 7.1.3 is amended by revis-
ing the first two sentences of the sixth
paragraph to read as follows:
7.1.3 Preparation of collection train. • • •
Assemble the train as shown In Figure
13A-1 (Method 13A) with the filter between
the third and fourth Impingers. Alterna-
tively, the filter may be placed between the
probe the first Implnger If a 20 mesh stain-
less steel screen Is used for the filter sup-
port. • • •
• • • • •
(d) In section 7.3.4, the reference in
the first paragraph to "section 7.3.6" is
corrected to read "section 7.3.5".
(Sees. 111. 114, and 301 (a) Clean Air Act/as
amended by sec. 4(a) of Pub. L. 91-604, 84
Stat. 1678 and by sec. 15(c)(2) of Pub. L.
81-604. 84 Stat. 1713 (42 U.S.C. 1857C-6.
1957C-9. and 1857g(2)).)
|FRDoc.76-34888Flled 11-26-76:8:45 am)
FEDERAL REGISTER. VOL 41, NO. 230—MONDAY, NOVEMBER 79. 1976
V-154
-------
RULES AND REGULATIONS
51
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAFTER C—AIR PROGRAMS
[FRL 661-5)
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to Pima County
Health Department On Behalf of Pima
County Air Pollution Control District
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPSi to Kie
Pima County Health Department on be-
half of the Pima County Air Pollution
Control District, dated October 7. 1976,
EPA is today amending 40 CFB 60.4
Address, to reflect this delegation. A
document announcing this delegation
is published today at 41 FR in the Notices
section of this issue. The amended
5 60.4 is set forth below. It adds the ad-
dress of the Pima County Air Pollution
Control District, to which must be ad-
dressed all reports, requests, applications.
submittals, and communications pursu-
ant to this part by sources subject to the
NSPS located within this Air Pollution
Control District.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective Imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
October 7, 1976 and it serves no purpose
to delay the technical change on this
addition of the Air Pollution Control
District's address to the Code of Federal
Regulations.
This rulemaking is effective Immedi-
ately, and is Issued under the authority
of Section 111 of the Clean Air Act. as
amended (42 U.S.C. 1867C-6).
Dated: November 19,1976.
R. ti. O'COMNELL.
Acting Regional Administrator.
Environmental Protection
Agency, Region IX.
52
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 adding subparagraph D to read as
follows:
§ 60.1 Address.
* • • • •
(3) • • •
(A)-(C) • • •
D—Arizona
Pima County Air Pollution Control Dis-
trict. 151 West Congress K< •••»<. Tucson. AZ
85701. •
|FR Doc.76-35562 Filed 12-2-76;8:45 am|
FEDERAL REGISTER, VOL. 41, NO. 234
MIOAV. OE^EMBES 3, 1976
I FRL 657-3]
PART 60— STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Califor-
nia on Behalf of San Diego County Air
Pollution Control District
Pursuant to the delegation of authority
for the standards of performance for
new stationary source* (NSPS) to the
State of California on behalf of the San
Diego County Air Pollution Control Dis-
trlct. dated November 8, 1976. EPA is
today amending 40 CFR 60.4 Address, to
reflect this delegation. A Notice announc-
ing this delegation is published in the
Notices section of this issue, under EPA
(FR Doc. 76-36929 at page 54798).. The
amended 8 60.4 is set forth below. It adds
the address of the San Diego County Air
Pollution Control District, to which must
be addressed all reports, requests, appli-
cations, submittals, and communications
pursuant to this part by sources subject
to the NSPS located within this Air Pol-.
lution Control District.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective Imme-
diately in that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegation which is reflected In this ad-
ministrative amendment was effective on
November 8. 1976 and it serves no pur-
pose to delay the technical change on
this addition of the Air Pollution Control
District's address to the Code of Federal
Regulations.
This rulemaking is effective Immedi-
ately, and is Issued under the authority
of section 111 of the Clean Air Act, as
amended (42 U.S.C. 1857c-6>.
.Dated: November 26, 1976.
Monterey Bay Unified Air Pollution Control
District, 420 Church Street (P.O. Box 4871
Salinas. CA 93901.
Northern Sonoma County Air Pollution
Control District. 3313 Chanate Road, SanU
Bosn. CA 96404.
Sacramento County Air Pollution Control
District, 3701 Branch Center Road, Sacra-
mento, CA 95627.
San Diego County Air Pollution Control
District, PlfO OneMpeak* Drir*. tea KM*.
CA03I3S. ^*^
San Joaqulu County Air Pollution Control
District, 1601 E. Bazelton Street (P.O Box
. 2009) Stockton, CA 96201.
Santa Barbara County Air Pollution Con-
trol District, 4440 Calle Heal. Santa Barbara
CA 93110 .
6tanl»lr.u8 County Air Pollution Control
District, 820 Scenic Drive, Modewto, CA 9S360.
Trinity County Air Pollution Control Dis-
trict, Box AJ, Weavervtlle. CA 96093.
Ventura County Air Pollution Control Dis-
trict, 626 E. Santa Clara Street, Ventura, CA
93001.
• • . • • «
|FB Doc,.76 36025 Filed 12-14-76:8:45 am]
FCDUAL UOIfTU. VOl. 41, NO. 24)
WEONCSDAr, DECfMMI 1-S. 1976
SHELIA M.
Acting Regional Administrator.
Environmental Protection
Agency, Region IX.
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 F to read as
follows:
§ 60.4 Addrraa.
• • • • •
(b> • • *
(A)-(E) • • • '
P-Californla:
Bay Area Air Pollution Control District.
939 Ellis Street, San Francisco, CA 94100.
Del Norte County Air Pollution Control
District, Courthouse, Crescent City, OA 96531.
Fresno County Air Pollution Control Dto-
trlct, 515 S. Cedar Avenue, Fresno, CA 93703.
Humboldt County Air Pollution Control
Dlstrlctt 5600 8. Broadway, Eureka, CA 96501.
Kem County Air Pollution Control Dis-
trict, 1700 Flower Street (P.O. Box 997).
Bakersfield, CA 93303.
Madera County Air Pollution Control Dis-
trict, y)5 W. Tosemlte Avenue. Modern. OA
93637.
Mendoclno County Air Pollution Control
District, County Courthouse. TJUah, OA
95482.
V-155
-------
53 [FRL 661-6]
PART 60—STANDARDS OF PERFORM
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of Ohio
Pursuant to the delegation of authority
to Implement the standards of per-
fc>! innnce for new stationary sources
' NSPS i to the State of Ohio on August 4,
1PVP. EPA Is today amending 40 CFR
00.4. Address to reflect this delegation.
A Notice announcing this delegation is
published in the Notices section of this
issue of the FEDERAL REGISTER (FR Doc.
76-37487). The amended §60.4 is set
forth below which adds the addresses
of the Agencies in Ohio which assist the
State in the delegated authority to that
list of addresses to which all reports, re-
quests, applications, submittals, and
communications to the Administrator
pursuant to this part must be sent.
The Administrator finds good cause for
foregoing prior notice and for making
this mlemaking effective immediately In
that it is an administrative change and
not one of substantive content. No addi-
tional substantive burdens are imposed
on the parties affected. The delegation
which is reflected by this administrative
amendment was effective on August 4,
1976, and it serves no purpose to delay
the technical change of this addition of
the addresses to the Code of Federal
Regulations.
This mlemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended.
(42 U.S.C. 1857C-6.)
Dated: December 10,1976.
GEORGE R. ALEXANDER, Jr.,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In 5 60.4, paragraph (b) is amended
by revising subparagraph KK, to read
as follows:
§ 60.4 Address.
(b) • • '
(A)-(JJ) • • •
(KK) Ohio—
Medina, Summit and Portage Counties;
Director, Air Pollution Control, 177 South
Broadway, Akron, Ohio, 44308.
Stark County; Director, Air Pollution Con-
trol Division, Canton City Health Depart-
ment, City Hall, 218 Cleveland Avenue SW.
Canton, Ohio, 44702.
Butler, Clermont, Hamilton and Warren
Counties; Superintendent, Division of Air
Pollution Control, 2400 Beekman Street. Cin-
cinnati, Ohio, 46214.
Cuyahoga County; Commissioner, Division
of Air Pollution Control, Department of
Public Health and Welfare, 2735 Broadway
Avenue, Cleveland, Ohio. 44115.
Loraln County; Control Officer. Division of
Air Pollution Control. 200 West Erie Avenue,
7th Floor. Lorain, Ohio. 44052.
Belmont, Carroll, Columbiana, Harrison,
Jefferson, and Monroe Counties; Director,
North Ohio Valley Air Authority (NOVAA).
814 Adams Street, Stcubenville, Ohio, 43052.
Clark, Darke, Greene, Miami. Montgomery,
and Preble Counties; Supervisor, Regional
Air Pollution Control Agency (RAPCA),
Montgomery County Health Department. 451
West Third Street, Dayton, Ohio, 45402.
RULES AND REGULATIONS
Lucas County and the City of Rossford (In
Wood County); Director, Toledo Pollution
Control Agency, 26 Main Street, Toledo, Ohio,
43605.
Adams, Brown, Lawrence, and Scioto
Counties; Engineer-Director. Air Division,
Portsmouth City Health Department. 740
Second Street, Portsmouth, Olilo, 45062.
All'1!). Ashland. Auglalzc. Crawford. De-
fiance, Erie. Fulton. Hancock. Hardln. Henry.
Huron. Knox, Marlon. Mercer, Morrow.
Ottawa. Paulding, Putnam. Richland, San-
dusky. Seneca. Van Wcrt. Williams,
Wood (except City ol Rossford), and Wyan-
dot CounUes: Ohio Environmental Protec-
tion Agency. Northwest District Office. Ill
West Washington Street, Bowling Green,
Ohio, 43402.
Ashtabula. Geauga, Lake. Mahonlng,
Trumbull, and Wayne Counties; Ohio Envi-
ronmental Protection Agency, Northeast Dis-
trict Office, 2110 East Aurora Road, Twins-
burg. Ohio, 44087.
Athens. Coshocton. Gallla, Guernsey, High-
land. Hocking, Holmes, Jackson, Melgs,
Morgan. MusTcingum, Noble, Perry, Pike,
Ro.is; Tuscarawas, Vlnton, and Washington
Counties: Ohio Environmental Protection
Agency. Southeast District Office, Route 3,
Box 603. Logan, Ohio. 43138.
Champaign, Clinton, Logan, and Shelby
Counties: Ohio Environmental Protection
Agency, Southwest District Office. 7 East
Fourth Street, Dayton. Ohio, 45402.
Delaware. Falrfield, Fayette. Franklin,
Licking. Madison, Plckaway, and Union
Counties; Ohio Environmental Protection
Agency. Central District Office. 309 Esst
Broad Street. Columbus, Ohio. 43216.
• • • • •
[FR Doc.76-37488 Filed 12-20-76:8:45 am)
FEDERAL REGISTER, VOL. 41, NO. 746
TUESDAY, DECEMBER 31, 1976
54 (FRL 665-1)
SUBCHAPTER C—AIR PROGRAMS
DELEGATION OF AUTHORITY—NEW
SOURCE REVIEW
Delegation of Authority to the State of
North Carolina
The amendments below institute cer-
tain address changes for reports and
applications required from operators of
new sources. EPA has delegated to the
State of North Carolina authority to
review new and modified sources. The
delegated authority includes the reviews
under 40 CFR Part 52 for the prevention
of significant deterioration. It also in-
cludes the reviews under 40 CFR Part 60
for the standards of performance for
new stationary sources and reviews un-
der 40 CFR Part 61 for national emission
standards for hazardous air pollutants.
A notice announcing the delegation of
authority is published elsewhere in thi:
issue of the FEDERAL REGISTER. Thes(
amendments provide that all reports, re
quests, applications, submittals. and
communications previously required for
the delegated reviews will now be sent
instead to the North Carolina Environ-
mental Management Commission. De-
partment of Natural and Economic Re-
sources. Division of Environmental Man-
agement, P.O. Box 27687, Raleigh. North
Carolina 27611. Attention: Air Quality
Section, instead of EPA's Region IV.
The Regional 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 sub-
stantive burdens are imposed on the par-
ties affected. The delegation which is
reflected by this administrative amend-
ment was effective on November 24, 1976,
and it serves no purpose to delay the
technical change of this addition of the
State address to the Code of Federal
regulations.
This rulemakmg is effective immedi-
ately, and is issued under the authority
of Sections 101. 110, 111, 112. and 301 of
the Clean Air Act, as amended, 42 U.S.C.
1857, 1857C-5. 6, 7 and 1857g.
Dated: December 21, 1976.
JOHN A. LITTLE,
Deputy Regional Administrator.
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
2. Part 60 of Chapter I, Title 40, Code
of Federal Regulations, is amended as
follows: In § 60.4, paragraph (b) is
amended by revising subparagraph (II)
to read as follows:
§ 60.1 Address.
*****
(b> ' * •
(A|-(HH) • ' •
(II) North Carolina Environmental Man-
agement Commission. Department of Natural
and Economic Resources, Division of Envi-
ronmental Management, P.O. Box 27887, Ra-
leigh. North Carolina 27611. Attention: Air
Quality Section.
SUBCHAPTER C—AIR PROGRAMS
| FRL 6G4-3)
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to Slate of
Nebraska
Pursuant to the delegation of author-
ity for the Standards of Performance
for New Stationary Sources (NSPS), to
the State of Nebraska on November 24.
1975. the Environmental Protection
Agency (EPA) is today amending 40 CFR
60.4, [Address.], to reflect this delega-
tion. A notice announcing this delegation
Is published (December 30. 1976), in the
FEDERAL REGISTER. Effective immediately
all requests, reports, applications, sub-
mittals, and other communications con-
cerning the 12 source categories of the
V-156
-------
NSPS which were promulgated Decem-
ber 23, 1971, and March 8. 1974, shall
be sent to Nebraska Department of En-
vironmental Control (DEC), P.O. Box
94653. State House Station, Lincoln,
Nebraska 68509. However, reports re-
quired pursuant to 40 CFR 60.7(a) shall
be sent to EPA, Region VII. 1735 Balti-
more, Kansas City, Missouri 64108, as
well as to the State.
The Regional Administrator finds good
cause for forgoing prior public notice
and making this rulemaking effective
immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
, This delegation, which is reflected by this
administrative amendment, was effective
on November 24. 1975, and it serves no
purpose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
This rulemaking is effective imme-
diately, and is issued under the author-
ity of Section 111 of the Clean Air Act,
as amended.
(42 U.S.C. 1857C-6.)
Dated: December 20,1976.
JEROME H. SVORE,
Regional 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 (CO to read
as follows:
g 60.4 Address.
* • * • •
(b) • * *
(A)-(BB) * • *
(CO Nebraska Department of Envi-
ronmental Control, P.O. Box 94653, State
House Station, Lincoln, Nebraska 68509.
(PR Doc.76-38234 Filed 12-29-76:8:45 am]
IFRL 664-6)
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Iowa
Pursuant to the delegation of author-
ity for New Source Performance Stand-
ards (NSPS) to the State of Iowa on
June 6, 1975, the Environmental Protec-
tion Agency is today amending 40 CFR
60.4, [Address.] to reflect this delegation.
A notice announcing this delegation is
published (December 30, 1976), in the
FEDERAL REGISTER.
The amended § 60.4 provides that all
reports, requests, applications, submit-
tals, and other communications required
for the 11 source categories of the NSPS.
which were delegated to the State.-shall
be sent to the Iowa Department of Envi-
ronmental Quality (DEQ>. 3920 Delaware
Avenue, P.O. Box 3326. Des Moines. Iowa
50316. However, reports required pur-
suant to 40 CFR 60.7(a) shall be sent to
EPA, Region VII, 1735 Baltimore, Kan-
sas City, Missouri 64108, as well as to the
State.
RULES AND REGULATIONS
The Regional Administrator finds good
muse to forgo prior public notice and
make this rulemaking effective immedi-
ately in that it is an administrative
change and not one of substantive con-
tent. The delegation was effective June 6,
1975, and it serves no purpose to delay
the technical change of the addition of
the State address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
(42 U.S.C. 1857C-G.)
Dated: December 20, 1976.
JEROME H. SVORE.
Regional Administrator.
Part 60 of Chapter 1, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph Q, to read as
follows:
§ 60.4 Address.
*****
(b) * * *
(A)-(P) • • •
(Q) State of Iowa, Department of
Environmental Quality, 3920 Delaware,
P.O. Box 3326, Des Moines, Iowa 50316.
*****
|PR Doc.76-38741 Filed 12-?9-76;8:45 am]
FEDERAL KGISTEI, VOL 41, NO. 252
THURSDAY, DECEMBEI 30, 1976
55
Title 40— Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[FRL 608-1]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of Vermont
Pursuant to the delegation of author-
ity for the Standards of Performance for
New Stationary Sources (NSPS) to the
State of Vermont on September 3, 1976,
.EPA is today amending 40 CPR 60.4,
Address, to reflect this delegation. A no-
tice announcing this delegation is pub-
lished today in the FEDERAL REGISTER.
(See FR Doc. 77-546 appearing in the
Notices section of this issue). The
amended § 60.4, which adds the address
of the Vermont .Agency of Environ-
mental Protection to which all reports,
requests, applications, submittals, and
communications to the Administrator
pursuant to this part must also be ad-
dressed, is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
September 3. 1976, and it serves no pur-
pose to delay the technical change of
this addition to the State address to the
Code of Federal Regulations.
This rulemaking is effective imme-
diately, and is issued under the authority
of Section 111 of the Clean Air. Act, as
amended. 42 U.S.C. 1857c-6.
Dated: December 17, 1976.
JOHN A. S. MCGLENNON,
Regioiial Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 5 60.4 paragraph (b) is amended
by revising subparagraph (UU) to read
as follows:
§ 60.4 Address.
*****
-------
RULES AND REGULATIONS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
DELEGATION OF AUTHORITY TO THE STATE
OF SOUTH CAROLINA
2. Part 60 of Chapter I, Title 40, Code
of Federal Regulations, Is amended by
revising subparagraph (PP) of § 60.4 (b)
to read as follows:
§ 60.4 . Address.
(b) • * *
(A)-(OO) • • •
(PP) State of Soulh Carolina, Oilicc of
Environmental Quality Control. Department
of Health and Environmental Control, 2000
Bull Street, Columbia, South Carolina 29201.
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
[PBL 673-6 J
NEW SOURCE REVIEW
Delegation of Authority to the State of
South Carolina
The amendments below institute cer-
tain address changes for reports and ap-
plications required from operators of new
sources. EPA has delegated to the State
of South Carolina authority to review
new and modified sources. The delegated
authority includes the reviews under 40
CFB Part 52 for the prevention of sig-
nificant deterioration. It also includes
the review under 40 CPR Part 60 for the
standards of performance for new sta-
tionary sources and review under 40 CFR
Part 61 for national emission standards
for hazardous air pollutants.
A notice announcing the delegation of
authority is published elsewhere in the
notices section of this Issue of the FED-
ERAL REGISTER. These amendments pro-
vide that all reports, requests, applica-
tions, submlttals, and communications
previously required for the delegated
reviews will now be sent to the Office of
Environmental Quality Control, Depart-
partment of Health and Environmental
Control, 2600 Bull Street, Columbia,
South Carolina 29201. instead of EPA's
Region IV.
The Regional Administrator finds
good cause for foregoing prior public
notice and for making this rulemaking
effective Immediately In that It Is an ad-
ministrative change and not one of sub-
stantive content. No additional substan-
tive burdens u.re Imposed on the parties
affected. The delegation which Is reflect-
ed by this administrative amendment
was effective on October 19, and It
serves no purpose to delay the technical
change of this addition of the State ad-
dress to the Code of Federal Regula-
tions.
This rulemaking is effective Immedi-
ately, and is issued under the authority
of sections 101, 110, 111, 112, and 301
of the Clean Air Act, as amended, 42
U.S.C. 1857C-5, 6, 7 and 1857g.
Dated: January 11, 1977.
JOHN A. LITTLE,
Acting Regional Administrator.
FEDERAL REGISTER, VOL. 42, NO. IS-MONDAY, JANUARY 24, 1977
NOTICES
ENVIRONMENTAL PROTECTION
AGENCY
[FBL 675-4 J
AIR PROGRAMS—STANDARDS OF PER-
FORMANCE FOR NEW STATIONARY
SOURCES
Receipt of Application and Approval of
Alternative Performance Test Method
On January 26, 1976 (41 FR 3826), the
Environmental Protection Agency (EPA)
promulgated standards of performance
for new primary aluminum reduction
plants under 40 CFR Part 60. The stand-
ards limit air emissions of gaseous and^
partlculate fluorides from new and modi-*
fled primary aluminum reduction plants.
The owners or operators of affected fa-
cilities are required to determine com-
pliance with these standards by conduct-
ing a performance test as specified in Ap-
pendix A—Reference Methods, Method
13A or 13B, "Determination of Total
Fluoride Emissions from Stationary
Sources" published In the FEDERAL REG-
ISTER August 6, 1075 (40 FR 33157). As
provided In 40 CFR 60.8(b), (2) and <3>,
the Administrator may approve the use
of an equivalent test method or may ap-
prove the use of an alternative method
if the method has been shown to be ade-
quate for the determination of compli-
ance with the standard. Method 13A
specified that total fluorides be deter-
mined by the SPADNS Zirconium Lake
colormetric method, and Method 13B
specified that this determination be made
by the specific ion electrode method.
On September 3, 1976. EPA received
written application for approval of equiv-
alency for a third analytical technique
from Kaiser Aluminum and Chemical
Corporation, Oakland, California. Specif-
ically, the application requested approv-
al of ASTM Method D 3270-73T, "Ten-
tative Method of Analysis for Fluoride
Content of the Atmosphere and Plant
Tissues," 1974 Annual Book of ASTM
Standards—Part 26.
Specific guidelines for the determina-
tion of method equivalency have not been
established by EPA. However, EPA has
completed a technical review of the ap-
plication and has determined that the
ASTM method will produce results ad-
equate for the determination of compli-
ance with the standards of performance
for new primary aluminum plants.
Therefore, EPA approves the ASTM
method as an alternative to the analyt-
ical procedures specified in paragraph
7.3 "Analysis" of Method 13A or 13B for
aluminum plants, pursuant to 40 CFR
60.8(b)(3).
Dated: January 18,1077.
ROGER STREIOW.
Assistant Administrator
tor Air and Waste Management.
|FR Doc.77-2385 Filed l-25-77;8:45 am]
FEDEKAL REGISTER, VOL. 41, NO. 17
WEDNESDAY. JANUARY 26, 1977
V-158
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RULES AND REGULATIONS
57
lllli! 'If)-- -Proleclloii nf riwiroMinnnt
CHAPMH I—tNVIRONMENTAL
PROTECTION AGENCY
|FHL (ion-4 |
PART 60—STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Revisions to Emission Monitoring
Requirements and to Reference Methods
On October 6, 1975 (40 FU 46250),
under sections 111, 114, and 301 of the
Clean Air Act, as amended, the Envi-
ronmental Protection Agency (EPA)
promulgated emission monitoring re-
quirements and revisions to the perform-
ance testing Reference Methods in 40
CPU Part 60. Since that time, EPA has
determined that there is a need for a
number of revisions to clarify the re-
quirements. Each of the revisions being
made in 40 CFR Part 60 are discussed
as follows:
1. Section 60.13. Paragraph (3) has
been rewritten to clarify that not only
new monitoring systems but also up-
graded monitoring systems must comply
with applicable performance specifica-
tions.
Paragraph (e) (1) is revised to provide
that data recording is not required more
frequently than once every six minutes
(rather than the previously required ten
seconds) for continuous monitoring sys-
tems measuring the opacity of emissions.
Since reports) of excess emissions are
based upon review of six-minute aver-
ages, more frequent data recording is
not required in order to satisfy these
monitoring requirements.
2. Section 60.45. Paragraphs (al
through 'ei have been reorganized for
clarification. In addition, restrictions on
use of continuous monitoring systems for
measuring oxygen on a wet basis have
been removed. Prior to this revision, only
dry basis oxygen monitoring equipment
was acceptable. Procedures for use of wet
basis oxygen monitoring equipment have
been approved by EPA and were pub-
lished in the FEDERAL REGISTER as an al-
ternative procedure (41 FR 44838).
Also deleted from § 60.45 are restric-
tions on the location of a carbon dioxide
(CO.) continuous monitoring system
downstream of wet scrubber flue gas de-
sulfurization equipment. At the time the
regulations were i promulgated (Octo-
ber 6. 1975), EPA thought that limestone
scrubbers were operated under condi-
tions that could cause significant gen-
eration or absorption of CO- by the
scrubbing solution which would cause
errors in the monitoring results. EPA in-
vesticntrd this potential problem and
concluded that lime or limestone scrub-
bers under typical conditions of opera-
tion do not significantly alter the con-
centration of CO.. in the flue gas and
would not introduce sicnificant errors
into the monitoring results. Lime scrub-
bers oocraU1 at a pH level between 7 and
8 which will maximize SO- absorption
and minimize CO, absorption. Thus, the
effect of CO.. loss on the emission results
is expected to be minimal. The exact
amount of CO;- loss, if any. during the
scrubber operation has not been deter-
mined Jiln'T! It Is (Irprndcnl 11)1011 tin:
>i|)i-r:illni: condition:; lor a piirlli-ular la-
cility. Although each percent of CO; ab-
sorption will result in a positive bias of
7.1 percent (at a ^tack concentration of
14 percent CO.-) in the final emission
results, i.e. the indicated results may be
higher than actual stack concentrations,
the actual bias is expected to be very
small since the amount of CO; absorp-
tion will be much less than one percent.
In flue gases from limestone scrubbers,
there exists a possibility of the addition
of COi from the scrubbing reaction to
the CO= from the fuel combustion. Every
two molecules of SO, reacting with the
limestone will produce a molecule of CO:.
Limestone scrubbers are typically oper-
ated at an approximate temperature of
50° C under acidic conditions. At these
operating conditions the amount of CO,
generated in a 90 percent efficiency
scrubber is 1350 ppm or 0.135 percent
CO... This will introduce a negative bias
of 1 to 1.5 percent for a CO: level of 8 to
15 percent. This amount of potential
error compares favorably with systems
previously approved. Therefore, EPA is
removing the restrictions which limited
the installation of carbon dioxide con-
tinuous monitoring systems to a location
upstream of the scrubber.
Several other revisions are being made
to paragraphs (a).
-------
RULES AND REGULATIONS
(2) For a fossil fuel-fired steam gen-
erator that does not use a flue gas de-
sulfurlzation device, a continuous moni-
toring system for measuring sulfur di-
oxide emissions is not required if the
owner or operator monitors sulfur di-
oxide emissions by fuel sampling and
analysis under paragraph (d) of this
section.
(3) Notwithstanding 560.13(10, in-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layednintil after the initial performance
tests under § 60.8 have been conducted.
If the owner or operator demonstrates
during the performance test that emis-
sions of nitrogen oxides are less than 70
percent of the applicable standards in
{ 60.44. a continuous monitoring system
for measuring nitrogen oxides emissions'
is not required. If the initial performance
test results show that nitrogen oxide
emissions are greater than 70 percent of
the applicable standard, the owner or
operator shall install a continuous moni-
toring system for nitrogen oxides within
one year after the date of the initial per-
formance tests under § 60.8 and comply .
with all other applicable monitoring re-
quirements under this part.
(4) If an owner or operator does not
install any continuous monitoring sys-
tems for sulfur oxides and nitrogen ox-
Ides, as provided under paragraphs (b)
(1) and (b)(3) or paragraphs (b) (2)
and (b) (3) of this section a continuous
monitoring system for measuring either
oxygen or carbon dioxide is not required.
(c) For performance evaluations un-
der 5 60.13(c) and calibration checks
under 560.13(d), the following proce-
dures shall be used:
(1) Reference Methods 6 or 7, as ap-
plicable, - shall be used for conducting
performance evaluations of sulfur diox-
ide and nitrogen oxides continuous mon-
itoring systems.
(2) Sulfur dioxide or nitric oxide, as
applicable, shall be used for preparing
calibration gas mixtures under Perform-
ance Specification 2 of Appendix B to
this part.
(3) For affected facilities burning fos-
sil fuel(s), the span value for a continu-
ous monitoring system measuring the
opacity of emissions shall be 80, 90, or
100 percent and for a continuous moni-
toring system measuring sulfur oxides or
nitrogen oxides the span value shall be
determined as follows:
(In parts per million)
Fossil luol
Span value lor Span value for
sulfur dioxide nitrogen oxides
Gas
Liquid
Solid
Combinations. .
W
1,000
1.600
1,000|/+ 1,5002
600
500
500
500(1+ 1/) +1,000*
1 Not applicable.
where:
X—the fraction of total heat Input derived
from gaseous fossil fuel, and
jr—the fraction of total heat Input derived
from liquid fossil fuel, and
B—the fraction of total heat Input derived
from solid fossil fuel.
(4) All span values computed under
paragraph (c)(3> of this section for
burning combinations of fossil fuels shall
be rounded to the nearest 500 ppm.
(5) For a fossil fuel-fired steam gen-
erator that simultaneously burns fossil
fuel and nonfossil fuel, the span value
of all continuous monitoring systems
shall be subject to the Administrator's
approval.
(d) [Reserved]
(e) For any continuous monitoring
system installed under paragraph (a) of
this section, the following conversion
procedures shall be used to convert the
continuous monitoring data into units of
the applicable standards (ng/J, Ib/mil-
lion Btu) : .
(1) When a continuous monitoring
system for measuring oxygen is selected,
the measurement of the pollutant con-
centration and oxygen concentration
shall each be on a consistent basis (wet
or dry) . Alternative procedures ap-
proved by the Administrator shall be
used when measurements are on a wet
basis. When measurements are on a dry
basis, the following conversion procedure
shall be used:
lowing conversion procedure shall be
used:
100 1
E=CF,\
f 20-9 1
L 20.9- percent O,J
where:
E, C, F, and % 0, are determined under para-
graph (t ) of this section.
(2) When a continuous monitoring
system for measuring carbon dioxide is
selected, the measurement of the pol-
lutant concentration and carbon dioxide
concentration shall each be on a con-
sistent basis (wet or dry) and the fol-
L percent COjJ
where:
E, C, PC and %CO; are determined under
paragraph (f) of this section.
APPENDIX B—PERFORMANCE
SPECIFICATIONS
3. Performance Specification 1 is
amended by revising paragraph 6.2 as
follows:
e . . .
6.2 Conformance with the requirements
of se'ction 6.1 may be demonstrated by the
owner or operator of the affected facility by
testing each analyzer or by obtaining a cer-
tificate of conformance from the Instrument
manufacturer. The certificate must certify
that at least one analyzer from each month's
production was tested and satisfactorily met
all applicable requirements. The certificate
must state that the first analyzer randomly
sampled met all requirements of paragraph
6 of this specification. If hny of the require-
ments were not met, the certificate must
show that the entire month's analyzer pro-
duction was resampled according to the mili-
tary standard 105D sampling procedure
(MIL-STD-106D) Inspection level II; was re-
tested for -each of the applicable require-
ments under paragraph 6 of this specifica-
tion; and was determined to be acceptable
under MII/-STD-105D procedures. The certifi-
cate of conformance must show the results
of each test performed for the analyzers
sampled during the month the analyzer be-
ing Installed was produced.
4. Performance Specification 2 is
amended by revising Figure 2-3 as
follows:
Test
No.
1
2
3
4
5
6
7
a
9
loan
lit (
kccur
Date
and
Time
Reference Method Samples
SO,
Sample 1
(ppn)
•
reference n
value (S02
onfldence 1
ethod
ntervals •
NO
Sample 1
(ppm)
»0 ; NO . ! NO Sample
Sample 2 ! Sample 3 ( Average
(ppm) i (ppm) j (ppm)
i |
|
1
Analyler 1-Hour
Average (ppm)*
soz NO,
I i
Kean reference method
test value (NOJ
ppm (SO.) • *
Difference
SO^'NO,
Mean of
"' the differences
ppm
Mean of the Differences , 951 confldence'lntervat _ ,„ . . ,«„
cl Mean reference method value " ""
lain and report method used to determine Integrated averages
• I (NOX)
Figure 2-]. Accuracy Determination (SOj and NO,)
(Sees. Ill, 114, 301(a), Clean Air Act, as amended, Pub. L. 91-604, 84 Stat. 1678 (42 U.S.C.
1857C-6, 1857-9, 1857g(a))).
(FR Doc.77-2744 Piled 1-28-77:8:46 am)
FEDERAL REGISTER, VOL. 42, NO. 70—MONDAY, JANUARY 31, 1977
V- 160
-------
RULES AND REGULATIONS
(FRL682-4)
RT 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to City of
Philadelphia
Pursuant to the delegation of author-
ity for the standards of performance
for new stationary sources (NSPS) to
the City of Philadelphia on Septem-
ber 30. 1976. EPA is today amending
40 CFR 60.4, Address, to reflect this
delegation. For a notice announcing
this delegation, see FR Doc. 77-3712
published in the Notices section of to-
day's FEDERAL REGISTER. The amended
§ 60.4. which adds the address of the
Philadelphia Department of Public
Health, Air Management Services, to
which all reports, requests, applications,
submittals. and communications to the
Administrator pursuant to this part
must also be addressed, is set forth be-
low.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this Ad-
ministrative amendment was effective on
September 30. 1976. and it serves no
purpose to delay the technical change
of this address to the Code of Federal
Regulations.
This rulemaking is effective imme-
iately, and is issued under the author-
,y of section 111 of the Clean Air Act,
Is amended, 42 U.S.C. 1857C-6.
Dated: January 25,1977.
A. R. MORRIS,
Acting Regional 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 (NN) to read
as follows:
§ f,0.1 Ailili-css.
* * * * •
(b) v * *
(A)-(MM) • • •
(NN)(a) City of Philadelphia: Philadelphia
Department of Public Health, Air Man-
agement Services, 801 Arch Street, Phila-
delphia. Pennsylvania 19107.
* * ' «, , .
[FR Doc.77-3709 Filed 2-3-77:8:46 am)
FEDERAL REGISTER, VOL 42, NO. 24
FRIDAY, FEBRUARY 4, 1977
59
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Region V Address; Correction
Section 60.4 paragraph (a) Is corrected
by changing Region V (Illinois, Indiana,
Minnesota, Michigan, Ohio, Wisconsin),
1 North Wacker Drive, Chicago, Illinois
60606 to Region V (Illinois, Indiana,
Minnesota, Michigan, Ohio, Wisconsin),
230 South Dearborn {Street, Chicago, Il-
linois 60604.
Dated: March 21,1977.
GEORGE R. ALEXANDER, Jr.,
Regional Administrator.
(FR DOC.77-9W6 Piled 3-29-77;8:45 am]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Wisconsin
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of Wisconsin on September 28.
1976, EPA Is today amending 40 CFR
60.4, Address, to reflect this delegation.
A Notice announcing this delegation Is
published today, March 30, 1977, at 42
FR 16845 in this FEDERAL REGISTER. The
amended 8 60.4, which adds the address
of the Wisconsin Department of Natural
Resources to which all reports, requests,
applications, submittals, and. communi-
cations 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 Im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
September 28, 1976 and it serves no pur-
pose to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Dated: March 21,1977.
GEORGE R. ALEXANDER, Jr.,
Regional 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 (YY), to read
as follows:
6 60.4 Address.
(b) • • •
(A)-(XX) • • •
(YY) Wisconsin—
Wisconsin Department of Natural Resources,
P.O. Box 7021, Madison, Wisconsin 63707.
(PR Doc.77-940* Piled »-29-77;8:46 am)
FEDEIIAL tEOISTER, VOL 43, NO. 61—WEDNESDAY. MARCH 30, 1977
V-161
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60
Title 40 — Protection of Environment
CHAPTER I— ENVIRONMENTAL
PROTECTION AGENCY
[FBI, 715-8]
PART 60— STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Compliance With Standards and
Maintenance Requirements
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action amends the
general provisions of the standards of
performance to allow methods other
than Reference Method 9 to be used as a
means of measuring plume opacity. The
Environmental Protection Agency (EPA)
Is Investigating a remote sensing laser
radar system of measuring plume opacity
and believes It could be considered as an
alternative meihod. to Reference Method
8. This amendment would allow EPA to
propose *uch systems as alternative
methods m the future.
: June 22, 1977.
FOR i-'UKTHKK INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone no. 919-688-8146. ext. 271. •
SUPPLEMENTARY INFORMATION:
As originally expressed, 40 CFR 60.11 (b)
permitted the use of Reference Method 9
exclusively for determining whether a
source complied with an applicable
opacity standard. By this action, EPA
•mends (60.1 Kb) so that alternative
methods approved by the Administrator
may be used to determine opacity.
When 8 60.1 Kb) was originally pro-
mulgated, the visible emissions (Method
0) technique of determining plume
opacity with trained visible emission ob-
servers was the only expedient and accu-
rate method available to enforcement
personnel. Recently, EPA funded the de-
velopment of a remote sensing laser ra-
dar system (LIDAR) that appears to pro-
duce results adequate for determination
of compliance with opacity standards.
EPA Is currently evaluating the equip-
ment and Is considering proposing Its
use as an alternative technique of meas-
uring plume opacity.
This amendment will allow EPA to
consider use of the LIDAR method of
determining plume opacity and, If ap-
propriate, to approve this method for en-
forcement of opacity regulations. If this
method appears to be a suitable alterna-
tive to Method 9, It will be proposed In
the FEDERAL REGISTER for public com-
ment. After considering comments, EPA
wfll determine If the new method will be
an acceptable means of determlnbig
•paclty compliance.
(Bees. Ill, 114.301 (a). Clean Air Act. sec, 4 (a)
Of Pub. L. 81-604, 84 Stat. 1883; sec. 4(a) of
Pub. L. 91-004, 84 Stat. 1687; oec. 3 of Pub. L.
Mo. 90-148, 81 Stat. 604 (43 U.S.C. 1867O-0.
1887C-9 and 18S7g(a)).)
RULES AND REGULATIONS
KCTTB.—Economic Impact Analysis: The
environmental Protection Agency has deter-
mined that thte action does not contain a
major proposal requiring preparation of an
Economic Impact Analysis under Executive
Orders 11821 and 11949 and OMB circular
A-10T.
Dated: May 10, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter L Title 40 of the
Code of Federal Regulations Is amended
•s follows:
L Section 60.11 Is amended by revising
i paragraph (b) as follows:
| 60.11 Compliance with standards and
maintenance requirements.
'••••»
Q>) Compliance with opacity stand-
ards m ttils part shall be determined by
conducting observations in accordance
with Reference Method 9 in Appendix A
of this part or any alternative method
that is approved by the Administrator.
Opacity readings of portions of plumes
which contain condensed, uncombined
water vapor shall not be used for pur-
poses of determining compliance with
opacity standards. The results of con-
tinuous monitoring by transmissometer
which indicate that the opacity at the
time visual observations were made was
not in excess of the standard are proba-
tive but not conclusive evidence of the
actual opacity of an emission, provided
that the source shall meet the burden of
proving that the instrument used meets
(at the time of the alleged violation)
Performance Specification 1 in Appendix
B of this part, has been properly main-
tained and (at the time of the alleged
violation) calibrated, and that the
resulting data have not been tampered
with in any way.
» - * • • •
(Sees. 111. 114, 301 (ft), Clean Air Act, Sec. 4
(a) of Pub. L. 91-604, 84 Stat. 1683; sec. 4(a)
of Pub. L. 91-604, 84 Stat. 1687; sec. 3 of Pub.
L. No. 90-148 81 Btat. 604 (42 U.S.C. 1857C-6.
1857C-9,18S7g(a)).)
(PR Doc.77-14562 Piled 6-20-77;8:45 am]
61
Tttto 40—Protection of Environment
CHAPTER 1—ENVIRONMENTAL PROTEC-
TION AGENCY
(PBL 743-6]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Petroleum Refinery Fluid Catalytic Cracking
Unit Catalyst Regenerators
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule revises the stand-
ard which limits the opacity of omissions
from new, modified, or reconstructed
petroleum refinery fluid catalytic crack-
Ing unit catalyst regenerators to 30 per-
cent, except for one six-minute period In
any one hour. The revision Is being made
to make the standard consistent with a
revision to the test method for opacity.
The standard Implements the Clean Air
Act and Is Intended to require the proper
operation and maintenance of fluid cata-
lytic cracking unit catalyst regenerators.
EFFECTIVE DATE: June 24, 1976.
ADDRESSES: Copies of the comment
letters and a report which contains a
summary of the issues and EPA's re-
sponses are available for public inspec-
tion and copying at the U.S. Environ-
mental Protection Agency, Public Infor-
mation Reference Unit (EPA Library).
Room 2922, 401 M Street SW., Washing-
ton, D.C. Copies of the report also may
be obtained upon written request from
the EPA Public Information Center
(PM-215), Washington, D.C. 20460
(specify Comment Summary—Petroleum
Refinery Fluid Catalytic Cracking
Units).
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone number 919-688-8146, ex-
tension 271;
.SUPPLEMENTARY INFORMATION:
BACKGROUND
On June 29, 1973, the U.S. Court of
Appeals for the District of Columbia
Circuit remanded to EPA the standards
of performance for Portland cement
plants (Portland Cement Association v.
Ruckelshaus, 486 F. 2d 375). One of the
issues remanded was the use of opacity
standards. On November 12, 1974, EPA
responded to the remand (39 FR
39872) and on May 22, 1975, the Court
affirmed the use of opacity standards
(513 F. 2d 506).
In the remand response, EPA recon-
sidered the use of opacity standards and
concluded that they are a reliable, In-
expensive, and useful means of ensuring
•that control equipment is properly main-
tained and operated at all times. EPA
also made revisions to the general pro-
FWHAl UCISTER, VOL 4«, NO. t*_MONOAY, MAY 13, 1*77
V-162
-------
AW© QE©yiLA¥ll©Kl§
visions of 40 CM?, Part 30 and to ®te
S&sference Method 9. •
EPA reevaluated the -opacity standard
ffor petroleum refinery fluid catalyse
cracking unit catalyst regenerators to
light of the revisions to Refereass
Method 9, and proposed & revision to
tills standard on August 30, 1873 (41 KS,
38600). The revision Is not the result c2
o reevaluation of the technical, economic
and environmental basis for the stand-
ard. Consequently, the revised op&cits?
standard will be neither more nor tea
stringent than the previous standard.
and will be consistent with the moa
emission standard (1.0 kg/1000 kg o5
cote burnofi).
SUMMARY OP COMMENTS &HD JgPA'o
R.BSPOHSES
iSPA received sis letters ccmmentins
on the proposed revision (three from to-
dustry and three from State and local
governments). Two commenters pointed
out that the basis for the original .cpac-
ity standard assumed new fluid catalyse
cracking units would be of 85,000 barrate
per day capacity, but the proposed re-
vision assumed new fluid catalytic crack-
ing units would be of less than 50,009
barrels per day capacity. Two other ccra-
menters pointed out that Jhe original
standard allowed one three-minute ex-
ception from the opacity standard oS
performance to accommodate soot-
blowing in the carbon monoxide boiler
and that the proposed change to ste-
minute averages did not justify addir?
on additional exception.
A review of the basis for the original
opacity standard indicates the com-
menters are correct. Large, new or modi-
fied fluid catalytic cracking units will
more likely be in the range of 85,000
barrels per day capacity, and one ex-
ception per hour more accurately reflects
the one three-minute exception allowed
under the previous test method. The ef-
fect of increased capacity on the opacity
of particulate mass emissions was dis-
cussed both in the FEDERAL REGISTER no-
tice proposing revision of the opacity
standard and In the background infor-
mation document supporting the revi-
sion. Considering the effect 6n opacity of
the greater capacity of a 85,000-barrel-
per-day fluid catalytic cracking unit
compared toe a 50,000-barrel-per-day
unit leads to the conclusion that the
opacity standard should not be revised
to 25-percent, but should remain at 30
percent opacity. Accordingly, the revised
opacity standard is promulgated as 30
percent opacity with one six-minute ex-
ception period per hour.
One comment concerned § 60.11 (e) of
the General Provisions and questioned
whether in its present form it adequately
accounts for the problems of petroleum
refinery fluid catalytic cracking units.
Section 80.11 (e) provides relief for those
individual sources where, because of op-
erating variables, opacity readings ore
abnormally high and cause it to exceed
the standard, even though.it is in com-
pliance with the mass emission stand-
ard. The mechaaism £0? relief te fctat
Q3»aelty readings may be taken during
initial start-up mass emission testing
and & special opacity standard assignee!
Co She source.
^Petroleum refinery fluid catalytSe-
crocking units operate continuously for
periods of two years or more; and over
ouch Ions periods, mass and opacity
omissions gradually increase. For thb
reason, the mass and opacity standard
were set on the basis of levels achievable
at the end of the run. Xt is to be es-
Btssted, therefore, that at the beginning
of the run, both mass and opacity emta-
oions from such units will be well below
£he standard, even in some cases where
opacity readings are abnormally hSg&
Given the mass emissions. XQ such cases,
on individualized opacity standard based
OB beglnning-of-run readings would not
necessarily prevent the facility which
still meets the mass emissions standard
at the end of the run from failing aa
ead-of-run opacity test. To alleviate (8), end (e)(4) of the General
Provisions, will permit determination of
an individualized opacity standard for
a Quid catalytic cracking unit during
any performance test and not just the
initial performance test. This will ensure
that a properly operated and maintained
source will not be found In violation oS
the opacity standard, while in compli-
ance with the applicable mass emtesioa
standard.
The proposed amendment to 9 30.103
(a) (2) specified that opacity readings
of oortions of plumes which contain
condensed, uncombined water vapor are
not to be used for determining compli-
ance with opacity standards. Since this
provision has been added to 8 60.1Kb)
of the General Provisions, it is not neces-
sary to repeat it in Subpart J for petro-
leum refineries.
MXSCEtLAHEOtTS
The opacity standard, as modified, ap-
plies to all affected facilities for which
construction or modification was com-.
menced after June 11,1973, the date the
standard was proposed.
This revision is promulgated under the
authority of sections 111, 114, and 301 (a)
of the Clean Air Act, as amended by
•Public Law 91-604, 84 Statute 1883, 1837
(42 U.S.C. 1857C-8, 1857c-9) and Public
Law 60-148. 81 Statute 504 (42 U.S.C.
1857g(a».
Norn.—The Environmental Protection
Agency hcs determined that this document
6osa not contain e major proposal requiring
preparation of on Economic Impact State-
ment under Ssecutlve Orders 11821 end
. 11949, and OMB Circular R-107.
Bated: June24.1977.65
DOUGLAS M. COSTLE,
Administrator.
Part 60, Chapter I of Title 40 of the
Code of Efteder&l Regulations is amended
os follows:
1. Section 80.102(o) (2) Sg'revtesd 4®
read as follows:
§ 60.102 Standard for particuIaRe mama?.
(O) ° ° °
(3) Gases exhibiting greater than SO
percent opacity, except for one sis-min-
ute average opacity. reading in any. one
hour.
(Ssc. Ill, Pub. L. 61-60$. 84 Stat. 1683 (42
U.S.C. 1857C-9): ESC. £01(a), Pub. L. 60-108.
01 Stat. B04 (C3 UJ3.C. 1867g (o)).)-
S. Section Q0.108(o) (i)
read as follows:
§ (SQ.105 Emission i
(e) . ° ° °
(1) Opacity. All hourly periods whic&
contain two or more six-minute periods
during which the average opacity as
measured by the continuous monitoring
system exceeds 30 percent.
O O . O 0 0
3. Section 80.108(e) is added to read oa
follows:
(e) An owner or operator of an af-
fected facility may request the Adminis-
trator to determine opacity of emissions
from the affected facility during any per-
formance test covered under g 60.8. In
such event the provisions of 88 60.11 (e)
(2) , (e) (3) , and (e) (4) shall apply.
(S3C. Ill, 114, Pub. L. 91-604, 84 Stat. :
1887 (42 U.S.C. 1867C-6, 1857C-9); sec. 301 (o),
Pub. L. &0-148, 01 Stat. 604 (43 U.S.C. 1Q37Q
(Q)).)
[PR Doc.77-10139 Filed 6-23-77:8:46 cm]
QBglSTQB, VOL-18, M©. 122—PQIBAV, .WNB 24, W77
V-163
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62
[PRL 752-31
6O—STANDARDS OF
PART 6O—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Units and Abbreviations
AGENCY: Environmental Protection
Agency
ACTION: Final rule
SUMMARY: This action revises the Gen-
eral Provisions by reorganizing the unite
and abbreviations and adding the Inter-
national System of Units (SI). Until re-
cently, EPA did not have a preferred sys-
tem of measurement to be used in tte
regulations. Now the Agency is using SI
units in all regulations issued under this
part. This necessitates that SI units be
added to the General Provisions to pro-
vide a complete listing of abbreviations
used..
EFFECTIVE DATE: August 18, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency. Research
Triangle Park, North Carolina 27711,
telephone no. 919-541-5271.
SUPPLEMENTARY INFORMATION:
BACKGROUND
Section 3 of Pub. L. 94-168, the Metric
Conversion Act of 1975, declares that
the policy of the United States shall be
to coordinate and plan the increasing
use of the metric system in the United
States. On December 10, 1978, a notice
was published in the FEDERAL RICISTW
(41 FR 54018) that set forth the inter-
pretation and modification of the Inter-
national System of Units (SI) for the
United States. EPA incorporates SI units
in all regulations issued under 40 CFR
Part 60 and provides common equivalents
in parentheses where desirable. Use of
81 unite requires this revision of the ab-
breviations section (} 60.3) of the Gen-
eral Provisions of 40 CFR Part 60.
Rename* DOCUMENTS
An explanation of the International
Systems of Units was presented in the
FEDERAL REGISTER notice mentioned
above (41 FR 54018). The Environmental
Protection Agency is using the Standard
for Metric Practice (E 380-76) published
by the American Society for Testing and
Materials (A.S.T-M.) as its basic refer-
ence. This document may be obtained by
•ending $4.00 to A.S.T.M.. 1916 Race
Street, Philadelphia, Pennsylvania 19103.
MISCELLANEOUS
As this revision has no regulatory im-
pact, but only defines units and abbrevi-
RULES AND REOUIATIONS
ations used in this part, opportunity for
public participation was judged unnec-
essary.
(Sections III and 301 (a) of the Clean Air
Act; sec. 4(a) of Pub. L. 91-604. 84 Stat. 1683;
sec. 3 ol Pub. U 90-148, 81 Stat. 504 (42 USJC.
1857C-6, 1857g(a».)
Nor*.—The Environmental Protection
Agency has determined that this document
doea not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Orders 11821 and 11949 and
OMB Circular A-107.
Dated: Julys, 1977.
DOUGLAS M. COSTLE,
Administrator.
40 CFR Part 60 Is amended by revis-
ing g 60.3 to read as follows:
§ 60.3 Units and abbreviations.
Used in this part are abbreviations and
symbols of units of measure. These are
defined as follows:
(a) System International (SI) units
of measure:
A—ampere
t—gram
Hs—hertf
J—joule
K—degree Kelvin
kg—kilogram
m—meter
a' cubic meter
mg—milligram—10-1 gram
mm—millimeter—IO-" meter
Mg—megagram—10* gram
mol—mole
N—newton
ng—nanogram—10-' gram
nm—nanometer—10-" meter
Pa—pascal
•—second
T—volt
W—watt
a—ohm
«g—mlcrogram—10-* gram
(b) Other units of measure:
Btu—British thermal unit
•C—degree Celsius (centigrade)
cal—calorie
cfm—cubic feet per minute
cu ft—cubic feet
dcf—dry cubic feet
dcm—dry cubic meter
dacf—dry cubic feet at standard conditions
dscm—dry cubic meter at standard condi-
tions
eq—equivalent
•F—degree Fahrenheit
ft—
-------
[FRL 762-2]
>AKY SO—STANDARDS OF PERFORM-
'ANCE FOR NEW STATIONARY SOURCES
[Delegation of Authority to the State of Now
Jersey
AGENCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: A notice announcing EPA's
delegation of authority for the New
Source Performance Standards to the
State of New Jersey is published at page
37387 of today's FEDERAL REGISTER. In
order to reflect this delegation, this docu-
ment amends EPA regulations to require
the submission of all notices, reports, and
other communications called for by the
delegated regulations to the State of New
Jersey rather than to EPA.
EFFECTIVE DATE: July 21,1977.
FOR FURTHER INFORMATION CON-
TACT:
J. Kevin Healy, Attorney, UJS. Envi-
ronmental Protection Agency, Region
n. General Enforcement Branch, En-
forcement Division, 26 Federal Plaza,
New York, New York 10007, 212-264-
1196).
SUPPLEMENTARY INFORMATION:
On May 9, 1977 EPA delegated author-
ity to the State of New Jersey to imple-
ment and enforce the New Source Per-
formance Standards. A full account of
the background to this action and of the
,ct terms of the delegation appear in
e Notice of Delegation which is also
blished in today's FEDERAL REGISTER.
This rulemaking is, effective Immedi-
ately, since the Administrator has found
good cause to forego prior public notice.
This addition of the State of New Jersey
address to the Code of Federal Regula-
tions is a technical change and Imposes
no additional substantive burden on the
parties affected.
Dated: July 18, 1977.
BARBARA BLUM,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
under authority of Section 111 of the
Clean Air Act (42 U.S.C. 1857C-6). as
follows:
(1) In § 60.4 paragraph (b) is amended
by revising subparagraph (FF) to read
as follows:
§ 60.4 Address.
O O O O O
(b) ° ° "
(FF)—State of New Jersey: New Jersey Ds-
partment of Environmental Protection,
John Fitch Plaza, P.O. Box 2807, Trenton,
Hew Jersey 08825.
o o ' o - o o
|PB Doc.77-21020 Filed 7-20-77:8:
regulations under proposal and to future
regulations at the time of promulgation.
' MISCELLANEOUS
As this action has no regulatory im-
pact, but only sets forth applicability
dates for the purpose of clarification,
public participation was judged un-
necessary.
(Sees. Ill and 301 (B) of the Clean Air Act;
nee. 4(a) of Pub. L. 91-804, 84 Stat. 1683; sec.
Z of Pub. L. 90-148, 81 Stat. 604 (42 U.S.C.
IB57C-6. 1857g(Q)).)
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Orders 11821 and 11949 and
OMB Olrcul&r A-107.
Dated: July 18, 1977.
BARBARA BLUM,
Acting Administrator.
40 CFR Part 60 is amended by revising
Subparts D through AA as follows:
Subpart D—Standards of Performance for
Fossil-Fuel-Fired Steam Generators
1. Sectioa 60.40 is revised as follows:
§ 60.40 Applicability and designation off
affected facility.
(e) The affected facilities to which the
provisions of this subpart apply are:
(1) Each fossll-fuel-fired steam gen-
erating unit of more than 73 megawatts
heat input rate (250 million Btu psr
hour).
(2) Each fossil-fuel and wood-residue-
fired steam generating unit capable of
firing fossil fuel at a heat input rate of
more than 73 megawatts (250 million
Btu per hour).
(b) Any change to an existing fossil-
fuel-fired steam generating unit feo
accommodate the' use of combustible
materials, other than fossil fuels os
defined in this subpart, shall not bring
that unit under the applicability of this
subpart.
(c) Any facility under paragraph (a)
of this section that commences con-
struction or modification after August
17, 1971, is subject to the requirements
of this subpart.
Subpart IE—Standards of Psrformaraco fer
• (Incinerators
2.-Section 60.50 is revised as follows:
§ 60.50 Applicability omdl deoigramion anff
affected jTacnlily.
(a) The provisions of Oils subpart ore
applicable to each incinerator of more
than 45 metric tons psr day charging
rate (50 tons/day), which & the affected
facility.
PE0SOAI QESISTEQ, VOl. 42, NO.
•7HUBSBA7, 48&V 21,
V-165
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RULES AND REGULATIONS
(b) Any facility under paragraph (a)
.01 Uils section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart F—Standards of Performance for
Portland Cement Plants
. 3. Section 60.60 is revised as follows:
§ 60.60 Applicability and designation of
. affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities In pertland cement plants: kiln,
clinker cooler, raw mill system, finish
mill system, raw mill dryer, raw material
storage, clinker storage, finished product
storage, conveyor transfer points, bag-
ging and bulk loading and unloading sys-
tems.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart G—Standards of Performance for
Nitric Acid Plants
4. Section 60.70 Is revised as follows:
§ 60.70 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to each nitric acid production
unit, which is the affected facility.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart H—Standards of Performance for
Sulfuric Acid Plants
5. Section 60.80 Is revised as follows:
§ 60.80 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to each sulfuric acid produc-
tion unit, which is the affected facility.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, Is subject to the requirements of
this subpart.
Subpart I—Standards of Performance for
Asphalt Concrete Plants
-6. Section 60.90 Is revised as follows:
§ 60.90 Applicability and designation of
affected facility.
(a) The affected facility to which the
provisions of this subpart apply Is each
asphalt concrete plant. For the purpose
of this subpart, an asphalt concrete plant
is comprised only of any combination of
the following: dryers; systems for
screening, handling, storing, and weigh-
ing hot aggregate; systems for loading,
transferring, and storing mineral filler;
systems for mixing asphalt concrete;
and the loading, transfer, and storage
systems associated with emission con-
trol systems.
Subpart J—Standards of Performance for
• Petroleum Refineries
7. Section 60.100 Is revised as follows:
§60.100 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities In petroleum refineries: fluid
catalytic cracking unit catalyst regen-
erators, fluid catalytic cracking unit
incinerator-waste heat boilers, and fuel
gas combustion devices.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
Is subject to the requirements of this
subpart.
Subpart K—Standards of Performance for
Storage Vessels for Petroleum Uquids
8. Section 60.110 is revised as follows:
g 60.110 Applicability and designation
of affected facility.
(a) Except as provided in 8 60.110(b>.
the affected facility to which this sub-
part applies Is each storage vessel for
petroleum Uquids which has a storage
capacity greater than 151,412 liters
(40,000 gallons).
(b) This subpart does not apply to
storage vessels for petroleum or conden-
sate stored, processed, and/or treated at
a drilling and production facility prior
to custody transfer.
(c) Subject to the requirements of
this subpart Is any facility under para-
graph (a) of this section which:
(1) Has a capacity greater than
151,412 liters (40,000 gallons), but not
exceeding 245,000 liters (65,000 gallons,
and commences construction or modifi-
cation after March 8,1974.
(2) Has a capacity greater than
245.000 liter (65,000 gallons), and com-
mences construction or modification
after June 11.1973.
Subpart L—Standards of Performance for
Secondary Lead Smelters
B. Section 60.120 is revised as follows:
160.120 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in secondary lead smelters: pot
furnaces of more than 250 kg (550 Ib)
charging capacity, blast (cupola) fur-
naces, and reverberatory furnaces.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after June 11.
1973. Is subject to the requirements of
this subpart
Subpart M—Standards of Performance for
Secondary Brass and Bronze Ingot Pro-
duction Plants
10. Section 60.130 is revised as fol-
lows:
§60.130 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities In secondary brass or bronze in-
got production plants: reverberatory
and electric furnaces of 1,000 kg (2,205
Ib) or greater production capacity and
blast (cupola) furnaces of 250 kg/hr
(550 Ib/hr) or greater production ca-
pacity.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
Is subject to the requirements of this
subpart.
Subpart N—Standards of Performance for
Iron and Steel Plants
11. Section 60.140 is revised as follows:
§ 60.140 Applicability and designation
of affected facility.
(a) The affected faculty to which the
provisions of this subpart apply Is each
basic oxygen process furnace.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
Subpart O—Standards of Performance for
Sewage Treatment Plants
12. Section 60.150 is revised as follows:
§60.150 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
incinerator which burns the sludge pro-
duced by municipal sewage treatment
facilities.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
Subpart P—Standards of Performance for
Primary Copper Smelters
13. Section 60.160 Is revised as follows:
§ 60.160 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
aplicable to the following affected facili-
ties in primary copper smelters: dryer,
roaster, smelting furnace, and copper
converter.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 16.
1974, is subject to the requirements of
this subpart.
Subpart Q—Standards of Performance for
Primary Zinc Smelters
14. Section 60.170 is revised as follows:
§ 60.170 Applicability and designation
of affected facility. ... .
(a) The provisions of this subpart are
applicable to the following affected facul-
ties In primary zinc smelters: roaster and
sintering machine.
. (b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 16,
1974, Is subject to the requirements of
this subpart.
HDMAl IfOISTH, VOL 42, NO. 141—MONDAY, JULY 13, 1977
V-166
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YULES AND REGULATIONS
iubpart R—Standards of Performance for
Primary Lead Smelters
15. Section 60.180 is revised as follows:
§ 60.180 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected
facilities in primary lead, smelters: sin-
tering machine, sintering machine dis-
charge end, blast furnace, dross rever-
beratory furnace, electric smelting fur-
nace, and converter.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
16. 1974, is subject to the requirements
of this subpart.
Subpart S—Standards of Performance for
Primary Aluminum Reduction Plants
16. Section 60.190 is revised as fol-
lows:
§ 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.
(b) Any faculty under paragraph (a)
of this section that commences con-
struction or modification after October
23, 1974, is subject to the requirements
of this subpart. •
Subpart T—Standards of Performance for
the Phosphate Fertilizer Industry: Wet-
Process Phosphoric Acid Plants
17. Section 60.200 is revised as fol-
lows:
§60.200 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply Is each
wet-process phosphoric acid plant For
the purpose of this subpart the affected
facility includes any combination of:
reactors, filters, evaporators, and hot-
wells.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
22, 1974, Is subject to the requirements
.of this subpart.
Subpart U—Standards of Performance for
the Phosphate Fertilizer Industry: Super-
phosphoric Acid Plants
18. Section 60.210 is revised as fol-
lows:
§ 60.210 Applicability and designation
of affected facility..
(a) The affected facility to which the
provisions of this subpart apply is each
superphosphorlc acid plant For the
purpose of this subpart, the affected
facility Includes any combination of:
evaporators, hotwells, add sumps, and
cooling tanks.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
,22, 1974, Is subject to the requirements
this subpart
Subpart V—Standards of Performance for
the Phosphate Fertilizer Industry: Diam-
monlum Phosphate Plants
19. Section 60.220 Is revised as fol-
lows:
§ 60.220 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply Is each
granular diammonium phosphate plant.
For the purpose of this subpart, the af-
fected facility Includes any combination
of: reactors, granulators, dryers, coalers,
screens, and mills.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, Is subject to the requirements of
this subpart.
Subpart W—Standards of Performance for
the Phosphate Fertilizer Industry: Triple
Superphosphate Plants
20. Section 60.230 Is revised as follows:
§ 60.230 Applicability and designation
of affected facility.
(a> The affected facility to which the
provisions of this subpart apply is each
triple superphosphate plant. For the pur-
pose of this subpart, the affected facility
Includes any combination of: mixers,
curing belts (dens), reactors, granula-
tors, dryers, cookers, screens, mills, and
facilities which store run-of-pile triple
superphosphate.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, Is subject to the requirements of
this subpart.
Subpart X—Standards of Performance for
the Phosphate Fertilizer Industry: Gran-
ular Triple Superphosphate Storage
Facilities
21. Section 60.240 is revised as follows:
§60.240 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of tills subpart apply is each
granular triple superphosphate storage
facility. For the purpose of this subpart,
the affected facility includes any combi-
nation of: storage or curing piles, con-
veyors, elevators, screens, and mills.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, Is subject to the requirements of
this subpart.
Subpart Y—Standards of Performance for
Coal Preparation Plants
22. Section 60.250 is revised as follows:
§ 60.250 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to any of the following af-
fected facilities in coal preparation
plants which process more than 200 tons
per day: thermal dryers, pneumatic coal-
cleaning equipment (air tables), coal
processing and conveying equipment (In-
cluding breakers and crushers), coal
storage systems, and coal transfer and
loading systems.
(Sees. Ill and 801 (a). Clean Air Act M
amended («3 UB.C. lM7o-«, lM7g(a».)
(FB Doc.77-31930 Filed 7-23-77:8:46 «m]
FEDERAL REGISTER. VOL 42, NO. 143—MONDAY, JULY 25, 1977
V-167
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65 ___
TWe 40 — Protection of UM Environment
CHAPTER I— ENVIRONMENTAL
PROTECTION AGENCY
IFHL 742-6]
PART 60— STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Petroleum Refinery Fluid Catalytic Cracking
Unit Catalyst Regenerators
Correction
In PR Doc. 77-18129, appearing at
page 32426, in Part VI of the Issue of Fri-
day, June 24, 1977, the EFFECTIVE
DATE should be changed to read "June
24. 1977".
(PRL-763-9Q
PART 60— STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Units and Abbreviations
Correction
ID FR Doc. 77-20557, appearing on
page 37000 In the issue for Tuesday,
July 19, 1977, in the second column.
I «0.3(a) should be changed so that the
last abbreviation reads as follows:
"ft — mlcrognun — 10-* gram".
RULES AND REGULATIONS
66
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Petroleum Refinery Fluid Catalytic Cracking
Unit Catalyst Regenerators; Correction
AGENCY: Environmental Protection
Agency.
ACTION: Correction.
SUMMARY: This document corrects the
final rule that appeared at page 32425 in
the FEDERAL REGISTER of Friday, June 24,
1977 (FR Doc. 77-18129).
EFFECTIVE DATE: August 4,1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone 919-541-5271.
Dated: July 29,1977.
ERIC O. STORK,
Acting Assistant Administrator
tor Air and Waste Management.
In FR Doc. 77-18129 appearing on
page 32425 in the FEDERAL REGISTER of
Friday, June 24, 1977, 55 60.102»«. *«»UST is. 1977
FEDERAL REGISTER, VOL. 42,
V-168
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68
RULES AND REGULATIONS
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
[PRL 776-t]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61—NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Authority Citations; Revision
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action revises the au-
thority citations tor Standards of Per-
formance for New Stationary Sources
and National Emission Standards for
Hazardous Air Pollutants. The revision
adopts a method recommended by the
FEDERAL REGISTER for identifying which
sections are enacted under which statu-
tory authority, making the citations
more useful to the reader.
EFFECTIVE DATE: August 17, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
• Triangle Park, N.C. 27711, telephone
919-541-5271.
SUPPLEMENTARY INFORMATION:
This action is being taken in accordance
with the requirements of 1 CFR 21.43
and is authorized under section 301 (a)
of the Clean Air Act, as amended, 42
U.S.C. 1857g(a). Because the amend-
ments are clerical in nature and affect
no substantive rights or requirements,
the Administrator finds it unnecessary
to propose and invite public comment.
Dated: August 12,1977.
DOUGLAS M. COSTLK,
Administrator.
Parts 60 and 61 of Chapter I. Title 4fl
of the Code of Federal Regulations are
revised as follows:
1. The authority citation following the
table of sections In Part 60 it revised to
read as follows:
AOTHOHITT: See. Ill, 3Ol(a) of the Ciena
Air Act a> amended (43 U.8.C. 1867O-6. 18»7f
(a)), unleu otherwise noted.
2. Following li 60.10 and 60.24(g) the
following authority citation is added:
(Sec. 116 of the Clean Air Act as amended
(42 C.&C. 1867d-l).)
3. Following §5 60.7. 60.8, 60.0, 60.11.
60.13, 60.45. 60.46, 60.53, 60.54. 60.63.
60.64, 60.73. 60.74, 60.84, 60.85, 60.93,
60.105. 60.106, 60.113, 60.123, 60.133.
60.144. 60.153, 60.154. 60.165, 60.166,
60.175, 60.176, 60.185, 60.186, 60.194.
60.195, 60.203. 60.204, 60.213. 60.214.
60.223. 60.224. 60.233. 60.234, 60.243,
60.244, 60.253. 60.254, 60.264, 60.26*.
60.266, 60.273, 60.274, 60.275 and Ap-
pendices A, B, C, and D, the following
authority citation is added:
(Sec. 114 of the Clean Air Act u amended
(42 U.S.C. 1857C-B).) .
4. The authority citation following the
table of sections in Part 61 is. revised to
read as follows:
AUTHORITY: Sec. 113, 301 (a) of the Clean
Air Act as amended (43 U.8.C. 1857C-7, 18i7g
(a)), unless otherwise noted.
5. Following I 61.16, the following au-
thority citation is added:
(Sec. 116 of the Clean Air Act as amende*
(42 O.S.C. 1857d-l).)
6. Following §5 61.09. 61.10. 61.12.
61.13, 61.14, 61.15. 61.24, 61.33, 61.34,
61.43, 61.44, 61.53, 61.54. 61.55. 61.67.
61.68, 61.69, 61.70, 61.71, and Appendices
A and B, the following authority citation
1-. added:
(Sec. 114 of the Clean Air Act as amended
(43 UJ3.C. 1857C-0).)
(FB Doc.77-23837 Filed 8-16-77:8:41 am]
FEDERAL REGISTER, VOL 41, NO. 159—WEDNESDAY, AUGUST 17, 1»77
V-169
-------
RULES AND REGULATIONS
69
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Revision to Reference Method* 1-8
AGENCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: This rule revises Reference
Methods 1 through 8, the detailed re-
quirements used to measure emissions
from affected facilities to determine
whether they are In compliance with a
standard of performance. The methods
were originally promulgated December
23, 1971, and since that time several re-
visions became apparent which would
clarify, correct and Improve the meth-
ods. These revisions make the methods
easier to use, and Improve their accuracy
and reliability.
EFFECTIVE DATE: September 19,1977.
ADDRESSES: Copies of the comment
letters are available for public Inspection
and copying at the U.S. Environmental
Protection Agency, Public Information
Reference Unit (EPA Library), Room
2922, 401 M Street, S.W., Washington.
D.C. 20460. A summary of the comments
and EPA's responses may be obtained
upon written request from the EPA Pub-
lic Information Center (PM-215), 401
M Street, S.W., Washington, D.C. 20460
(specify "Public Comment Summary:
Revisions to Reference Methods 1-8 in
Appendix A of Standards of Performance
for New Stationary Sources").
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone No. 919-541-5271.
SUPPLEMENTARY INFORMATION:
The amendments were proposed on June
8.1976 (40 FR 23060). A total of 55 com-
ment letters were received during the
comment period—34 from industry, 15
from governmental agencies, and 6 from
other Interested parties. They contained
numerous suggestions which were Incor-
porated in the final revisions.
Changes common to all eight of the
reference methods are: (1) the clarifica-
tion of procedures and equipment spec-
ifications resulting from the comments,
(2) the addition of guidelines for al-
ternative procedures and equipment to
make prior approval of the Administra-
tor unnecessary and (3) the addition of
an Introduction to each reference meth-
od discussing the general use of the
method and delineating the procedure
for using alternative methods and equip-
ment.
Specific changes to the methods are:
METHOD 1
1. The provision for the use of more
than two traverse diameters, when spec-
ified by the Administrator, has been
deleted. If one traverse diameter Is In a
plane containing the greatest expected
concentration variation, the intended
purpose of the deleted paragraph will be
fulfilled.
2. Based on recent data from Fluldyne
(Particulate Sampling Strategies for
Large Power Plants Including Nonunl-
form Flow, EPA-600/2-76-170, June
1976) and Entropy Environmentalists
(Determination of the Optimum Number
of Traverse Points: An Analysis of
Method 1 Criteria (draft), Contract No.
68-01-3172), the number of traverse
points for velocity measurements has
been reduced and the 2:1 length to width
ratio requirement for cross-sectional lay-
out of rectangular ducts has been re-
placed by a "balanced matrix" scheme.
3. Guidelines for sampling in stacks
containing cyclonic flow and stacks
smaller than about 0.31 meter In diam-
eter or 0.071 m1 in cross-sectional area
will be published at a later date.
4. Clarification has been made as to
when a check for cyclonic flow is neces-
sary; also, the suggested procedure for
determination of unacceptable flow con-
ditions has been revised.
METHOD 2
1. The calibration of certain pitot tubes
has been made optional. Appropriate con-
struction and application guidelines have
been Included.
2. A detailed calibration procedure for
temperature gauges has been Included.
3. A leak check procedure for pitot
lines has been included.
METHOD 3
1. The appiicablility of the method has
been confined to fossil-fuel combustion
processes and to other processes where it
has been, determined that components
other than Oi, CO,, CO, and N, are not
present in concentrations sufficient' to
affect the final results.
2. Based on recent research informa-
tion (Particulate Sampling Strategies for
Large Power Plants Including Nonuni-
form Flow, EPA-600/2-76-170, June
1976), the requirement for proportional
sampling has been dropped and replaced
with the requirement for constant rate
sampling. Proportional and constant rate
sampling have been found to give essen-
tially the same result.
3. The "three consecutive" require-
ment has been replaced by "any three"
for the determination of molecular
weight, COi and O,.
4. The equation for excess air has been
revised to account for the presence of CO.
5. A clearer distinction has been made
between molecular weight determination
and emission rate correction factor
determination.
6. Single point, integrated sampling
has been included.
METHOD 4
1. The sampling time of 1 hour has
been changed to a total sampling tune
which will span the length of time the
pollutant emission rate Is being deter-
mined or such time as specified in an
applicable subpart of the standards.
2. The requirement for proportional
sampling has been dropped and replaced
with the requirement for constant rate
sampling.
3. The leak check before the test run
has been made optional; the leak check
after the run remains mandatory.
METHOD 5
1. The following alternatives have
been included in the method:
a. The use of metal probe liners.
b. The use of other materials of con-
struction for filter holders and probe
liner parts.
c. The use of polyethylene wash bot-
tles and sample storage containers.
d. The use of desiccants other than
silica gel or calcium sulfate, when
appropriate.
e. The use of stopcock grease other
than silicone grease, when appropriate.
f. The drying of filters and probe-filter
catches at elevated temperatures, when
appropriate.
g. The combining of the filter and
probe washes into one container.
2. The leak check prior to a test run
has been made optional. The post-test
leak check remains mandatory. A meth-
od for correcting sample volume for ex-
cessive leakage rates has been included.
3. Detailed leak check and calibration
procedures for the metering system have
been included.
METHOD. 6
1. Possible interfering agents of the
method have been delineated.
2. The options of: (a) using a Method
8 impinger system, or (b) determining
SO, simultaneously with particulate
matter, have been Included In the
method.
3. Based on recent research data, the
requirement for proportional sampling
has been dropped and replaced with the
requirement for constant rate sampling.
4. Tests have shown that isopropanol
obtained from commercial sources oc-
casionally has peroxide impurities that
will cause erroneously low SO, measure-
ments. Therefore, a test for detecting
peroxides in isopropanol has been In-
cluded in the method.
5. The leak check before the test run
has been made optional; the leak check
after the run remains mandatory.
6. A detailed calibration procedure for
.the metering system has been Included
in the method.
METHOD 7
1. For variable wave length spectro-
. photometers, a scanning procedure for
determining the point of maximum ab-
sorbance has been incorporated as an
option.
METHOD 8
1. Known interfering compounds have
been listed to avoid misapplication of
the method.
2. The determination of filterable
particulate matter (including acid mist)
simultaneously with SO, and SO2 has
been allowed where applicable.
3. Since occasionally some commer-
cially available quantities of isopropanol
FEDERAL REGISTER, VOL. 42, NO. 160—THU.jiMY, AUGUST 18, 1977
V-170
-------
tULES AND KEGULATrONS
have peroxide impurities that wffl cause
erroneously high sulfurtc add mist meas-
urements, a test for peroxides to Isopro-
panol has been Included In the method.
4. The gravimetric technique for mois-
ture content (rather than volumetric)
has been specified because a mixture of
Isopropyl alcohol and water will have a
volume less than the sum of the volumes
of Its content.
5. A closer. correspondence has been
made between similar parts of Methods
8 and 5.
MISCELLANEOUS
Several commenters questioned the
meaning of the term "subject to the ap-
proval of the Administrator" In relation
to using alternate test methods and pro-
cedures. As denned In 5 60.2 of subpart
A, the "Administrator" Includes any au-
thorized representative of the Adminis-
trator of the Environmental Protection
Agency. Authorized representatives are
EPA officials In EPA Regional Offices or
State, local, and regional governmental
officials who have been delegated the re-
sponsibility of enforcing regulations un-
der 40 CPR 60. These officials in consulta-
tion with other staff members familiar
with technical aspects of source testing
will render decisions regarding accept-
able alternate'test procedures.
In accordance with section 117 of the
Act, publication of these methods was
preceded by consultation with appropri-
ate advisory committees, Independent
experts, and Federal departments, and
agencies.
(Sees. Ill, 114 and 301 (a) of the Clean Air
Act, «ec. *(*) of Pub. L. No. 01-604, «4 Stat,
1883; sec. i(a) of Pub. L. MO. 91-604, 84 Slat.
1087; sec. 2 of Pub. L. No. 90-148, 81 Stat. 604
(42 UJ3.C. 1867C-6, 1B57C-9, 1857g(a».)
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
pnparatlon of an Economic Impact Analyrts
under Executive Orders 11831 and 11949 and
OMB Circular A-107.
Dated: August 10,1977.
DOUGLAS M. COSTLE,
• Administrator.
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
by revising Methods 1 through 8 of Ap-
pendix A—Reference Methods as
follows:
APPEND!* A—REFERENCE METHODS
The reference methods in this appendix arc referred to
in 160.8 (Performance Tests) and 440.11 (Compliance
With Standards and Maintenance Requirements) of 40
CFB Part 80, Subpart A (General Provisions). Specific
uses of these reference methods are described fn the
standards of performance contained In the subparu,
beginning with Subpart D..
Wltliin each standard of performance, a section titled
"Test Methods ami Procedures" Is provided to (1)
Identify the test methods applicable to the facility
subject to the respective standard and (2) identify any
special instructions or conditions to be followed when
applying a method to the respective facility. Such in-
structions (for example, establish sampling rates, vol-
umes, or temperatures) are to be used either in addition
to, or as a substitute for procedures in a reference method.
Similarly, for sources subject to emission monitoring
requirements, specific instructions pertaining to any use
of a reference method are provided in the subpart or in
Appcndii B.
f methods In this appendix b not intended
M an endorsement of denial of their applicability to
•Booroes that are not subject to standards of performance.
The methods are potentially, applicable to other sourom;
however, applicability should be confirmed by careful
and appropriate evaluation of the conditions prevalent
at such sources.
The approach followed in the formulation of the ref-
erence methods involves specifications for equipment,
procedures, and performance. In concept, a performance
specification approach would be preferable in all methods
- because this allows the greatest flexibility to the user.
In practice, however, this approach is impractical in most
cases because performance specifications cannot be
established. Most of the methods described herein,
therefore, Involve specific equipment specifications and
procedures, and only a few methods in this appendix rely
on performance criteria.
Minor changes in the reference methods should not
necessarily affect the validity of the results and it Is
recognised that alternative and equivalent methods
exist. Section 60.8 provides authority for the Administra-
tor to specify or approve (1) equivalent methods, (2)
alternative methods, and (8) minor changes in the
methodology of the reference methods. It should be
clearly understood that unless otherwise identified all
such methods and changes must have prior approval of
the Administrator. An owner employing such methods or
deviations from the reference methods without obtaining
prior approval does so at the risk of subsequent diiap-
• proval and retesting with approved methods.
Within the reference methods, certain specific equip-
ment or procedures are reoogniied as being acceptable
or potentially acceptable and are specifically identified
in the methods. The items Identified as acceptable op-
tions may be nsed without approval but mnst be identi-
fied in the test report. The potentially approvable op-
tions are cited as "subject to the approval of the
Administrator" or as "or equivalent." Such potentially
approvable techniques or alternatives may be used at the
discretion of the owner without prior approval. However,
detailed descriptions for applying these potentially
approvable techniques or alternatives are not provided
In the reference methods. Also, the potentially approv-
able options are not necessarily acceptable in all applica-
tions. Therefore, an owner electing to use such po-
tentially approvable techniques or alternatives is re-
sponsible for: (1) assuring that the techniques or
alternatives are in fast applicable and are properly
executed; (2) including a written description of tin
alternative method In the tost report (the written
method most be clear and must be capable of being per-
formed without additional instruction, and the decree
of detail should be similar to the detail contained in the
reference methods); and (3) providing any rationale or
supporting data necessary to show the validity of the
alternative in the particular application. Failure to
meet these requirements can result In the Adminis-
trator's disapproval of the alternative.
METHOD 1—SAMPLE AND VELOCITY TRAVERSES FOE
STiTlONAET SOCECE8
1. Principli and Applicability
1.1 Principle. To aid in the representative measure-
ment of pollutant emissions and/or total volumetric flow
rate from a stationary source, a measurement site wnere
the effluent stream is flowing In a known direction to
selected, and the cross-section of the stack Is divided Into
a number of equal areas. A traverse point is then located
within each of these equal areas.
1.2 Applicability. This method Is applicable to flow-
ing J«s streams in ducts, stacks, and flues. The method
tannot be used when: (1) flow Is cyclonic or swirling (we
Section 2.4), (2) a stack is smaller than about 0.30 meter
(12 in.) in diameter, or 0.071 m> (113 In.') In cross-eec-
tional area, or (3) the measurement site is less than two
stack or duct diameters downstream or less than a half
diameter upstream from a Sow disturbance.
The requirements of this method must be considered
before construction of a new facility from which emissions
will be measured; failure to do so may require subsequent
alterations to the stack or deviation from tbe standard
procedure. Cases Involving variants are subject to ap-
proval by the ' Administrator, U.S. Environmental
Protection Agency.
2. Procedure
2.1 Selection of Measurement Site. Sampling or
velocity measurement la performed at a site located at
least eight stack or duct diameters downstream and two
diameters upstream from any flow disturbance soon as
• bend, expansion, or contraction in the stack, or from a
visible flame. If necessary, an alternative location may
be selected, at a position at least two stack or duct di-
ameters downstream and a half diameter upstream from
any flow disturbance. For a rectangular cross section,
an equivalent diameter (D,) shall be calculated from tbe
following equation, to determine the upstream and
downstream distances:
2LW
L+W
rSDEtAl tKISTH, VOL 4J, NO. lio—THUISOAY, AUGUST It. 1977
TW_171
-------
RULES AND REGULATIONS
50
0.5
DUCT DIAMETERS UPSTREAM FROM FLOW DISTURBANCE (DISTANCE A)
1.0 1.5 2.0
2.5
I
I
I
40
2
LLJ
in
ffi
DISTURBANCE
MEASUREMENT
I- SITE
^ .30
ec
s
2
1 20
z
s
s
i 10
DISTURBANCE
* FROM POINT OF ANY TYPE OF
DISTURBANCE (BEND, EXPANSION, CONTRACTION, ETC.)
I
1
I
3456789
DUCT DIAMETERS DOWNSTREAM FROM FLOW DISTURBANCE (DISTANCE B)
Figure 1-1. Minimum number of traverse points for paniculate traverses.
10
where £=length and W-wldth.
2.2 Determining the Number of Traverse Points.
2.2.1 Paniculate Traverses. When the eight- and
two-diameter criterion can be met, the minimum number
of traverse points shall be: (1) twelve, (or circular or
rectangular stacks with diameters (or equivalent di-
ameters) greater than 0.61 meter (24 in.); (2) eight, (or
circular stacks with diameters between 0.30 and 0.61
meter (12-24 in.); (3) nine, (or rectangular stacks with
equivalent diameters between 0.30 and 0.61 meter (12-24
in.).
When the eight- and two-diameter criterion cannot be
met, the minimum number o( traverse points is deter-
mined from Figure 1-1. Before referring to the figure,
however, determine the distances (rom the chosen meas-
urement site to the nearest upstream and downstream
disturbances, and divide each distance by the stack
diameter or equivalent diameter, to determine tho
distance in terms of the number of duct diameters. Then,
determine from Figure 1-1 the minimum number of
traverse points that corresponds: (I) to the number o(
duct diameters upstream; and (2) to the number of
diameters downstream. Select the higher o( the two
minimum numbers of traverse points, or a greater value,
so that for circular stacks the number is a multiple of 4,
and for rectangular stacks, the number is oue of those
shown in Table 1-1.
TART.E 1-1. Croti-iectional layout fur rectangular itaeki
Ma-
trix
•Kn-
out
: 3l3
4x3
4x4
5x4
5x5
6x5
6x8
7x8
7x7
dumber of traverse poiittt:
12..
16..
20-..
25..
30..
36..
42..
49..
FEDERAL .REGISTER, VOL. 42, NO. 160—THURSDAY, AUGUST 18, 1977
IV-172
-------
50
0.5
RULES AND REGULATIONS
DUCT DIAMETERS UPSTREAM FROM FLOW DISTURBANCE (DISTANCE A)
1.0 1.5 2.0
2.5
o
a.
UJ
V)
30
-20
z
z 10
I
I
I
I
I
^ ^DISTURBANCE
MEASUREMENT
I- 7— SITE
DISTURBANCE
I
J_
! 3 4 5 6 78 9 10
DUCT DIAMETERS DOWNSTREAM FROM FLOW DISTURBANCE (DISTANCE R)
Figure 1-2. Minimum number of traverse points for velocity (nonparticulate) traverses.
2.2.2 Velocity (Non-Particulat*) Traverses. When
velocity or volumetric flow rate is to be determined (but
not particular matter), the same procedure as tbat for
paniculate traverses (Section 2.2.1) is followed, except
that Figure 1-2 may be used Instead of Figure 1-1.
2.3 Cross-Sectional Layout and Location of Traverse
Points.
2.3.1 Circular Stacks. Locate the traverse points on
two perpendicular diameters adcordiiig to Table 1-2 and
the example shown in Figure 1-3. Any equation (for
examples, see Citations '2 and 3 in the Bibliography) that
gives the same values as those in Table 1-2 may be used
in lieu of Table 1-2.
For particulate traverses, one of the diameters must be
In a plane containing the greatest expected concentration
variation, e.g., after bends, one diameter shall be In the
plane of the bend. This requirement becomes less critical
as the distance from the disturbance increases; therefore,
ether diameter locations may be used, subject to approval
• of the. Administrator.
In addition, for stacks having diameters greater than
0.61 in (24 In.) no traverse points shall be located within
2.5 centimeters (1.00 In.) of the stack walls; and for stack
diameters equal to or less than 0.61 m (24 in.), no traverse
points shall be located within 1.3 cm (0.60 in.) of the stack
walls. To meet these criteria, observe the procedures
given below.
2.3.1.1 Stacks With Diameters Greater Than 0.61 m
(24 in.). When any of the traverse points as located in
Section 2.3.) fall within 2.6cm U.OOin.) of the slack walls,
relocate them away frum the stack walls to: (1) a distance
of 2.5 cm (1.00 in.); or (2) a distance equal to the nozzle.
inside diameter, whichever is larger. These relocated
traverse points (on each end of a diameter) shall be tbo
"adjusted" traverse points.
Whenever two successive traverse points are combined
to form a single adjusted traverse point, treat the ad-
Justed point as two separate traverse points, botb in the
sampling (or velocity measurement) procedure, and in
recording the data.
ftDNAL REGISTER, VOL. 42, NO. 16O—THURSDAY, AUGUST 1*. 1977
V-173
-------
RULB AND REGULATIONS
TRAVERSE
POINT
1
2
3
4
5
S
Figure 1-3. Example showing circular stack cross section divided into
12 equal areas, with location of traverse points indicated.
a> In stacki haviag t^.nti^i inlets or other duct con-
tjrontloBi which tend to Induce swirling; In these
instance!, the presence or absence of cyclonic flow at
the sampling location must be determined. The following
techniques are acceptable for this determination.
0
o
o
o
r
o
r—
o
o
.
o
0
o
o
Figure 1-4. Example showing rectangular stack cross
section divided into 12 equal areas, with a traverse
point at centroid of each area.
Table 1-2. LOCATION OF TRAVERSE POINTS IN CIRCULAR STACKS
(Percent of stack diameter from inside wall to traverse point)
Traverse
point
number
on a •
diameter
1
2
3
4|
5'
6
7
8
9
10
11
12J
13
14
15
16
J7
18
19
20!
21
22
' 23
24
• Number of traverse points on a diameter
2
14.6
85.4
4
6.7
25.0
75.0
93.3
6
4.4
14.6
29.6
70.4
85.4
95.6
•
8
3.2
10.5
19.4
32.3
67,7
80.6
89.5
96.8
10
2.6
8.2
14.6
22.6
34.2
65.8
77.4
85.4
91.8
97.4
12
2.1
6.7
11.8
17.7
25.0
35.6
64.4
75.0
82.3
88.2
93.3
97.9
14
1.8
5.7
9.9
14.6
20.1
26.9
36.6
63.4
73.1
79,9
85.4
90.1
94.3
98.2
!
16
1.6
4.9
8.5
12.5
16.9
22.0
28.3.
37.5
62.5
71.7
78.0
83.1
87.5
91.5
95'. 1
98.4
18
1.4
4.4
7.5
10.9
14.6
18.8
23.6
29.6
38.2
61.8
70.4
76.4
81.2
85.4
89.1
92.5
95.6
98.6
20
1.3
3.9
•6.7
.9.7
12.9
16.5
20.4
25.0
30.6
38.8
61 .'2
69.4
75.0
79.6.
83.5
87.1
90.3
93.3
96. 1
98.7
22
1.1
3.5
6,0
8.7
11.6
14.6
18.0
21.8
26.2
31.5
39.3
60.7
68.5
73.8
78.2
82.0
85.4
88.4
91.3
94.0
96.5
98.9
24
1.1
3.2
'5.5
7.9
10.5
13.2
16.1
19.4
23.0
27.2
32.3
39.8
60.2
67.7
72.8
77.0
80.6
83.9
86.8
89.5
92.1
94.5
96.8
98.9 ,
2.3.1.2 Stacks With Diameters Equal to or Less Than
0.61 m (24 In.). Follow the procedure In Section 2.3.1.1,
noting only that any "adjusted" points should be
relocated away from the stack walls to: (I) a distance of
1.3 cm (0.50 in.); or (2) a distance equal to the noule
Inside diameter, whichever Is larger.
2.3.2 Rectangular Stacks. Determine the number
of traverse points as explained In Sections 2.1 and 2.2 of
this method. From Table 1-1, determine the grid con-
figuration. Divide the stack cross-section Into as many
equal rectangular elemental areas as traverse polnta,
and then locate a traverse point at the centroid of each
equal area according to the example in Figure 1-4.
The situation of traverse points being too close to the
stack walls Is not expected to arise with rectangular
stacks. If this problem should ever arise, the Adminis-
trator must be contacted for resolution of the matter.
2.4 Verification of Absence of Cyclonic Plow. In most
stationary sources, the direction of stack gaa flow is
essentially parallel- to the stack walls. However,
cyclonic flow may exist 0) after such devices as cyclones
and Inertlal demisters following venturl scrubbers, or
Level and zero the manometer. Connect a Type 8
pitot tube to the manometer. Position the Type 8 pilot
tube at each traverse point, in succession, so that the
planes of the face openings of the pitot tube are perpendic-
ular to the stack cross-sectional plane: when the Type 8
pitot tube is in this position, it Is at "0° reference." Note
the differential pressure (Ap) reading at each traverse
point. If a null (zero) pitot reading is obtained at 0*
reference at a given traverse point, an acceptable Stow
condition exists at that point. If tbe pitot reading Is not
zero at 0° reference, rotate the pitot tube (up to ±90* yaw
angle), until anon reading isobtalned. Carefully deUrmino
and record the value of the rotation angle (a) to the
nearest degree. After the null technique has been applied
at each travrse point, calculate the average of the abso-
lute values of a; assign a values of 0° to those points for
which no rotation was required, and include these m the
overall average. If the average Value of a Is greater than
10°, the overall flow condition in the stack is unacceptable
and alternative methodology, subject to the approval of
the Administrator, must be used to perform accurate
sample and velocity traverses.
3. Bibliofraplti
1. Determining Dust Concentration in a Qas Stream.
A3ME. Performance Test Code No. 27. New York.
1957.
• 2. Devorkln, Howard, et at Air Pollution Source
Testing Manual. Air Pollution Control District. Los
Angeles, CA. November 1963
3. Methods for Determination of Velocity, Volume,
Dust and Mist Content of Oases. Western Precipitation
Division of Joy Manufacturing Co. Los Angeles, CA.
Bulletin WP-50.1968.
4. Standard Method for Sampling Stacks for Paniculate
Matter. In: 1971 Book of ASTM Standards, Part 23.
ASTM Designation D-2928-71. Philadelphia, Pa. 1971.
S. Hanson, H. A., et al. Paniculate Sampling Strategies
for Large Power Plants Including Nonuniform Flow.
USEPA, ORD, ESRL, Research Triangle Park, N.C.
EPA-600/2-76-170. June 1976.
6. Entropy Environmentalists, Inc. Determination of
the Optimum Number of Sampling Points: An Analysis
of Method 1 Criteria. Environmental Protection Agency.
Research Triangle Park, N.C. EPA Contract No. 68-01-
3172, Task 7.
METHOD 2—DETERMINATION OF STACK OAS VELOCITY
AND VOLUMETRIC FLOW RATE (TYPE S PITOT TUBE)
1. Prlnclpk 7
• V-174
-------
RULES AND REGULATIONS
1.90-2.S4 cm*
(0.75 -1.0 in.)
^./Ir
t^^^S^SSg^£fSSuSf^O^^
t 7.62 cm (3 in.)*
«-| TEMPERATURE SENSOR
LEAK-FREE
CONNECTIONS
•SUGGESTED (INTERFERENCE FREE)
PITOT TUBE • THERMOCOUPLE SPACING
Figure 2-1. Type S pitot tube manometer assembly.
2.1 Type 8 Pitot Tube. The Type 8 pitot tobe
(Figure 2-1) shall be mode of metal tubing (e.g., stain-
Jess steel). It IB recommended that the external tubing
diameter (dimension Di, Figure 2-2b) be between 0.48
and 0.95 centimeters (*i« and 'A Inch). There shall be
an equal distance from the base of each leg of the pitot
tube to its face-opening plane (dimensions Pi and Ft,
Figure 2-2b); It Is recommended that this distance be
between 1.06 and 1.60 times the external tubing diameter.
The face openings of the pitot tube shall, preferably, be
aligned as shown In Figure 2-2; however, slight misalign-
ments of the openings are permissible (see Figure 2-3).
The Type 8 pitot tube shall have a known coefficient,
determined as outlined in Section 4. An Identification
number shall be assigned to the pilot tube; this number
•ban be permanently marked or engraved on the body
of the tube.
NDMAl HOISTH, VOL. 4S, NO. 140—THURSDAY, AUGUST 1«, 1977
IV-175
-------
RUIES AND REGULATIONS
TRANSVERSE
TUBE AXIS
FACE
•OPENING
PLANES
(a)
A SIDE PLANE
LONGITUDINAL Y_ Ot
TUBE AXIS
B
T
B-SIDE PLANE
(b)
-- I
PB \
NOTE:
1.05Dt<
A ORB
(c)
Figure 2-2. Properly constructed Type S pilot tube, shown
in: (a) end view; face opening planes perpendicular to trans-
verse axis; (b) top view; face opening planes parallel to lon-
gitudinal axis; (c) side view; both legs of equal length and
centerlines coincident, when viewed from both sides. Base-
line coefficient values of 0.84 may be assigned to pitot tubes
coristructed this way.
FEOUAL lECISTER, VOL 49, NO. 160—THURSDAY, AUGUST », 1977
V-176
-------
TRANSVERSE
TUBE AXIS "
RULES AND REGULATIONS
I <»> i
LONGITUDINAL
TUBE AXIS
(t)
••-€•
t •
r
(f)
(l)
Figure 2-3. Types of face-opening misalignment that can result from field use or im-
proper construction of Type S pitot tubes. These will not affect the baseline value
of.Cp(s) so long as ai and 02 < 10°, 01 and 02 < 5°. z < 0.32 cm (1/8 in.) and w <
0.08 cm (1/32 in.) (citation 11 in Section 6).
•fBERAl REGISTH, VOL. 42, NO. 160—THURSDAY, AUGUST 18, 1977
V-177
-------
RULES AND REGULATIONS
A standard pltot tube may be used Instead of •Type 8,
provided that it meets the sperificaltnnj of Sections 2.7
anil 4.-.'; note, however, that the static and impact
pressure holes of standard pilot tubes are susceptible to
.limping In particulate-laden cos streams. Therefore,
whenever a standard pilot tube is used to perform a
traverse, adequate proof must lie furnished that the
openings of the pilot tube have not plupeed up during the
traverse period; this ean be done by taking a velocity
head t*i* reading at the final traverse pmiil. cleaning out
the imiwt and static holes of the standard pilot tube by
••liaek-purfilng" with pressurized air. and then taking
another A;> reading. If the 4p readings made before and
after the air purge arethe same ( tS perrenO. the traverse
is acceptable. Otherwise, reject the run. Note that if Ap
at the final traverse point is unsuitably low, another
point may be selecled. If "back-purging" at regular
intervals is part of the procedure, then comparative Ap
readings shall be taken, as above, for the last two back
purges at which suitably high Ap readings are observed.
•> •' Differential Pressure Gauge. An inclined manom-
eter or equivalent device is used. Most sampling trains
ore equipped with a 10-in. (water column) inclined-
vertical manometer, having 0.01-in. n,O d visions on the
0- to 1-in. Inclined scale, and 0.1-in. HiO divisions on the
1- to 10-in. vertical scale. This type of manometer for
other gauge of equivalent sensitivity) is satisfactory for
the measurement of Ap values as low as 1.3 mm (0.08 in.)
HtO However, a differential pressure gauge of greater
sensitivity shall be used (subject to the approval of the
Administrator), if any of the following is found to be
true: (1) the arithmetic average of all Ap readings at the
traverse points in Ihe slack is less than 1.3 mm (0.06 in.)
HiO; (2) for traverses of 12 or more points, more than 10
percent of the Individual Ap readings are below 1.3 mm
(0.05 in.) HiO; (3) for traverses of fewer than 12 points,
more than one Ap reading is below 1.3 mm (0.06 in.) HiO.
Citation 18 in Section 6 describes commercially available
Instrumentation for the measurcmen t of low-range gas
velocities. . it
As an alternative to criteria (1) through (3) above, the
following calculation may be performed to determine the
necessity of using a more sensitive differential pressure
gauge:
T=-
perature gauge need not be attached to the pi tot tube;
this alternative is subject to the approval of the
Adminlstralor.
2.4 Pressure Probe and Gauge. A piezometer tube and
mercury- or water-tilled U-tube manometer capable of
measuring stack pressure to within 2.5 mm (0.1 in.) Hg
is used. The static tap of a standard type pitot tube or
one leg of a Type X pitot tube with the face opening
planes positioned parallel to the gas flow may also be
used as the pressure probe.
2.5 Barometer. A mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to
within 2.5 mm Ilg (0.1 in. Ilg) may be used. In many
cases, the barometric reading may be obtained from a
nearby national weather service station, In which case
the station value (which Is the absolute baromctrio
pressure) shall be requested and an adjustment for
elevation differences between the weather station and
the sampling point shall be applied at a rate of minus
2.5 mm (0.1 In.) Ilg per 30-meter (100 foot) elevation
Increase, or vice-versa for elevation decrease.
2.6 Gas Density Determination Equipment. Method
3 equipment, If needed (see Section 3.6), to determine
the stack gas dry molecular weight, and Reference
Method 4 or Method 5 equipment for moisture content
determination; other methods may be used subject to
approval of the Administrator,
2.7 Calibration FItot Tube. When calibration of the
Type 8 pltot tube Is necessary (see Section 4), a standard
pitot turn Is used as a reference. The standard pltot
tube shall, preferably, have a known coefficient, obtained
either (1) directly from the National Bureau of Stand-
ards, Route 270, Quince Orchard Road, Gaithersburg,
Maryland, or (2) by calibration against another standard
pltot tube with an NBS-traccable coefficient. Alter-
natively, a standard pitot tube designed according to
the criteria given in 2.7.1 through 2.7.5 below and illus-
trated In Figure 2-4 (see also Citations 7, 8, and 17 In
Section 6) may be used. Fitot tubes designed according
to these specifications will have baseline coelOclents of
about O.WiO.Ol.
2.7.1 Hemispherical (shown in Figure2-4),ellipsoidal,
or conical tip.
2.7.2 A minimum of six diameters straight run (based
upon D, the external diameter of the tube) between the
tip and the static pressure holes.
2.7.3 A minimum of eight diameters straight run
between the static pressure holes and the centerline of
the external tube, following the 90 degree bend.
2.7.4 Static pressure holes of equal size (approximately
0.1 ID, equally spaced in a piezometer ring configuration.
2.7.5 Ninety degree bend, with curved or mitered
Junction.
2.8 Differential Pressure Gauge for Type 8 Pltot
Tube Calibration. An inclined manometer or equivalent
is used. If the single-velocity calibration technique Is
employed (see Section 4.1.2.3), the calibration differen-
tial pressure gauge shall be readable to the nearest 0.1J
mm HiO (0.005 in. H>O). For multlvelocity calibrations,
the gauge shall be readable to the nearest 0.13 mm HtO
(0.005 In HiO) for Ap values between 1.3 and 25 mm HtO
(0.09 and 1.0 In. HiO), and to the nearest 1.3 mm HiO
(0.06 in. HtO) for Ap values above 25 mm HiO (1.0 In.
HiO). A special, more sensitive gauge will be required
to read Ap values below 1.3 mm 11:0 [0.05 in. HiOJ
(see Citation 18 in Section 6).
Ap,=Individual velocity head reading at a traverse
point, mm HiO (in. H.O).
n=Total number of traverse points.
A'=0.13 mm HiO when metric units are used and
0.005 in HiO when English units are used.
If T is greater than 1.05, the velocity head data are
unacceptable and a more sensitive differential pressure
gauge must be used.
NOTE.—If differential pressure gauges other than
Inclined manometers are used (e.g., magnehelic gauges),
their calibration must be checked after each test series.
To check the calibration of a differential pressure gauge,
compare Ap readings of the gauge with those of a gauge-
oil manometer at a minimum of three points, approxi-
mately representing the range of Ap values in the stack.
If, at each point, the values of Ap as read by the differen-
tial pressure gauge and gauge-oil manometer agree to
within S percent, the differential pressure gauge shall b«
considered to be in proper calibration. Otherwise, the
test series shall either be voided, or procedures to adjust
the measured Ap values and final results shall be used,
subject to the approval of the Administralar.
2.3 Temperature Gauge. A thermocouple, liquid-
filled bulb thermometer, bimetallic thermometer, mer-
cury-in-glass thermometer, or other gauge capable of
measuring temperature to within 1.5 percent of the mini-
mum absolute stack temperalure shall be used. The
temperature gauge shall be attached to the pitot tube
such that the sensor tip does not touch any metal; tn»
gauge shall be in an interference-free arrangement with
respect to the pitot tube face openings (see Figure 2-1
and also Figure 2-7 in Section 4). Alternate positions may
be used if the pltot tube-temperature gauge system U
calibrated according to the procedure of Section 4. Pro-
vided that a difference of not more than 1 percent in the
average velocity measurement is introduced, the tern-
CURVED OR
MITERED JUNCTION
HEMISPHERICAL
TIP
Figure 2-4. • Standard pitot tube design specifications.
STATIC
HOLES
3. ProudtHt
3.1 Set up the apparatus as shown in Figuce 2-1.
Capillary tubing or surge tanks Installed between the
manometer and pltot tube may be used to dampen Ap
fluctuations. It is recommended, but not required, that
a pretest leak-check be conducted, as follows: (1) blow
through the pitot Impact opening until at least 7.6 cm
(3 in.) HtO velocity pressure registers on the manometer;
then, close off the impact opening. The pressure shall
remain stable for at least 15 seconds; (2) do the same for
the static pressure side, except using suction to obtain
the minimum of 7.4 cm (3 in.) HtO. Other leak-cheek
procedures, subject to the approval of the Administrator^
may be uaed. - -
3.2 Level and zero the manometer. Because the ma
nometer level and zero may drift due to vibrations and
temperature changes, make periodic checks during the
traverse. Record all necessary data as shown in the
example data sheet (Figure 2-5).
3.3 Measure the velocity head and temperature at the
traverse points specified by Method 1. Ensure that the
proper differential pressure gauge is being used for the
range of Ap values encountered (see Section 2.2). If it is
necessary to change to a more sensitive gauge, do so, and
remeasure the Ap and temperature readings at each tra-
verse point. Conduct a post-test leak-check (mandatory),
as described In Section 3.1 above, to validate the traverse
run.
3.4 Measure the static pressure in the stack. On*
reading is usually adequate.
3.5 Determine the atmospheric pressure.
FEDERAL REGISTER, VOL 4), NO. 160—THURSDAY, AUGUST 1C, 1977
V-178
-------
RULES AND REGULATIONS
PLANT.
DATE.
.RUN NO.
STACK DIAMETER OR DIMENSIONS, m(in.)
BAROMETRIC PRESSURE, mm Hg (in. Hg)_
CROSS SECTIONAL AREA. m2(ft2)
OPERATORS '
PIT.OTTUBEI.D.NO.
AVG. COEFFICIENT,Cp = .
LAST DATE CALIBRATED.
SCHEMATIC OF STACK
CROSS SECTION
Traverse
Pt.No.
Vel.Hd..Ap
mm (in.) H20
y
Stack Temperature
ts.eC{°F)
Avtregt
TS,°K(°R)
pg
mm Hg (in.Hg)
f^p"
Figure 2-5. Velocity traverse data.
KDOAL IfOISTR, VOL. 42, NO. 160—THUtSDAT, AUGUST 18, 1977
V-179
-------
RULES AND REGULATIONS
3.0 Determine the stack gas dry moloouar weight.
For combustion processes or processes that emit essen-
liully COi, O:, CO, and.Ni, use Method 3. For processes
•'milting essentially air, an analysis need not be con-
ilui'ted; use a dry molecular weight ot M.O. For other
processes, other methods, subject to the approval of the
Administrator, must be used.
:!.7 Obtain the moisture content from Reference
Method 4 (or equivalent) or from Method 5.
:l.S Determine the cross-sectional area of the stack
«r duct at the sampling location. Whenever possible,
physically measure the stack dimensions rather than
using blueprints.
4. Calibration
4.1 Typo 9 Pilot Tube. Before its initial use, care- '
hilly examine the Type S pilot tube in top, side, and
end views to verify that the face openings of the tube
nrn aligned within the specifications illustrated In Figure
2-2 or 2-3. The pilot tube shall not be used if it fails to
meet these alignment specifications.
After verifying Ihe face opening alignment, measure
and record the following dimensions of Ihe pitoj tube:
(a) the external tubing diameter (dimension Di, Figure
2-2b); and (b) the base-to-opening plane distance*
(dimensions PA and Pe, Figure 2-2b). If D, is between
0.48 and 0.05 cm (X« and H In.) and if PA and Pa an
equal and between 1 .OS and 1.90 R,, there are two possible
options: (1) Ihe pilot tube may be calibrated according
to the procedure outlined in Sections 4.1.2 through
4.1.5 below, or (2) a baseline (isolated tube) coefficient
value of 0.84 may bo assigned lo Ihe pilot tube. Note,
however, thai if Ihe pilol lube is part of an assembly,
calibration may still be required, despite knowledge
of the baseline coefficient value (see Section 4.1.1).
If D,, PA, and PB are oulside Ihe specified limits, the
pitol tube must be calibrated as outlined in 4.1.2 through
4.1.5 below.
4.1.1 Typo S Pitol Tube Assemblies. During sample
and velocity traverses, the isolated Type S pilot tube is
not always used; in many instances, the pitol tube is
used In combination with other source-sampling compon-
euls (thermocouple, sampling probe, nozile) as part of
an "assembly." The presence of other sampling compo-
nents can sometimes affect the baseline value of the Type
S pilot tube coefficient (Citation 9 in Section 6); therefore
an assigned (or otherwise known) baseline coefficient
value may or may not be valid tor a given assembly. Th»
baseline and assembly coefficient values will be identical,
only when the relative placement ol the components in
the assembly Is such that aerodynamic interference
effects are eliminated. Figures 2-6 through 2-S illustrate
interference-free component arrangements for Type 8
pitol tubes having external tubing diameters between
0.48 and 0.95 cm (ft, and H In.). Type S pilot labe assem-
blies thai fall lo meel any or all of the specifications ot
Figures 2-8 through 2-8 shall be calibrated according to
the procedure outlined In Sections 4.1.2 through 4.1.6
below, and prior lo calibration, the values of the inter-
component spacings (pitot-nonle, pitot-thermocouple,
pitot-protx) sheath) shall be measured and recorded.
NOTE.—Do not use any Type 8 pilot tube assembly
which is constructed such thai Ihe Impact pressure open-
ing plane of the pilot tube Is below Ihe entry plane of UM
nonle (see Figure 2-6b).
4.1.2 Calibration Setup. If the Type 8 pilot tube Is to
be calibrated, one leg of the tube shall be permanently
marked A, and the other, 1. Calibration shall be don* In
a flow system having the following essential design
features:
I
TYPES PITOT TUBE
I
M £1.90 em (3/4 in.) FOR On -1.3 em (1/2 in.)
SAMPLING NOZZLE
A. BOTTOM VIEW; SHOWING MINIMUM PITOT NOZZLE SEPARATION.
SAMPLING
PROBE
1
\
SAMPLING
NOZZLE
E
O
TYPES
PITOT TUBE
NOZZLE ENTRY
PLANE
SIDE VIEW: TO PREVENT PITOT TUBE
FROM INTERFERING WITH GAS FLOW
STREAMLINES APPROACHING THE
NOZZLE. THE IMPACT PRESSURE
OPENING PLANE OF THE PITOT TUBE
SHALL BE EVEN WITH OR ABOVE THE
NOZZLE ENTRY PLANE.
STATIC PRESSURE
OPENING PLANE
IMPACT PRESSURE
OPENING PLANE
Figure 2-6. Proper pitot tube • sampling nozzle configuration to prevent
aerodynamic interference; buttonhook • type nozzle; centers of nozzle
and pitot opening aligned; Dt between 0.48 and 0.95 cm (3/16 and
3/8 in.).
FEDERAL REGISTER, VOL 42, NO. 160—THURSDAY, AUGUST 18, 1977
.V-180
-------
RULES AND REGULATIONS
THERMOCOUPLE
W>7.62em
«
-U-
(3 in.)
'Z ^1.91 cm 0/4 in.)
THERMOCOUPLE
Z> 5.01 cm
U in.)
TYPE SPITOT TUBE
SAMPLE PROBE
I
OR
TYPE S PITOT TUBE
, SAMPLE PROBE
Figure 2-7. Proper thermocouple placement to prevent interference;
Dt between 0.48 and 0.95 cm (3/16 and 3/8 in.).
TYPE SPITOT TUBE
SAMPLE PROBE
Y>7.62cm(3inJ
Figure 2-8. Minimum pitot-sample probe separation needed to prevent interference;
Dt between 0.48 and 0.95 cm (3/16 and 3/8 in.).
4.1.SI The flowing gas stream must be confined to a
duct of definite cross-sectional area, either circular or
rectangular. For circular cross-sections, the minimum
duct diameter shall be 30.5 cm '(12 in.); -for rectangular
cross-sections, the width (shorter side) shall be at least
25.4cm (10in.).
4.1.2.1 The cross-sectional area of the calibration duct
nrost be constant OTer a distance of 10 or more duct
diameters. For a rectangular cross-section, use an equiva-
lent diameter, calculated from the following equation,
to determine the number of duct diameters:
2LW
= (L+W)
vhere:
D,"Equivalent diameter
L— Length
IP-Width
Equation 2-1
To ensure the presence of stable, fully developed flow
patterns at the calibration site, or "lest section," the
site must be located at least eight diameters downstream
and two diameters upstream from the nearest disturb-
ances.
NOTE.—The eight- and two-diameter criteria are not
absolute; other test section locations may be used (sub-
ject to approval of the Administrator), provided that the
flow at the test site is stable and demonstrably parallel
to the duct ails.
4.1.2.3 The flow system shall have the capacity to
generate a test-section velocity around 915 m/rain (3,000
ft/rain). This velocity must be constant with time to
guarantee steady flow during calibration. Note that
Type S pilot tube coefficients obtained by single-velocity
calibration at 915 m/min (3,000 ft/min) will generally be
valid to within =1:3 percent for the measurement of
velocities above 305 m/rain (1,000 ft/min) and to within
±5 to 6 percent for the measurement of velocities be-
tween 180 and 305 m/min (600 and 1,000 ft/min). If a
more precise correlation between Cf and velocity is
desireo, the flow system shall have the capacity to
generate at least four distinct, time-invariant test-section
velocities covering the velocity range from 180 to 1.525
in (600 to 5,000 ft/min), and calibration data shall
m/min
be taken at regular velocity intervals over this range
(see Citations 9 and 14 hi Section 6 for details).
4.1.2.4 Two entry ports, one each for the standard
and Type S pilot tubes, shall be cut In the test section;
the standard pilot entry port shall be located slightly
downstream of the Type 8 port, so that the standard
and Type S impact openings will lie' in the same cross-
sectional plane during calibration. To facilitate align-
ment of the pilot tubes during calibration, it is advisable
that the test section be constructed of plexiglas or some
oilier transparent material.
4.1.3 Calibration Procedure. Note that this procedure
Is a general one and must not be used without first
referring to the special considerations presented in Sec-
tion 4.1.5. Note also that this procedure applies Only to
single-velocity calibration. To oblain calibration data
for the A and B sides of the Type S pitol lube, proceed
as follows:
4.1.3.1 Make sure that the manometer Is properly
filled and thai the oil is free from contaminat ion and is of
the proper density. Inspect and leak-check all pilot lines;
repair or replace it necessary.
4.1.3.2 Level and icro Ihe manometer. Turn on the
tan and allow the flow to stabilize. Seal the Typo S entry
port.
4.1.3.3 Ensure that the manometer Is level and teroed.
Position the standard pilot lube at the calibration point
(determined as outlined ip Sction 4.1.5.1), and align the
tube so that its tip is pointed directly into the flow. Par-
ticular care should be taken in aligning the lube to avoiil
yaw and pilch angles. Make sure that the entry port
surrounding the lube is properly sealed.
4.1.3.4 Read 6pud and record its value in a dala table
similar to the one shown in Figure M. Remove the
standard pilot tube from the duct and disconnect it from
the manometer. Seal the standard entry |wrt.
4.1.3.5 Connect the Type S pitol tube to Hie manom-
eler. Open Ihe Type S entry port. Check the manom-
eter level and zero. Insert and align the Type S pilot tube
so that its A side impact opening is at the same point as
was the standard pilot tube and is pointed directly into
the How. Make sure that the entry port surrounding the
tube is properly sealed.
4.1.3.6 Read Ap. and enter its value in the data table.
Remove the Type S pilot tube from the duct and dis-
connect il from the manometer.
4.1.3.7 Repeal steps 4.1.3.3 through 4.1.3.6 above until
three pairs of Ap readings have been obtained.
4.1.3.8 Repeat steps 4.1.3.3 through 4.1.3.7 above for
the B side of the Ty|ie S pilot tube.
4.1.3.9 Perform calculations, as described in Section
4.1.4 below.
4.1.4 Calculations.
4.1.4.1 For each of the six pairs of Ap readings (i.e.,
three from side A and three from side B) obtained in
Section 4.1.3 above, calculate the value of Ihe Type 8
pilol lube coellicienl as follows:
KMtAL WttSHft, VOL 41, NO.
IV-181
AVOVCT
-------
RULES AND REGULATIONS
PITOT TUBE IDENTIFICATION NUMBER:
CALIBRATED BYf.
.DATE:.
RUN NO.
1
2
3
"A" SIDE CALIBRATION
Apstd
cm HaO '
(in. H20)
Ap(s)
emH20
(in. H20)
Cp (SIDE A)
Cp(s)
DEVIATION
Cp(s)-Cp(A)
RUNUa.
1
i
3
"B" SIDE CALIBRATION
Apstd
emHaO
(In. H20)
AP($)
cmH20
(in. H20)
Cp (SIDE B)
Cp($)
DEVIATION
Cp(j)-Cp(B)
AVERAGE DEVIATION « o(AORB)
S|Cp(s)-Cp(AORB)|
-MUSTBE<0.01
| Cp (SIDE A)-Cp (SIDE B) |-*-MUST BE <0.01
Figure 2-9. Pitot tube calibration data.
wbew
according to the criteria of Sections 2.7.1 to
2.7.5 of this method.
Ap.,j=Velocity bead measured by the standard pltot
tube, cm HK> (In. H,O)
Pn,,„»;„„ n o Ap.=Veloclty head measured by the Type S pltot
liquation 2-2 tuD,p cm HJO (to. HiO)
4.1.4J Calculate C, (dde A), the mean A-dde coef-
4.1.4.3 Calculate the deviation of each of the three A-
side values of C, <•> from C, (side_A ), and the deviation at
each B-slde value of C,
-------
RULES AND REGULATIONS
ESTIMATED
SHEATH
BLOCKAGE
DUCT AREA
x 100
Figure 2-10. Projected-area models for typical pitot tube assemblies.
4.1.6 Field Use and Recalibration.
4.1.6.1 Field Use.
4.1.6.1.1 When a Type 8 pitot tube (isolated tube or
assembly) Is used in the field, the appropriate coefficient
value (whether assigned or obtained by calibration) shall
•be used to perform velocity calculations. For calibrated
Type S pitot tubes, the A side coefficient shall be used
when the A side of the tube faces the flow, and the B side
coefficient shall be used when the B side faces the flow;
alternatively, the arithmetic average of the A and B side
coefficient values may be used. Irrespective of which side
faces the flow.
4.1.6.1.2 When a probe assembly Is used to sample a
small duct (12 to 36 in. in diameter), the probe sheath
sometimes blocks a significant part of the duct cross-
section, causing a reduction in the effective value of
7,(.i. Consult Citation 9 in Section 6 for details. Con-
ventional pitot-sampling probe assemblies are not
recommended for use in ducts having inside diameters
smaller than 12 inches (Citation 16 in Section 6).
4.1.6.2 Recalibration.
4.1.6.2.1 Isolated Pitot Tubes. After each field use, the
pitot tube shall be carefully reexamined in top, side, and
end views. If the pitot face openings are still aligned
within the specifications Illustrated in Figure 2-2 or 2-3,
tt can be assumed that the baseline coefficient of the pitot
tube has not changed. If, however, the tube has been
damaged to the extent that it no longer meets the specifi-
cations of Figure 2-2 or 2-3, the damage shall either be
repaired to restore proper alignment of the face openings
or the tube shall be discarded.
4.1.6.2.2 Pitot Tube Assemblies. After each field nse,
check the face opening alignment of the pitot tube, as
In Section 4.1.6.2.1; also, rcmeasure the intcrcomponent
spacings of the assembly. If theintercomponcnt spacings
have not changed and the face opening alignment is
acceptable, it can be assumed that the coefficient of the
assembly has not changed. If the face opening alignment
It no longer within the specifications of Figures 2-2 or
9-8, either repair the damage or replace the pitot tube
(calibrating the new assembly, if necessary). If the inter-
component spacings have changed, restore the original
spacings or recalibrate the assembly.
4.2 Standard pitot tube (If applicable). If a standard
pitot tube Is used for the velocity traverse, the lube shall
be constructed according to the criteria of Section 2.7 and
shall be assigned a baseline coefficient value of 0.99. If
the standard pitot tube if used as part of an assembly.
the tube shall be in an interference-free arrangement
(subject to the approval of the Administrator).
4.3 Temperature Gauges. After each field use, cali-
brate dial thermometers, liquid-filled bulb thermom-
eters, thermocouple-potentiometer systems, and other
gauges at a temperature within 10 percent of the average
absolute stack temperature. For temperatures up to
405° C (761° F), use an ASTM mercury-fn-glass reference
thermometer, or equivalent, as a reference; alternatively,
either a reference thermocouple and potentiometer
(calibrated by NBS) or thermometric fixed points, e.g.,
ice bath and boiling water (corrected for barometric
pressure) may be used. For temperatures above 405° C
(761° F), use an NBS-calibrated reference thermocouple-
potentiometer system or an alternate reference, subject
to the approval of the Administrator.
If, during calibration, the absolute temperatures meas-
ured with the gauge being calibrated and the reference
gauge agree within 1.5 percent, the temperature data
taken in the field shall be considered valid. Otherwise.
the pollutant emission test shall either be considered
invalid or adjustments (if appropriate) of the test results
shall be made, subject to the approval of the Administra-
tor. -
4.4 Barometer. Calibrate the barometer used against
a mercury barometer.
5. Calculation!
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculation.
6.1 Nomenclature.
A = Cross-sectional area of stack, m" (ft1).
.Biri=Water vapor in the gas stream (from Method 5 or
Reference Method 4), proportion by volume.
Cp=Pitot tube coefficient, dimensionless.
Kt= Pitot tube constant,
(°K)(mmH2O) J
for the metric system and
« 4Q 1L r(lb/lb-mole)(in.Hg)-|'*
80 9secL (°K)(>n.H,0) J
for the English system.
Af <=Molecular weight of stack gas, dry basis (set
Section 3.6) g/g-mole (Ib/lb-mole).
M,=Molecular weight of stack gas, wet basis, g/g-
mole (Ib/lb-molo).
^Md (1—B».)+18.0 B*t Equation 2-5
. Pb«r=Barometric pressure at measurement site, mm
Hg (in. Hg).
Pf=Stack static pressure, mm Hg (in. Hg).
P.=Absolute stack gas pressure, ">™ Hg (in. Hg).
=Pb»r+P» Equation 2-6
P,,d = Standard absolute pressure, 760 mm Hg (29.92
in. Hg).
Qld=Dry volumetric stack gas flow rate corrected to
standard conditions, dscm/hr (dscf/hr).
l.=Stack temperature, °C (°F).
T.=Absolute stack temperature, °K (°R).
=273+(, for metric Equation 2-7
=460+1. for English Equation 2-8
r.tj=8tandard absolute tompcraWre, 293 °K (528° R)
p.=Average stack gas velocity, m/sec (ft/sec).
Ap=Velocity head of stack gas, mm H|O (in. BK>).
3,600=Conversion factor, sec/hr.
18.0=Molecular weight of water, g/g-mole (Ib-lb-
mole).
5.2 Average stack gas velocity.
frrt
v n f f~H—^ / •(»»«>
f.= ApCpt.VApAT. \-pT-, f~
f i ,J>J J
Equation 2-9
5.3 Average stack gns dry volumetric flow rale%
Q.d=3,600(l-B,,.)K.X
Equation 2-10
6. Bibliography
1. Mark, L. S. Mechanical Engineers' Handbook. New
York, McGraw-Hill Book Co., ln«. 1951.
2. Perry, J. H. Chemical Engineers' Handbook. New
York. McGraw-Hill Book Co., Inc. 1900.
ffDUM tfOrSTM, YOU .42, NO. t&O—'THUItSOAY, AUCUST 18, 1977
V-183
-------
RULES AND REGULATIONS
3. ShiKchara, R. T., W. F. Todd, and W. 8. Smith.
Aignilicimce of Krrors in Stack Sampling Measurement*.
U.S. Environmental Protection Agency, Research
Triangle Park, N.C. (Presented at the Annual Meeting of
tlto Air Pollution Control Association, fit. Louis, Mo.f
June 14-19. 1U70.)
4. Standard Method for Sampling SI neks for Par! Iculate
Matter. In: 11171 Book of ASTM Standards, Part 23.
Philadelphia, Pa. 1-J71. ASTM Designation D--J.W8-71.
.'>. Vennard, J. K. Elementary Fluid Mechanics. New
York. John Wiley and Sons, Inc. 1947.
li. Kluiil .Meters—Their Theory and Application.
American Society of .Mechanical Engineers, New York,
N.Y. 1H.V.I.
7. ASH KAE Handbook of Fundamentals. 1!>W. p. 208.
8. Annual Book of ASTM Standards. 1'an 'J6. l'J74. p.
CM.
9. Vollnro, R. F. Guidelines for Type 3 I'itot Tube
Calibration. U.S. Environmental Protection Agency.
Kesearch Tiangle Park, N.C. (Presented at 1st Annual
Meeting, Source Evaluation Society, Dayton, Ohio,
September 18,1975.)
10. Vollaro, R. F. A Type S Pitot Tulw Calibration
Sludy. U.S. Environmental Protection Agency, Emis-
sion Measurement Branch, Research Triangle Park,
N.C. July 1974.
11. Vollaro, R. F. The Effects of Impact Opening
Misalignment on the Value of the Type S Pitot Tube
Coefficient. U.8. Environmental Protection Agency,,
Emission Measurement Branch, Research Triangle
Park, N.C. October 1976.
12. Vollaro, R. F. Establishment of a Baseline Coeffi-
cient Value for Properly Constructed Typo S Pitot
Tubes. U.S. Environmental Proteciion Apency, Emis-
sion Measurement Branch, Research Triangle Park,
N.C. November 1976.
13. Vollaro, R. F. An Evaluation of Single-Velocity
ralibral ion Techniques as a Means of Determining Type
a 1'itot Tube Coefficients. U.S. Environmental Protec-
tion Agency, Emission Measuremeut Branch, Research
Triangle Park N.C. August 1975.
14. Vollaro, R. F. The Use of Type S Pilot Tubes for
the Measurement of Low Velocities. U.S. Environmental
Protection Agency, Emission Measurement Branch,
Research Triangle Park, N.C. November 1976.
15. Smith, Marvin L. Velocity Calibration of EPA
Type Source Sampling Probe. United Technologies
Corporation, Pratt and Whitney Aircraft Division,
East Hartford, Conn. 1975.
16. Vollaro, R. F. Recommended Procedure for Sample
Traverses in Ducts Smaller than 12 Inches in Diameter.
U.S. Environmental Protection Agency, Emission
Measurement Branch, Research Triangle Park, N.C.
November 1976.
17. Ower, E. and R. C..Pankhurst. The Measurement
of Air Flow, 4th Ed., London, Pergamon Press. 19fl6.
18. Vollaro, R. F. A survey of Commercially Available
Instrumentation for the Measurement of Low-Range
Oas Velocities. U.S. Environmental Protection Agency,
Emission Measurement Branch, Research Triangle
Park, N.C. November 1976. (Unpublished Paper)
19. Onyp, A. W. C. C. St. Pierre, D. S. Smith, D.
Mozzon. and J. Steiner. An Experimental Investigation
of the Effect of Pitot Tube-Sampling Probe Configura-
tions on the Magnitude of the 8 Type Pitot Tube Co-
efficient for Commercially Available Source Sampling
Probes. Prepared by the University ol Windsor for tb»
Ministry of the Environment, Toronto, Canada. Feb-
ruary 1975.
METHOD 3—GAS ANALYSIS TOR CARBON Dioxnx,
OXYGEN, EXCESS Am, AND DRY MOLECULAR WKIOHT
I. Principle and Applicability
1.1 Principle. A gas sample is extracted from a stack,
by one of the following methods: (1) single-Point, grab
sampling* (2) single-point, integrated sampling; or (8)
multi-point, integrated sampling. The gas sample If
analyzed for percent carbon dioxide (COi), percent oxy-
gen (O:), and, if necessary, percent carbon monoxide
(CO). If a dry molecular weight determination is to be
made, either an Orsat or a Fyrite > analyzer may be used
for the analysis; for excess air or emission rate correction
factor determination, an Orsat analyzer must be used.
1.2 Applicability. This method Is applicable for de-
termining CO> and Oj concentrations, excess air, and
dry molecular weight of a sample from a gas stream of »
fossil-fuel combustion process. The method may also be
applicable to other processes where It has been determined
that compounds other than COj, 0:, CO, and nitrogen
(Ni) are not present* In concentrations sufficient to
ailect the results.
Other methods, as well as modifications to the proce-
dure described herein, are also applicable for some or mil
of the above determinations. Examples of specific meth-
ods and modifications include: (1) a multi-point samp-
ling method using an Orsat analyzer to analyze Indi-
vidual grab samples obtained at each point; (2) a method
using COi or Oi and stoichiometrlc calculations to deter-
mine dry molecular weight and excess air; (3) assigning •
value of 30.0 for dry molecular weight, In lieu of actual
measurements, for processes burning natural gas, coal, or
oil. These methods and modifications may be used, but
are subject to the approval of the Administrator.
2. Apparalul
As an alternative to the sampling apparatus and sys-
tems described herein, other sampling systems (e.g.,
liquid displacement) may be used provided such systems
are capable of obtaining a representative sample and
maintaining a constant sampling rate, and are otherwise
capable of yielding acceptable results. Use of such
systems is subject to the approval of the Administrator.
2.1 Grab Sampling (Figure 3-1).
•2.1.1 Probe. The probe should be made of stainless
steel or borosilicate glass tubing and should be equipped
with an iu-stack or out-stock filter to remove particulate
matter (a plug of glass wool is satisfactory for this pur-
pose). Any other material inert to Oi, COi, CO, and N>
and resistant to temperature at sampling conditions may
be used for the probe; examples of such material are
aluminum, copper, quartz glass and Teflon.
'2.1.2 Pump. A one-way squeeze bulb, or equivalent,
is used to transport the gas sample to the analyzer.
2.2 Integrated Sampling (Figure 3-2).
2.2.1 Probe. A probe such as that described in Section
2.1.1 is suitable.
i Mention of trade names or specific products does not
constitute endorsement by the Environmental Protec-
tion Agency.
FEDERAL REGISTER, VOL. 42, NO. 160—THURSDAY, / UOUST It, 1»77
'V-184
-------
RULES AND REGULATIONS
PROBE
FLEXIBLE TUBING
FILTER (GLASS WOOL)
TO ANALYZER
SQUEEZE BULB
Figure 3-1. Grab-sampling train.
RATE METER
AIR-COOLED
CONDENSER
PROBE
•B»^"
FILTER
(GLASS WOOL)
PUMP
VALVE
QUICK DISCONNECT
JT
RIGID CONTAINER'
Figure 3-2. Integrated gas-sampling train.
HOMAL M0ISTM, VOL 4s; NO. t«0—THIMISDAY, AUGUST 18, W7T
BAG
V-185
-------
KUB.HS
Di©PlLA¥II©KS
5 2 2 Condenser. An air-cooled or wat«r-«6oled con-
denser, or other condenser that will not removo On,
i 'Oi CO, and Ni, may be used to remove excess raoletnro
which would interfere with the operation of the pump
and flow meter.
:' 2.3 Valve. A needle valve is used to adjust sample
pas flow rate.
2.2.4 Pump. A leak-free, diaphragm-type pump, or
equivalent, is used to transport sampW gas to the flexible
\ .\g. Install a small surge tank between the puinp and
rale meter to eliminate the pulsation erfcct of the dia-
phragm pump on the rotameter.
2.2.8 Kate .Meter. The rotameter, or equivalent rate
meter, used should be capable of measuring flow rate
to within ±2 percent of the selected flow rate. A flow
rale ranee of NX) to 1000 cuiVnihi is suggested.
2.2.6 Flesihle Dai;. Any leak-free plastic (e.g., Tcdlar,
Mylar Teflon) or plastic-coated aluminum (e.g., alumi-
nitfd Mylar) bag, or equivalent, having a capacity
consistent with the selected flow rale and time length
or the test run. may be used. A capacity in the range of
M to 90 liters is suppested.
To leak-check the bap, connect it to a water manometer
and pressurize the bag to 5 to 10cm HzO (2 to 4 in. HjO).
Allow to stand for 10 minutes. Any displacement in the
water manometer indicates a leak. An alternative leak-
check method is to pressurize the bag to 5 to 10 cm H:O
(2 to 4 In. HiO) and allow to stand overnight. A deflated
bag Indicates a leak.
2.2.7 Pressure Gauge. A water-filled U-tnl>e manom-
eter, or equivalent, of about 28 cm (12 in.) is used for
the fleiible bag leak-check.
2.2 8 Vacuum Gauge. A mercury manometer, or
equivalent, of at least 760 mm Hg (30 in. Hg) is used for
tbe sampling train leak-check.
2.3 Analysis. For Orsat and Fyrite analyzer main-
tenance and operation procedures, follow the instructions
recommended by the manufacturer, unless otherwise
specified herein.
2.3.1 Dry Molecular Weight Determination. An Orsat
analyzer or Fyrite type combustion gas analyzer may be
used.
2.3.2 Emission Rate Correction Factor or Eicess Air
Determination. An Orsat analyzer must be used. For
low COi (less than 4.0 percent) or high Oi (greater than
15.0 percent) concentrations, the measuring burette o/
the Orsat must have at least 0.1 percent subdivisions.
3. Dry Molecular Weight Determination
Any of the three sampling and analytical procedures
described below may be used for determining the dry
molecular weight.
3.1 Single-Point, Grab Sampling and Analytical
3.1.1 The sampling point in the duct shall either be
at the centroid of the cross section or at a point no closer
to the walls than 1.00 m (3.3 ft), unless otherwise specified
by the Administrator.
8.1.2 Set up the equipment as shown in Figure 3-1,
matdng sure all connections ahead of the analyzer are
tight and leak-free. If an Orsat analyzer is used, it is
recommended tbat the analyzer be leaied-checked by
following the procedure in Section 5; however, the leak-
ehecb Is optional.
3.1.3 Place the probe in the stack, with the tip of the
probe positioned at the sampling point; purge the saropl-
inS line. Draw a sample into the analyzer and imme-
diately analyze it for percent COi and percent O>. Deter-
mine the percentage of the gas that Is Ni and CO by
subtracting the sum of the percent CO> and percent Oi
from 100 percent. Calculate the dry molecular weight es
indicated in Section 6.3. .
3.1.4 Repeat the sampling, analysis, and calculation
procedures, until the dry molecular weights of any three
trrnb samples differ from their mean by no more than
0.8 g/B-mole (0.3 Ib/lb-mole). Average these three molec-
ular weights, and report the results to the nearest
0.1 g/g-mole (lb,1b-nio!e). .
3.2 Single-Point, Integrated Sampling and Analytical
3.2.1 The sampling point in the duct shall be located
asspecifiedinSection3.1.1.
3.2.2 Leak-check (optional) the fleiible bag as In
Section 2.2.6. Set up the equipment as shown in Figure
3-2. Just prior to sampling, leak-check (optional) the
train by placing a vacuum gauge at the condenser inlet,
pulling a vacuum of at least 250 mm Hg (10 in. Hg),
plugging the outlet at the quick disconnect, and then
turning off the pump. The vacuum should remain stable
for at least 0.5 minute. Evacuate the flexible bag. Connect
Die probe and place it in the stack, with the tip of the
probe positioned at the sampling point; purge the sampl-
ing line. Next, connect the bag and make sure that all
connexions are tight and leak free.
323 Sample at a constant rate. The sampling run
should be simultaneous with, and for the same total
length of time as, the pollutant emission rate determina-
tion. Collection of at least 30 liters (1.00 ft») of sample gas
is recommended; however, smaller volumes may be
c-ollpetfd. if desired.
.1-'.4 obtain one integrated flue gas sample during
each pollutant emission rate determination. Within 8
hours after the sample is taken, analyze it for percent
i.'Oi and percent Oi using either au Orsat analyzer or a
Fyrite-type combustion gas analyzer. If an Orsat ana-
lyzer is used, it is recommended that the Orsat leak-
. heck described In Section 5 be performed before this
determination; however, the checti to optional. Det«r-
loine the percentage of the gas that is Ni and CO by sub-
tracting tbe sum of tbe percent CO: and percent Oj
from 1(10 percent. Calculates the dry molecular weight Co
indicated in Section 0.1
3.3.5 Repsot 6ho analysis and calculation procedures
until tbe individual dry molecular weights lor any threa
analyses differ from their mean by no more than 0.8
g/g-mole (0.3 Ib/lb-mole). Ararcje vtesa three molecular
weights, and report the results to the nearest 0.1 g/g-molo
(0.1 Ib/lb-mole).
3.3 Multi-Point, Integrated Sampling and Analytical
Procedure.
3.3.1 Unless otherwise specified by the Adminis-
trator, a minimum of eight traverse points shall be used
for circular stacks having diameters less then 0.61 m
(24 in.), a minimum of nine shall be used for rectangular
stacks having equivalent diameters less than 0.61 m
(24 in.), and a minimum of twelve traverse points shall
be used for all other cases. The traverse points shall be
located according to Method 1. The use of fewer points
is subject to approval of the Administrator.
3.3.2 Follow the procedures outlined in Sections 3.2.2
through 3.2.5, except for the following: traverse all sam-
pling points and sample at each point for an equal length
of lime. Record sampling data as shown in Figure 3-3.
A. Etaltuloa Kale Correction Factor C7 Exttw A'a Dtttr-
mlocftoo
NOTE.—A Fyrite-typa combustion gas analyze? Is no3
acceptable for excess air or emission rate correction Ibcte?
determination, unless approved by the Administrator.
If both percent CO] and percent Oi are measured, tbo
analytical results of any of the three procedures given
below may also be used lor calculating the dry molecule?
weight.
Each of the three procedures below shall be used only
when specified in an applicable subpart of tbe standards
The use of these procedures for other purposes must bovo
specific prior approval of the Administrator.
4.1 Single-Point, Grab Sampling and Analytical
Procedure.
4.1.1 The sampling point in the duct shall either ba
at the centroid of the cross-section or at a point no closer
to the walls than 1.00m (3.3ft), unless otherwise specified
by the Administrator.
4.1.2 Set up tbe equipment as shown in Figure 3-1,
making sure all connections ahead of the analyze; ere
tight and leak-free. Leak-check the Orsat analyzer ac-
cording to the procedure described in Section 4. This
leak-check Is mandatory.
TIME
TRAVERSE
/ B-Qavgv
> 0 awisi '
(MUST BE < 11%)
Figure 3-3- Sampling rate data.
4.1.3 Place the probe in the stack, with the Up of the
probe positioned at the sampling point; purge the sam-
pling line. Draw a sample into the analyzer. For emission
rate correction factor determination, Immediately ana-
lyze the sample, as outlined in Sections 4.1.4 and 4.1.5,
for percent COi or percent Oi. If excess air Is desired,
proceed as follows; (1) Immediately analyze the sample,
as In Sections 4.1.4 and 4.1.6, for percent COi, Di, and
CO; (2) determine the percentage of the gas tbat Is Ni
by subtracting the sum of the percent COi, percent Oi,
and percent CO from 100 percent; and (3) calculate
percent excess air as outlined in Section 6.2.
4.1.4 To ensure complete absorption of the COi, Ot,
or if applicable, CO, make repeated passes through each
absorbing solution until two consecutive readings are
the same. Several passes (three or four) should ba made
between readings. (If constant readings cannot be
obtained after three consecutive readings, replace the
absorbing solution.)
4.1.6 After the analysis Is completed, leak-check
(mandatory) the Orsat analyzer once again, as described
in Section 5. For the results of the analysis to be valid,
the Orsit analyzer must pass this leak test before and
after the analysis. NOTE.—Since this single-point, grab
sampling and analytical procedure Is normally conducted
in conjunction with a single-point, grab sampling and
analytical procedure for a pollutant, only one analysis
is ordinarily conducted. Therefore, great care must be
taken to obtain a valid sample and analysis. Although
in most cases only COi or Oi is, required, it is recom-
mended that both CO; and Oi be measured, and that
Citation 5 in the Bibliography be used to validate the
analytical data.
4.2 Single-Point, Integrated Sampling anil Analytical
Procedure.
4.2.1 The sampling pjint in Hie duct shall be located
as specified in Section 4.1.1.
4.2.2 Leak-check (mandatory) the flexible bag as in
Section 2.2.tt. Set up the equipment as shown in Figure
3-2. Just prior to sampling, leak-check (mandatory) the
train by placing a vacuum gauge at the condenser inlet,
pulling a vacuum of at least 250 mm Hg (10 in. Hg),
plugging the outlet at the quick disconnect, and then
turning oB the pump. The vacuum shall remain stable
for at least 0.5 minute. Evacuate tho flexible beg. Con-
nect the probe and place it in the stack, with tbe Up of the
probe positioned at the sampling point; purge the sam-
pling line. Next, connect the bag and make sure that
all connections are tight and leak tree.
4.2.3 Sample at a constant rate, or as specified by the
Administrator. The sampling run must be simultaneous
with, and for the same total length of time as, tbe pollut-
ant emission rate determination. Collect at least 30
liters (1.00 ft1) of sample gas. Smaller volumes may be
collected, subject to approval of the Administrator.
4.2.4 Obtain one integrated flue gas sample during
each pollutant emission rate determination. For emission
rate correction factor determination, analyze the sample
within 4 hours after it is taken fur percent COi or percent
Oi (as outlined in Sections 4.2.5 through 4.2.7). The
Orsat anolyzer must be leak-checked (see Section 5)
Iwfore tho analysts. If excess air is desired, proceed es
follows: (1) within 4 hours after the sample is taken,
analyze it (as in Sections 4.2.5 through 4.2.7) for percent
C()i. O;, and CO: (2) determine the percentage of Ihe
gas that is Ni by subtracting the sum of the percent CO>,
percent O?, and percent CO from 100 percent; (3) cal-
culate percent excess air, as outlined in Section 6.2.
4.2.5 To ensure complete absorption of the COi, Oi,
or if applicable, CO, make repeated passes through each
absorbing solution until two consecutive readings are the
same. Several passes (three or four) should be made be-
tween readings. (If constant readings cannot be obtained
after three consecutive readings, replace the absorbing
solution.)
4.2.6 Repeat the analysis until the following criteria
4.2.6.1 For percent COi, repeat the analytical pro-
cedure until the results of any three analyses differ by no
more than (a) 0.3 percent by volume when CO» is greater
than 4.0 percent or (b) 0.2 percent by volume when COj
is less than or equal to 4.0 percent. Average the three ac-
ceptable values of percent COi and report tbe results to
the nearest 0.1 percent.
4.2.6.2 For percent Oi, repeat the analytical procedure
until the results of any tbree analyses differ by no moro
FEDERAL REGISTER, VOL. 42, NO. 160—THURSDAY, AUGUST 10, 1977
V-186
-------
RULES AND REGULATIONS
than (a) (U percent by volume when Oi Is leas than 15.0 8. Calailaltont
percent or (b) 0.2 percent by volume when Oi Is greater
than 16.0 percent. Average the three acceptable values of
percent Oi and report the results to the nearest 0.1
4.2.6.3 For percent CO, repeat the analytical proce-
dure until the results of any three analyses differ by no
more than 0.3 percent. Average the three acceptable
values of percent CO and report the results to the nearest
0.1 percent.
4.2.7 After the analysis Is completed, leak-check
(mandatory) the Orsat analyzer once again, as described
In Section 8. For the results of the analysis to be valid, the
Orsat analyzer must pass this leak test before and after
the analysis. Note: Although in most instances only COi
or Oi Is required, it is recommended that both C0» and
Oi be measured, and that Citation 5 in the Bibliography
be used to validate the analytical data.
4.1 Haiti-Point, Integrated Sampling and Analytical
Procedure.
4*3.1 Both the minimum number of sampling points
and the sampling point location shall be as specified in
Section 3.3.1 of this method. The use of fewer points than
specified It Jobject to the approval of the Administrator.
4.8.2 Follow the procedures outlined In Sections 4.2.2
through 4.2.7, except for the following: Traverse all
aampunc points and sample at each point for an equal
length online. Record sampling data as shown In Figure
8-3.
6. Leak-duck Procedure for Ortat Analyzers
Moving an Orsat analyzer frequently causes It to leak.
Therefore, an Orsat analyzer should be thoroughly leak-
checked on site before the flue gas sample is introduced
Into It. The procedure for leak-checking an Orsat analyzer
Is:
6.1.1 Bring the liquid level in each pipette up to the
reference mark on the capillary tubing and then close the
pipette stopcock.
5.1.2 Raise the leveling bulb sufficiently to bring the
confining liquid meniscus onto the graduated portion of
the burette and then close the manifold stopcock.
6.1.3 Record the meniscus position.
6.1.4 Observe the meniscus in the burette and the
liquid level in the pipette for movement over the neit 4
minutes.
6.1.6 For the Orsat analyzer to pass the leak-check,
two conditions must be met.
6.1.5.1 The liquid level in each pipette must not fall
below the bottom of the capillary tubing during this
4-mlnuteinterval.
6.1.5.2 The meniscus in the burette must not change
by more than 0.2 ml during this 4-mlnutelnterval.
5.1.6 If the analyzer falls the leak-check procedure, all
rubber connections and stopcocks should be checked
until the cause of the leak Is Identified. Leaking stopcocks
must be disassembled, cleaned, and regressed. Leaking
rubber connections must be replaced. After the analyzer
Is reassembled, the leak-check procedure must be
repeated.
6.1 Nomenclature.
Mj-Dry molecular weight, g/g-mole (Ib/lb-mole).
%EA=Percent excess air.
%COi=Peroent COj by volume (dry basis).
%Oi—Percent Oi by volume (dry basis).
%CO=Percent CO by volume (dry basis).
%Ni=Percent Ni by volume (dry basis).
0.264= Ratio of Oi to Ni in air, v/v.
0.280=Molecular weight of Ni or CO, divided by 100.
0.320=Molccular weight of O, divided by 100.
0.440=Molecular weight of CO; divided by 100.
6.2 Percent Excess Air. Calculate the percent excess
air (if applicable), by substituting the appropriate
values of percent Oi, CO,and Nj (obtainedfrom Section
4.1.3 or 4.2.4) into Equation 3-1.
TEA f %0.-0.6%CO "I
/oLA-|_0.264%N,(%02-0.5%CO) J °°
Equation 3-1
NOTE.—The equation above assumes that ambient
air Is used as the source of Oi and that the fuel does not
contain appreciable amounts of N* (as do coke oven or
blast furnace gases). For those cases when appreciable
amounts of N> are present (coal, oil, and natural gas
do not contain appreciable amounts of Ni) or when
oxygen enrichment is used, alternate methods, subject
to approval of the Administrator, are required.
6.3 Dry Molecular Weight. Use Equation 3-2 to
calculate the dry molecular weight of the stack gas
A/j=0.440(%COi)+0.320(%O!)+0.280(%Xi+%CO)
Equation 3-2
NOTE.—The above equation does not consider argon
in air (about 0.9 percent, molecular weight of 37.7).
A negative error of about 0.4 percent is Introduced.
The tester may opt to include argon In the analysis using
procedures subject to approval of the Administrator.
7. Bibliography
1. Altshuller, A. P. Storage of Oases and Vapors in
Plastic Bags. International Journal of Air and Water
Pollution. 6:75-81.1963.
2. Conner, William D. and J. S. Nader. Air Sampling
Plastic Bags. Journal of the American Industrial Hy-
giene Association. W:291-297.1964.
3. Burrell Manual for Qes Analysts, Seventh edition.
Burrell Corporation, 2223 Fifth Avenue, Pittsburgh,
Pa, 15219.1061.
4. Mitchell, W. J. and M. R. Midgett. Field Reliability
of the Orsat Analyzer. Journal of Air Pollution Control
Association «6:491-495. May 1U76.
5. Shigehara, R. T., R. M. Neulicht, and W. S. Smith.
Validating Orsat Analysis Data from Fossil Fuel-Fired
Units. Stack Sampling News. -!(2):21-26. August, 1970.
METHOD 4—DETEBMWATIOS o» MOISTURE CONTEXT
n» STACK GASES
1. Principle and Applicability
1.1 Principle. A gas sample is extracted at a constant
rate from the source; moisture is removed from the sam-
ple stream and determined either volumetrically 01
gravimetrically.
1.2 Applicability. This method is applicable for
determining the moisture content oi stack gas.
Two procedures are given. The first is a reference
method, for accurate determinations of moisture content
(such as are needed lo calculate emission data). The
second is an approximation method, which provides
estimates of percent moisture to aid in setting isokinetic
sampling rates prior to a pollutant emission measure-
vment run. The approximation method described herein
is only a suggested approach; alternative means for
approximating the moisture content, e.g., drying tubes,
wet bulb-dry bulb techniques, condensation techniques,
stoichiometric calculations, previous experience, etc.,
are also acceptable.
The reference method is often conducted simultane-
ously with a pollutant emission measurement run; when
it is, calculation of percent isokinetic, pollutant emission
rate, etc., for the run shall be based upon the results of
the reference method or its equivalent; these calculations
shall not be based upon the results of the approximation
method, unless the approximation method is shown, to
the satisfaction of the Administrator, U.S. Environmen-
tal Protection Agency, to be capable of yielding results
within 1 percent H;O of the reference method.
NOTE.—The refercnc-e method may yield questionable
results when applied to saturated gas streams or to
streams that contain water droplets. Therefore, when
these conditions exist or are suspected, a second deter-
mination of the moisture content shall be made simul-
taneously with the reference method, as follows: Assume
that the gas stream is saturated. Attach a temperature
sensor (capable of measuring to *1° C (2° F)| to the
reference method probe. Measure ttie stack gas tempera-
ture at each traverse point (see Section 2.2.1) during the
reference method traverse: calculate the average stack
gas temperature. Next, determine the moisture percent-
age, either by: (1) using a psychrometric chart and
making appropriate corrections if stack pressure is
different from that of the chart, or (2) using saturation
vapor pressure tables. In cases where the psychrometric
chart or the saturation vapor pressure tables are not
applicable (based on evaluation of the process), alternate
methods, subject to the approval of the Administrator,
shall be used.
2. Reference Method
The procedure described in Method 5 for determining
moisture content is acceptable as a reference method.
2.1 Apparatus. A schematic of the sampling train
used in this reference method is shown in Figure 4-1.
All components shall be maintained and calibrated
according to the procedure outlined in Method 5.
TOEIAl RfOISTER, VOL 42, NO. 160—THUHSDAY, AUGUST 18, 1977
V-187
-------
RULES AND REGULATIONS
FILTER
(EITHER IN STACK /I
OR OUT OF STACK)
STACK
WALL
CONDENSER-ICE BATH SYSTEM INCLUDING
SILICA GEL TUBE —7
Figure 4-1. Moisture sampling train-reference method.
2.1.1 Probe. The probe is constructed of stainless
(teel or glass tubing, sulflcieiitly heated to prevent
water condensation, and is equipped with a filter, either
In-atack (e.g., a plug of glass wool inserted into the end
of the probe) or heated out-stack (e.g., as described In
Method 5), to remove paniculate matter.
When stack conditions permit, other metals or plastic
tubing may boused for the probe, subject to the approval
of the Administrator.
2.1.2 Condenser. The condenser consists of four
impingers connected in series with ground glass, leak-
free fittings or any similarly leak-free non-contaminating
fittings. The first, third, and fourth impingers shall be
of the Orcenburg-Smith design, modified by replacing
the tip with a 1.3 centimeter (Yi inch) ID glass tube
extending to about 1.3 cm (^ in.) from the bottom of
the flask. The second impinger shall be of the Greenburg-
Bmith design with the standard tip. Modifications (e.g.,
using flexible connections between the impingers, using
materials other than glass, or using flexible vacuum lines
to connect the tiltcr holder to the condenser) may be
used, subject to the approval of the Administrator.
The first two impinpers shall contain known volumes
of water, the third shall be empty, and the fourth shall
contain a known weight of 6- to 16-mesh indicating type
silica gel, or equivalent desiccant. If the silica gel has
been previously used, dry at 175° C (350° F) for 2 hours.
New silica gel may be used as received. A thermometer,
eapable of measuring temperature to within 1° C (2° F),
shall be placed at the outlet of the fourth impinger, for
monitoring purposes.
Alternatively, any system may he used (subject to
the approval of the Administrator) that oools the sample
gas stream and allows measurement of both the water
that has been condensed and the moisture leaving the
condenser, each .to within 1 ml or 1 g. Acceptable means
are to measure the condensed water, either grayi-
metrically or volumetrically, and to measure the mois-
ture leaving the condenser by: (1) monitoring the
temperature and pressure at the exit of the condenser
»ud using Dalton'a law of partial pressures, or (2) passing
the sample gas'stream through a tared silica gel (or
equivalent desiccant) trap, with exit gases kept below
2u° C (68° F). and determining the weight gain.
If means other than silica gelare used to determine the
amount of moisture leaving the condenser, it is recom-
mended that silica gel (or equivalent) still be used be-
tween the condenser system and pump, to prevent
moisture condensation In the pump and metering
devices and to avoid the need to make corrections for
moisture in the metered volume.
2.1.3 Cooling System. An ice bath container and
crushed ice (or equivalent) are used to aid in condensing
moisture.
2.1.4 Metering System. This system includes a vac-
uum gauge, leak-free pump, thermometers capable of
measuring temperature to within 3° C (5.4° F), dry gas
meter capable of measuring volume to within 2 percent,
and related equipment as shown in Figure 4-1. Other
metering systems, capable of maintaining a constant
sampling rate and determining sample gas volume, may
be used, subject to the approval of the Administrator.
2,1.5 Barometer. Mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to within
2.6 mm Ilg (0.1 in. Hg) may be used. In many cases, the
barometric reading may be obtained from a nearby
national weather service station, in which case the sta-
tion value, (which is the absolute barometric pressure)
shall be requested and an adjustment 'for elevation
differences between the weather station and the sam-
pling point shall be applied at a rate of minus 2.6 mm Hg
(0.1 in. Hg) per 30 m (100 ft) elevation increase or vice
versa for elevation decrease.
2.1.6 Graduated Cylinder and/or Balance. These
items are used to measure condensed water and moisture
caught in the silica gel to within 1 ml or 0.5 g. Graduated
cylinders shall have subdivisions no greater than 2 ml.
Most laboratory balances are capable of weighing to the
nearest 0.5 g or less. These balances are suitable for
use here.
2.2 Procedure. The following procedure is written for
a condenser system (such as the impinger system de-
scribed in Section 2.1.2) incorporating volumetric analy-
sis to measure the condensed moisture, and silica gel ftnd
gravimetric analysis to measure the moisture leaving the
condenser.
2.2.1 Unless otherwise specified by the Administrator,
a minimum of eight traverse points shall be used for
circular stacks having diameters less than 0.61 m (24 in.),
a minimum of nine points shall be used for rectangular
stacks having equivalent diameters less than 0.61 m
(24 in.), and a minimum of twelve travers points shall
be used in all other cases. The traverse points shall be
located according to Method 1. The use of fewer points
is subject to the approval of the Administrator. Select m
suitable probe and probe length such that all traverse
points can be sampled. Consider sampling from opposite
sides of the stack (four total sampling ports) for large
stacks, to permit use of shorter probe lengths. Mark the
probe with heat resistant tape or by some other method
to denote the proper distance into the stack or duct tor
each sampling point. Place known volumes of water in
the ttrst two impingers. Weigh and record the weight of
the silica gel to the nearest 0.5 g, and transfer the sille*
gel to the fourth impinger; alternatively, the silica gel
may Qrstbe transferred to the impinger, and the weight
of the silica gel plus impinger recorded.
2.2.2 Select a total sampling time such that a mini-
mum total gas volume of 0.00 scm (21 scf) will be col-
lected, at a rate no greater than 0.021 m'/min (0.75 dm).
When both moisture content and pollutant emission rate
are to be determined, the moisture determination shall
he simultaneous with, and for the same total length of
time as. the pollutant emission rate run, unless otherwise
specified in an applicable subpart of the standards.
2.2.3 Set up the sampling train as shown la Figure
4-1. Turn on the probe beater and (U applicable) the
niter heating system to temperatures of about 120* C
(248° F), to prevent water condensation ahead of UM
condenser; allow time for the temperatures to stabilise.
Place crushed ice In the ice batb container. It IB recom-
mended, but not required, that a leak sheck be done, M
follows: Disconnect the probe from the first impinger or
FEDERAL REGISTER, VOl. 42. NO. 160—THURSDAY. AUGUST 18, 1977.
V-188
-------
IULES AND REGULATIONS
(If applicable) from the filter bolder. Plug the Inlet to the
ftnt impinger (or filter holder) and pull s 380 mm (15 In.)
Hg vacuum; a lower vacuum may be used, provided that
It it not exceeded during the test. A leakage rate in
excess of 4 percent of the average sampling rate or 0.00057
m'/min (0.02 elm), whichever is less, is unacceptable.
Following the I eak check, reconnect the probe to the
•unplug train.
2.2.4 During the sampling run, maintain a sampling
nte within 10 percent of constant rate, or as specified by
the Administrator. For each run, record the data re-
quired on the example data sheet shown in Figure 4-2.
Be ture to record the dry gas meter reading at the begin-
ning and end of each sampling time increment and when-
FIANT
(OCATION.
OPERATOR.
MtE
•UN N0._
AMBIENT TEMPERATURE-
BAROMETRIC PRESSURE-
PROIE LENGTH nlft)
ever sampling is halted. Take other appropriate readings
at each sample point, at least once during each time
Increment.
2.2.5 To begin sampling, position the probe tip at the
first traverse point. Immediately start the pump and
adjust the flow to the desired rate. Traverse the cross
section, sampling at each traverse point for an equal
length of time. Add more ice and, If necessary, salt to
maintain a temperature of less than 20° C (68° F) at the
silica gel outlet.
2.2.6 After collecting the sample, disconnect the probe
from the filter holder (or from the first impinger) and con-
duct a leak check (mandatory) as described in Section
2.2.3. Record the leak rate. If the leakage rate exceeds the
allowable rate, the tester shall either reject the test re-
sults or shall correct the sample volume as in Section 6.3
of Method 5. Next, measure the volume of the moisture
condensed to the nearest ml. Determine the increase in
weight of the silica gel (or silica gel plus impingcr) to the
nearest 0.5 g. Record this information (see example data
sheet, Figure 4-3) and calculate the moisture percentage,
as described in 2.3 below.
2.3 Calculations. Carry out the following calculations,
retaining at least one extra decimal figure beyond that of
the acquired data. Round ofl figures after final calcula-
tion.
SCHEMATIC OF STACK CROSS SECTION
TRAVERSE POINT
NUMBER
TOTAL
SAMPLING
TIME
(91. mm.
AVERAGE
STACK .
TEMPERATURE
•CPFI
PRESSURE
DIFFERENTIAL
ACROSS
•RIFICE METER
(AH).
mmfinj H]0
..
METER
READING
GAS SAMPLE
VOLUME
•'Ml')
AVB
mStfiJ)
CAS SAMPLE TEMPERATURE
AT DRY GAS METER
INLET
(Tmin),»C(«F)
Aug.
A».
OUTLET
(Tmoal),eC(0F)
A*.
TEMPERATURE
OF GAS
LEAVING
CONDENSER OR
LAST IMPINGER,
•C («F»
Figure 4-2. Field moisture determination-reference method.
MBBMt BXOtSTiR, VOL. 41, NO. 160—WUtSDAY, AUGUST IB, 1*77
V-189
-------
RULES AND REGULATIONS
FINAL
INITIAL
DIFFERENCE
IMPINGED •
VOLUME.
ml '
SILICA GEL
WEIGHT.
g •
Figure 4 3. Analytical data • reference method.
2.3.1 Nomenclature.
./?iT. = Proportion of water vapor, by volume, in
the gas stream.
M w = Molecular woight of water, 18.0 g/g-mole
Kquation 4-1
where:
Jfi=0.001333 m'/uil for metric units
=0.04707 ft'/ml for English units
2.3.3 Volume of water vapor collected in silica gel.
vbere:
.Ki=0.001335 m'/g for metric units
-0.04718 ft'/gtor English units
2.3.4 Sample gas volume.
Erjuatlon 4-2
v I/j»l<_Zr..)
'
V P
is v m m
= "3* ~if—
1 m
K(|ii:itioil 4-3
where:
A'3=0.3858°K/mm Hg for metric units
=17.64 "R/in. Hg for English unite
NOTE.—If the post-test leak rate (Section 2.2.B) ei-
ceeds the allowable rate, correct the value of V, in
Kiiualiun 4-3, as described in Section 0.3 of Method 5.
2.3.8 Moisture Content.
V»«(.tn-f-I'.. „<«:)'
trt <«tj> + V.r,« (,t.l) + Vm («|J)
Kquation 4-4
N'orK— In saturated or mnUtiirc droplet-laden gas
streams, two calculations of the moisture content of the
stack gas shall be made, one using a value based upon
the saturated conditions (see Section 1.2), and another
based upon the results of the impinger analysis. The
lower of these two values of B«. shall be considered cor-
rect.
2.3.1; Verification of constant sampling rate. For each
time increment, determine the At/*. Calculate the
average. If the value for any time increment differs from
the average by more than 10 percent, reject the results
and repeat the run.
3. Approximation Method
The approximation method described below is pre-
sented only as a suggested method (see Section 1.2).
3.1 Apparatus.
3.1.1 Probe. Stainless steel or glass tubing, sufficiently
heated to prevent water condensation and equipped
with a filter (either in-atack or heated out-stack) to re-
move participate matter. A plug of glass wool, inserted
into the end of the probe, is a satisfactory filter.
3.1.2 Irapingers. Two midget impingers, each with
30 ml capacity, or equivalent.
3.1.3 Ice Bath. Container and ice, to aid in condens-
ing moisture in impingers.
3.1.4 Drying Tube. Tube packed with new or re-
generated 6- to 16-mesh indicating-type silica gel (or
equivalent dcsiccant), to dry the sample gas and to pro-
tect the meter and pump.
3.1.5 Valve. Needle valve, to regulate the sample gas
flow rale.
3.1.6 Pump. Leak-free, diaphragm type, or equiva-
lent, to null the gas sample through the train.
3.1.7 Volume meter. Dry gas meter, sufficiently ac-
curate to measure the sample volume within 2%, and
calibrated over the range of flow rates and conditions
actually encountered during sampling.
3.1.8 Hate Meter. Hotameter, to measure the flow
range from 0 to 31 pm (0 to 0.11 cfm).
3.1.9 Graduated Cylinder. 25 ml.
3.1.10 Barometer. Mercury, aneroid, or other barom-
eter, as described in Section 2.1.5 above.
3.1.11 Vacuum Gauge. At least 760 mm rig (30 in.
Hg) gauge, to be used for the sampling leak check.
3.2 Procedure.
3.2.1 Place eiactly 5 ml distilled water in each im-
pinger. Assemble the apparatus without the probe as
shown in Figure 4-4. Leak check the train by placing a
vacuum gauge at the inlet to the first impinger and
drawing a vacuum of at least 250 nun Hg (10 in. Hg)
plugging the outlet of the rotameter, and then turning
off the pump. The vacuum shall remain constant for at
east one minute. Carefully release the vacuum gauge
Ibefore unplugging the rotameter end.
FEDERAL REGISTER, VOL. 42, NO. 160—THURSDAY, AUGUST 18, 1977
V-190
-------
RUIES AND REGULATIONS
HEATED PROBE SILICA GEL TUBE
RATE METER,
VALVE
DRY GAS )
JWETER /
MIDGET IMPINGERS
PUMP
Figure 4-4. Moisture-sampling train - approximation method.
LOCATION.
TEST
COMMENTS
DATE
OPERATOR
BAROMETRIC PRESSURE.
CLOCK TIME
.
GAS VOLUME THROUGH
METER, (Vm).
m3 (ft3)
RATE METER SETTING
m^/min. (ft^/min.)
METER TEMPERATURE.
°C (°F)
•
Figure 4-5. Field moisture determ.ination - approximation method.
fCDCIAl UUIlltl, VOL n, NO. 149—1HUUDAY, ftWVST Tt, TVT7
V-191
-------
RULES AND REGULATIONS
3.2.2 Connect the probe, insert It into the stack, and
earn pie at a constant rate of 21pm (0.071 ctm). Continue
sampling until the dry gas meter registers about 30
liters (1.1 ft») or until visible liquid droplets are carried
over from the (list Impinger to the second. Record
temperature, pressure, and dry gas meter readings aa
required by Figure 4-5.
3.2.3 After collecting the sample, combine the con-
tents of the two Impingers and measure the volume to the
nearest 0.5 ml.
3.3 Calculations. The calculation method presented Is
designed to estimate the moisture in the stack gas;
therefore, other data, which are only necessary for ac-
curate moisture determinations, are not collected. The
following equations adequately estimate the moisture
content, for the purpose o( determining isokinetic sam-
pling rate settings.
3.3.1 Nomenclature.
J}WH=Approximate proportion, by volume, of
water vapor in the gas stream leaving the
second impinger, 0.025.
B„.=• Water vapor in the gas stream, proportion by
volume.
M.=Molecular weight of water, 18.0 g/g-mole
(IS.Olbflb-mole)
P.=Absolute pressure (for this method, same aa
barometric pressure) at the dry gas meter.
P,u=Standard absolute pressure, 780 mm Hg
(29.92 in. Hg).
JJ = Tdeal gas constant, 0.06236 (mm Hg) (m')/
(g-mole) (°K) for metric units and 21.85
(in. Hg) (ft»)flb-mole) (°B) for English
units.
T.=Absolute temperature at meter, °K (°R)
r,,j=Standard absolute temperature, 293° K
(528° H)
Vi=Final volume of impinger contents, ml.
Vi=Initial volume of impinger contents, ml.
V.-Dry gas volume measured by dry gas meter,
dcm (dcf).
V.(.u)=Dry gas volume measured by dry gas meter,
corrected to standard conditions, dscm
(dscf).
V.,c,u)=Volume of water vapor condensed, corrected
to standard conditions, scm (scf).
*.-Density of water, 0.9982 g/ml (0.002201 Ib/ml).
3.3.2 Volume of water vapor collected.
P.aM.
Equation 4-5
vbere:
Ki=0.001333 mi/ml for metric units
=0.04707 ft'/ml for English units.
3.3.3 Oaa volume.
y
Equation 4-0
»tere:
£-1=0.3868 °K/mm Hg for metric units
-17.M °B/in. Hg for English units
3.3.4 Approximate moisture content.
D v..
+(0.025)
4. Calibration
Equation 4-7
4.1 For the reference method, calibrate equipment aa
specified In the foUowir,* sections of Method 6: Section 5.1
(metering system); Section S.5 (temperature gauges);
and Section 5.7 (barometer). The recommended leak
check of the metering system (Section 5.6 of Method 5)
also applies to the reference method. For the approxima-
tion method, use the procedures outlined In Section 5.1.1
of Method 6 to calibrate the metering system, and tbe
procedure of Method 5, Section 5.7 to calibrate the
barometer.
5. BMIofrapht
1. Air Pollution Engineering Manual (Second Edition).
Danielson, I. A. (ed.). U.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards.
Research Triangle Park, N.C. Publication No. AP-tO.
1973.
2. Devorkin, Howard, et al. Air Pollution Source Test-
ing Manual. Air Pollution Control District, Los Angeles,
Calif. November, 1963.
3. Methods for Determination of Velocity, Volume,
Dust and Mist Content of Oases. Western Precipitation
Division of Joy Manufacturing Co., Los Angeles, Calif.
Bulletin WP-50. 1968.
METHOD 5— DETERMINATION or FARTICUUTK EMISSIONS
FROM STATIONARY SOURCES
1. Princiftt and AppUcabUUf
1.1 Principle. Paniculate matter la withdrawn Iso-
kinetically from the source and collected on a glass
fiber filter maintained at a temperature in the range of
120±14* C (248±2S° F) or such other temperature aa
specified by an applicable subpart of the standards or
approved by the Administrator, U.S. Environmental
Protection Agency, for a particular application. The
particulate masa, which Includes any material that
condenses at or above the filtration temperature, la
determined gravimetrically after removal of uncombined
water.
1.2 Applicability. This method is applicable for tbe
determination of paniculate emissions from stationary
sources.
2. Apparatus
2.1 Sampling Train. A schematic of the sampling
train used in this method is shown In Figure 5-1. Com-
plete construction details are given In APTD-0581
(Citation 2 in Section 7); commercial models of this
train are also available. For changes from APTD-0581
and for allowable modifications of tbe tram shown In
Figure 5-1, see the tollowln subsections.
The operating and maintenance procedures for the
sampling tram are described In APTD-0676 (Citation 3
in Section 7). Since correct usage is Important In obtain-
ing valid results, all users should read APTD-0576 and
adopt tbe operating and maintenance procedures out-
lined In it, unless otherwise specified herein. Tbe sam-
pling train consists of the following components:
KDIRAL UGISTH. V04, 41, NO. !«•—THUXSDAY, AUGUST It, 1977
V-192
-------
QPWii 'AM® Rli©yiAYD©MS
ORHPIWGER TRAIifl OPTIONAL, MAY SE REPLACED
• ©V AW EQUIVALENT COftJDEWSER
THERMOMETER
1TEMIP
e^ ._
HEATEO AREA THERMOMETER
FILTER HOLDER
REVERSE-TYPE
P1TOT MANOMETER OMPIWGERS ICE BATH
BY-PASS VALVE
CHECK
VALVE
VACUUM
UNE
VACUUM
GAUGE
THERMOMETERS
DRY GAS METER
VALVE
AIR-TJG.HT
Fjgure 5 1. Particulate-sampling train.
2.1.1 Probe Nozzle. Stainless steel (316) or glass with
den), tapered leading edge. The angle of taper shall
to
-------
RULES AND REGULATIONS
i ho absolute Iwomctric pressure) shall be requested »nd
•in adjustment (or elevation differences between the
weather station and sampling point shall be applied at a
rate of mlnns -'.5 mm Hg (0.1 In. Hg) per 30 m (100 ft)
iWation increase or vice versa (or elevation decrease.
•1 1 10 Clas Density Determination Equipment.
Temperature sensor and pressure gauge, 09 described
in Sections 2.3 and 2.4 of Method 2, and gas analyter,
if necessary, as described in Me.thod 3. The temperature
u-nsor shall, preferably, be permanently attached to
1 he pilot lube or sampling probe in a fixed configuration,
such that the tip of the sensor extends beyond the leading
edge of the probe sheath and docs not touch any metal.
Alternatively, the sensor may be attached Just prior
to use in the Held. Note, however, that if the temperature
M'nsor is attached in the field, the sensor must be placed
in an interference-free arrangement with respect to the
Type 8 pitot tube openings (see Method 2, Figure 2-7).
As a second alternative, if a diilerence of not more than
I percent in the average velocity measurement is to be
introduced, the temperature gauge need not be attached
to tb.e probe or pilot tube. (This alternative Is subject
to the approval of the Administrator.)
2.2 Sample Recovery. The following items are
needed:
2.2.1 Probe-Liner and Probe-Noitle Brushes. Nylon
bristle brushes with stainless steel wire handles. The
probe brush shall have extensions (at least as long as
the probe) of stainless steel, Nylon, Teflon, or similarly
inert material. The brushes shall be properly sized and
shaped to brush out the probe liner and noule.
2.2.2 Wash Dottles— Two. Glass wash bottles are
recommended; polyethylene wash bottles may be used
at the option of the tester. It is recommended that acetone
not be stored in polyethylene bottles for longer than a
month.
2.2.3 Olass Sample Storage Containers. Chemically
resistant, borosilicate glass bottles, for acetone washes,
600 ml or 1000 ml . Screw cap liners shall either be rubber-
backed Teflon or shall be constructed so as to be leak-free
and resistant to chemical attack by acetone. (Narrow
mouth glass bottles have been found to be less prone to
leakage.) Alternatively, polyethylene bottles may be
used.
2.2.4 Petri Dishes. For niter samples, gla«s or poU-
ethylene, unless otherwise specified by the Admin-
istrator.
• 2.2.5 Graduated Cylinder and/or Balance. To meas-
ure condensed water to within 1 ml or 1 g. Graduated
cylinders shall have subdivisions no greater than 2 ml.
Most laboratory balances are capable of weighing to the
nearest 0.5 g or less. Any of these balances Is suitable for
use here and iu Section 2.3.4.
2 2.6 Plastic Storage Containers. Air-tight containers
to store silica gel.
2.2.7 Funnel and Rubber Policeman. To aid in
transfer of silica gel to container: not necessary if silica
gel is weighed in the field.
2.2.8 Funnel. Glass or polyethlene, to aid in sample
recovery.
2.3 Analysis. For analysis, the following equipment is
needed.
2.3.1 Glass Weighing Dishes.
2.3.2 Desiccator.
2.3.3 Analytical Balance. To measure to within 0.1
mg.
2.3.4 Balance. To measure to within 0.5 g.
2.3.5 Beakers. 250 ml.
2.3.6 Hygrometer. To measure the relative humidity
of the laboratory environment.
2.3.7 Temperature Gauge. To measure the tempera-
ture of the laboratory environment.
3. Rtagrntl
3.1 Sampling. The reagents used in sampling are aa
follows:
3.1.1 Filters. .Glass fiber filters, without organic
binder, exhibiting at least 99.95 percent efficiency (<0.05
ntha
,
percent penetration) on 0.3-micron dioctyl p
smoke particles. The niter efficiency test shaft be con
.
halate
e con-
ducted In accordance with A8TM standard method D
2986-71. Test data from the supplier's quality control
program are sufficient for this purpose.
3.1.2. Silica Gel. Indicating type, 6 to 16 mesh. If
previously used, dry at 175° C 1350* F) for 2 hours. New
silica gel may be used as received. Alternatively, other
types of desiccants (equivalent or better) may be used,
subject to the approval of the Administrator.
3.1.3 Water. When analysis of the material caught in
the impingers is required, distilled water shall be used.
Run blanks prior to field use to eliminate a high blank
on test samples.
3.1.4 Crushed Ice.
3.1.5 Stopcock Grease. Acetone-insoluble, heat-stable
silicone grease. This is not necessary if screw-on con-
nectors with Teflon sleeves, or similar, are used. Alterna-
tively, other types of stopcock grease may be used, sub-
ject to the approval of the Administrator.
3.2 Sample Recovery. Acetone— reagent grade, <0.001
ficreent residue, in glass bottles — is required. Acetone
rom metal containers generally has a hign residue blank
and should not be used. Sometimes, suppliers transfer
acetone to glass bottles from metal containers; thus,
acetone blanks shall be run prior to field use and only
acetone with low blank values (<0.001 percent) shall be
used. In no case shall a blank value of greater than 0.001
percent of the weight of acetone used be subtracted from
the sample weight.
3.3 Analysis. Two reagents are required for the analy-
sis:
3.3.1 Acetone. Same as 3.2.
3.3.2 Deslccant. Anhydrous calcium sulfate, Indicat-
ing type. Alternatively, other types of desiccants may be
used, subject to the approval of the Administrator.
4. Protttuti
4.1 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.
4.1.1 Pretest Preparation. All the components shall
be maintained and calibrated according to the procedure
described in APTD-0576, unless otherwise specified
herein.
Weigh several 200 to 300 g portions of silica gel in air-tight
containers to the nearest 0.5 g. Record the total weight of
the silica gel plus container, on each container. As an
alternative, the silica gel need not be preweighed, but
may be weighed directly in its impinger or sampling
holder just prior to train assembly.
Check filters visually against light for irregularities and
flaws or pinhole leaks. Label niters of the proper diameter
on the back side near the edge using numbering machine
ink. As an alternative, label the shipping containers
(glass or plastic petri dishes) and keep the niters in these
containers at all times except during sampling and
weighing.
Desiccate the filters at 20±5.6° C (68±10° F) and
ambient pressure for at least 24 hours and weigh at in-
tervals of at least 6 hours to a constant weight, I.e.,
<0.5 mg change from previous weighing; record results
to the nearest 0.1 mg. During each weighing the filter
must not be exposed to the laboratory atmosphere for a
period greater than 2 minutes and a relative humidity
above 50 percent. Alternatively (unless otherwise speci-
fied by the Administrator), the filters may be oven
dried at 105° C (220° F) for 2 to 3 hours, desiccated for 2
hours, and weighed. Procedures other than those de-
scribed, which account for relative humidity effects, may
be used, subject to the approval of the Administrator.
4.1.2 Preliminary- Determinations. Select the sam-
pling site and the minimum number of sampling points
according to Method 1 or as specified by the Administra-
tor. Determine the stack pressure, temperature, and the
range of velocity heads using Method2; it is recommended
that a leak-check of the pitot lines (see Method 2, Sec-
tion 3.1) be performed. Determine the moisture content
using Approximation Method 4 or its alternatives for
the purpose of making isoKinetic sampling rate settings.
Determine the stack gas dry molecular weight, as des-
cribed in Method 2, Section 3.6; if integrated Method 3
sampling is used for molecular weight determination, the
integrated bag sample shall be taken simultaneously
with, and for the same total length of time as, the par-
ticulate sample run.
Select a nozzle size based on the range of velocity heads,
such that it is not necessary to change the nozzle size iu
order to maintain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure that the
proper differential pressure gauge is chosen lor the range
of velocity heads encountered (see Section 2.2 of Method
2).
Select a suitable probe liner and probe length such that
all traverse points can be sampled. For large stacks,
consider sampling from opposite sides, of the stack to
reduce the length of probes.
Select a total sampling time greater than or equal to
the minimum total sampling time specified in the test
procedures for the specific industry such that (1) the
sampling time per point is not less than 2 min (or some
greater time interval as specified by the Administrator),
and (2) the sample volume taken (corrected to standard
conditions) will exceed the required minimum total gas
sample volume. The latter Is based on an approximate
average sampling rate.
It is recommended that the number of minutes sam-
pled at each point be an integer or an integer plus one-
half minute, in order to avoid timekeeping errors.
In some circumstances, e.g., batch cycles, It may be
necessary to sample for shorter times at the traverse
points and to obtain smaller gas sample volumes. In
these cases, the Administrator's approval must first
be obtained.
4.1.3 Preparation of Collection Train. During prep-
aration and assembly of the- sampling train, keep all
openings where contamination can occur covered until
Just prior to assembly or until sampling is about to begin.
Place 100 ml of water in each of the first two impingers,
leave the third impinger empty, and transfer approxi-
mately 200 to 300 g of preweighed silica gel from ita
container to the fourth impinger. More silica gel may b*
used, but care should be taken to ensure that it Is not
entrained and carried out from the impinger during
sampling. Place the container hi a clean place for later
use in the sample recovery. Alternatively, the weight of -
the silica gel plus Impinger may, be determined to the.
nearest 0.5 g and recorded.
Using a tweexer or clean disposable surgical gloves,
place a labeled (Identified) and weighed filter in the
filter holder. Be sure that the filter is properly centered
and the gasket properly placed so as to prevent the
sample gas stream from circumventing the filter. Check
the filter for tears after assembly is completed.
When glass liners are used, Install the selected noule
using a Viton A O-ring vhen stack temperatures ire
less than 260° C (600° F) and an asbestos string gasket
when temperatures are higher. See APTD-0676 lor
details. Other connecting systems using either 316 stain
less rteel or Teflon ferrules may be used. When metal
liners are used, Install the noule as above or by • leak-
free direct mechanical connection. Mark the probe with
heat resistant tape or by some other method to denote
the proper distance into the stack or duct for each sam-
pling point.
Set up the train as in Figure 5-1, using (if necessary)
a very light' coat of silicone grease on all ground glass
Joints, greasing only the outer portion (see APTD-0576)
to avoid possibility of contamination by the silicone
grease. Subject to the approval of the Administrator, a
glass cyclone may be used between the probe and filter
Bolder when the total partlculate catch is expected to
exceed 100 mg or when water droplets are present In the
stack gas.
Place crushed ice around the Impingers.
4.1.4 Leak-Check Procedures.
4.1.4.1 Pretest Leak-Check. A pretest leak-check is
recommended, but not required. If the tester opts to
conduct the pretest leak-check, the following procedure
shall be used.
After the sampling train has been assembled, turn on
and set the filter and prone heating systems at the desired
operating temperatures. Allow time for the temperatures
to stabilize. If a Viton A O-ring or other leak-free connec-
tion is used in assembling the probe noitle to the probe
liner, leak-check the train at the sampling site by plug-
ging the nottle and pulling a 380 nun Hg (19 in. Hg)
vacuum.
NOTE.—A lower vacuum may be used, provided that
it is not exceeded during the test.
If an asbestos string is used, do not connect the probe
to the train during the leak-check. Instead, leak-check
the train by first plugging the inlet to the filter bolder
(cyclone, if applicable) and pulling a 380mm Hg (15 in.
Hg) vacuum (see Note immediately above). Then con-
nect the probe to the train and leak-check at about 25
mm Hg (1 in. Hg) vacuum; alternatively, the probe may
be leak-checked with the rest of the sampling train, in
one step, at 380 mm Hg (15 in. Hg) vacuum. Leakage
rates in excess of 4 percent of the average sampling rate
or 0.00057 m'/mln (0.02 cfm), whichever is less, are
unacceptable.
The following leak-check instructions for the sampling
train described in APTD-0576 and APTD-0581 may be
helpful. Start the pump with bypass valve fully open
and coarse adjust valve completely closed. Partially
open the coarse adjust valve and slowly close the bypass
valve until the desired vacuum is reached. Do not reverse
direction of bypass valve; this will cause water to back
up into the filter holder. If the desired vacuum is ex-
ceeded, either leak-check at this higher vacuum or end
the leak check as shown below and start over.
When the leak-check is completed, first slowly remove
the plug from the inlet to the probe, filter holder, or
cyclone (if applicable) and immediately turn off the
vaccum pump. This prevents the water in the impingers
from being forced backward into the filter holder and
silica gel from being entrained backward into the third
impinger.
4.1.4.2 Leak-Checks During Sample Run. If, during
the sampling run, a component (e.g., filter assembly
or impinger) change becomes necessary, a leak-check
shall be conducted immediately before the change is
mode. The leak-check shall be done according to the
procedure outlined in Section 4.1.4.1 above, except that
It shall be done at a vacuum equal to or greater than the
maximum value recorded up to that point in the test.
If the leakage rate is found to be no greater than 0.00057
m'/mln (0.02 cfm) or 4 percent of the average sampling
rate (whichever is less), the results are acceptable, and
no correction will need to be applied to the total volume
of dry gas metered; if, however, a higher leakage rate
Is obtained, the tester shall either record the leakage
rate and plan to correct the sample volume as shown m
Section 6.3 of this method, or shall void the sampling
run.
Immediately after component changes, leak-checks
are optional; if such leak-checks are done, the procedure
outlined in Section 4.1.4.1 above sbaU be used.
4.1.4.3 Post-test Leak-Check. A leak-check is manda-
tory at the conclusion of each sampling run. The leak-
check shall be done in accordance with the procedures
outlined In Section 4.1.4.1. except that It shall be con-
ducted at a vacuum e
-------
Take other readings required by Figure 5-2 at least ODOQ
at each sample point during each time increment and
c&litional readings when significant changes (20 percent
variation in velocity bead readings) necessitate addi-
tional adjustments in Dow rate. Level and zero the
manometer. Because the manometer level and zero may
drift due to vibrations and temperature changes, make
periodic checks during the traverse.
Clean tho portholes prior to tho teat ran to mlnimlco
tho cbanco of campling deposited materiel. To begin
sampling, remove the nozzle cap, verify that the filter
and proba heating systems are up to temperature, and
that the pilot tube and probe are properly positioned.
Position the nozzle at the first traverse point with the tip
pointing directly Into the gas stream. Immediately start
the pump and adjust the Sow to Isokinetic conditions.
Nomographs are available, which aid in the rapid adjust-
ment cf the lEoktaette sampling rate without excessive
compntatlono. Thesa nomographs are designed for use
when the Type 8 pilot tube coefficient Is 0.85±0.02. and
tha stack gas equivalent density (dry molecular weight)
is equal to 29±4. APTD-0676 details the procedure for
using the nomographs. If C, and Ma are outside the
above stated ranges do not use the nomographs unless
appropriate steps (see Citation 7 in Section 7) are taken
to compensate for the deviations.
PLANT.
LOCATION.
OPERATOR,.
OATE
RUM MO
SAMPLE BOX W0._
METER SOX WO. _
METER AH@=
6 FACTOR
AMBIENT TEMPERATURE.
BAROMETRIC PRESSURE.
ASSUMED MOISTURE. 95 _
PROBE lEWGTH.m (ft)
PITOT TUBE COEFFICIENT, Cp.
SCHEMATIC OF STACK CROSS SECTION
•NOZZLE IPEWTIFICATIOM MO
AVERAGE CALIBRATED NOZZLE DIAMETER, cm (in.).
PROBE HEATER SETTING
LEAK RATE. m3/min,{cfm)
PROBE LINER MATERIAL
STATIC PRESSURE, mm HB (In. HoL
FILTER NO
TRAVERSE POINT
. NUMBER
TOTAL
SAMPLING
TIME
(01. min.
AVERAGE
VACUUM'
mm Hg
(In. Hg)
STACK
TEMPERATURE
-------
RULES AND REGULATIONS
fitting, probe UNIT, and front 1\alf of the filter hoMw by
washing those oompoueuts with acetone and placing the
u ;ish in a glass container. Distilled water may b« used
instead of acetone wheo approved by the Administrator
und shall be. used when spwiflnd by the Administrator;
in these caw, save a water blank and follow the Admin-
istrator's dim-.tums un analysis. Perform the acetone
rinses as follows:
i 'aivfnlly ft siun-e the prul*1 r.oiulr and cltHin the inside
•surface !•>•'Mil-mi: with in-i-ioiu' from a wasli bottle and
brush)up*«i:ii ;v i»ylou bi 1st le .brush. It rush until the-
:uWone rii^e *hciws no visible puMiclcs, after which
make a tinitl rins«- of ilv i;iMe li;'«-r wiih a<.-nono by tilling and
riikiiii!-.: thr pru*v while 5« [inn iny ai-'.-ioiiii imo its upper
t:nl ?-»'ih:ii sill in container. A funnel ^gla.-=s or polyethylene.) may
IT usc-d to aid in :ransferring liquid washes in the con-
lairu-r. Follow lite niyione rinse, wiih a probe Inush.
Hold iht1 probe in au iucliin-d position, sqniri iu-«'ione
inlo the upper end as the pvobo bru^h is U-intr pnslied
with a twisting a<'iio>i ihrongh the pro!*1: hold a sample
roniaincr uiKlern.-ath (be lowr end of »he prolM*. and
i-rttrh any acetone and jKirticiilate matter which is
brushed from tho probe. Him the brush ihrough the
probe three timnp or more uinll no visible paniculate
inattpr is carried out with the :ircto:ie or until none
remains in the pro*>e liin-r on visual insix-rtion. With
rainless ?re«*l or other metal prol^-s, run the brush
ihrouph in ihe abovi- piesi-ril'-i-d iniunu-r at least six
limes siix-e im-ial piul»rs have small ere vices in which
paniculate niatti-1" can be ••cirapivd. Hi use the brush
with acetone, and rniantiiamvly collect these washings
in i he sample coniaitn-r. A(tt>r the brushing, make a
final acetone rinse of the prob** as described above.
It is recommended that two people be used to clean
the probe to minimize ."ample losses. Between sampling
rnn«, keep brushes clean and protected from contamina-
tion.
After ensuring that all joints have been wiped clean
of silicone grease, clean the inside of the front half of the
lilter holder by rubbing the surfaces with a nylon bristle
brush and rinsing with acetone. Rin£« each surface
three times or more if needed to remove visible paaticu-
)ate. Make a linal rinse of the, bni>b and tiller holder.
Carefully rinse'out the glass cyclone, also (if applicable).
After all acetone washings and paniculate matter have
been collected in the sample container, tighten the lid
on the sample container M> that acetone will not leak
out when it is shipped to the laboratory. Mark the
tteight of the MM id level to determine whether or not
leakage oerurrcd during transport. Label the container
to clearly identify its contents.
Container -Vo. 4. Note the color of the indicating silica
gel to determine if it has been Completely spent aim make
a notation of its condition. Transfer the silica gel from
the fourth impinger to its original container and seal.
A funnel may make it easier to pour the silir agel without
spilling. A mbb«r policeman may be used as an aid in
removing the silica gel from the impinger. It is nut
necessary to remove the t>mall 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, follow the procedure for container'No. 3
in Section 4.3.
Impinger Water. Treat the impingers as follows; Make
a notation of any color or film in the liquid catch. Measure
the liquid which is in the first three impingers to within
±1 ml by using a graduated cylinder or by weighing it
to within *0.fl g by using a balance 'if one is available).
Record the volume or weight of liquid present. This
information is required to calculate the moisture content
of the effluent gas.
Discard the liquid after measuring and recording the
volume or weight, unless analysis of the impinger catch
is required (see Note, Section 2.1.7).
If a ditferent type of condenser is used, measure the
amount of moisture condensed either volurnetrkally or
gravimetrically.
Whenever possible, containers should be shipped in
such a way that they remain upright at all times.
4.3 Analysis. Record the data required on a sheet
such as the one shown in Figure ir3. Handle each sample
container as follows;
Container No. 1. Leave the contents in the shipping
container or transfer the filter and any loot* paniculate
from the sample container to a tared glass weighing dish.
Desicrate for 24 hours in a desiccator containing anhy-
drous calcium sulfate. Weigh to a constant weight and
n-port the results to the nearest 0.1 mg. For purposes of
this Section. 4.3, the term "constant weight" means a
difference of no more than 0.5 nig or 1 percent of total
weight less tare weight, whichever is greater, between
two consecutive weighings, with no less than 6 hours of
desiccation time between weighings.
Plant.
Date.
Run No..
Filter No.
Amount liquid lost during transport
Acetone blank volume, ml
Acetone wash volume, ml
Acetone blank concentration, mg/mg (equation 5-4).
Acetone wash blank, mg (equation 5-5}
CONTAINER
NUMBER
1
2
TOTAL
WEIGHT OF PARTICIPATE COLLECTED.
mg
FINAL WEIGHT
Less acetoi
Weight of p:
TARE WEIGHT
Izxr
ie blank
articulate matter
WEIGHT GAIN
FINAL
INITIAL
LIQUID COLLECTED
TOTAL VOLUME COLLECTED
VOLUME OF LIQUID
WATER COLLECTED
IMPINGER
VOLUME,
ml.
SILICA ca
WEIGHT.
9
8*| ml
* CONVERT WEIGHT OF WATER TO VOLUME BY DIVIDING TOTAL WEIGHT
INCREASE BY DENSITY OF WATER (1fl/ml).
INCREASE, g. . VOLUME WATER ^,
1 a/ml
Figure 5-3. Analytical data.
KOERAL UCiSTHI. VOt, 42. NO. 160—THURSDAY, AUGUST 1«, 1977
V-196
-------
•QUIES AND KIGULA¥I©WS
Alternatively, the sample may be oven dried at 105° C
(220° F) for 2 to 3 hours, cooled in the desiccator, and
uelghed to a constant weight, unless otherwise specified
by tiie Administrator. The tester may also opt to oven
dry the sample at 106 ° C (220 ° F) for 2 to 3 hours, weigh
She sample, and use this weight as a final weight.
Container No. S. Note the level of liquid in the container
end confirm on the analysis sheet whether or not leakage
occurred during transport. If e noticeable amount of
leakage has occurred, either void the sample or use
methods, subject to the approval of the Administrator,
to correct the final results. Measure the liquid in this
container either volumetrically to ±1 ml or gravl-
metrically to ±0.5 g. Transfer the contents to a tared
250-ml beater and evaporate to dryness at ambient
temperature and pressure. Desiccate for 24 hours and
weigh to o constant weight. Report the results to the
nearest 0.1 mg.
Container No. 3. Weigh the spent silica gel (or silica gel
inger) to the nearest 0.5 g using a balance. This
plus impin
otep may be conducted in the field.
"Acetone Blank" Container. Measure acetone in this
container either volumetrically or gravimetrically.
Transfer the acetone to a tared 250-ml beaker and evap-
orate to dryness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a contsant weight.
E&eport the results to the nearest 0.1 mg.
NOTE.—At the option of the tester, the contents of
Container No. 2 as well as the acetone blank container
may be evaporated at temperatures higher than ambi-
ent. If evaporation Is done at an elevated temperature,
ihe temperature must be below the boiling point of the
colvent; also, to prevent "bumping," the evaporation
process must be closely supervised, and the contents of
the beaker must be swirled occasionally to maintahi an
oven temperature. Use extreme care, as acetone is highly
flammable and has a low flash point.
&. Calibration
Maintain a laboratory log of all calibrations.
5.1 Probe Nozzle. Probe nozzles shall be calibrated
before their Initial use in the field. Using a micrometer,
measure the Inside diameter of the nozzle to the nearest
0.025 mm (0.001 in.). Blake three separate measurements
using different diameters each time, and obtain the aver-
age of the measurements. The difference between the high
and low numbers shall not exceed 0.1 mm (0.004 in.).
When nozzles become nicked, dented, or corroded, they
shall be reshaped, sharpened, and recalibrated before
use. Each nozzle shall be permanently and uniquely
identified.
5.2 Pitot Tube. The Type 8 pltot tube assembly shall
be calibrated according to the procedure outlined in
Section 4 of Method 2.
5.3 Metering System. Before its initial use in the field,
the metering system shall be calibrated according to the
procedure outlined in APTD-0576. Instead of physically
adjusting the dry gas meter dial readings to correspond
to the wet test meter readings, calibration factors may be
used to mathematically correct the gas meter dial readings
to the proper values. Before calibrating the metering sys-
tem, It is suggested that a leak-check be conducted.
For metering systems having diaphragm pumps, the
normal leak-check procedure will not detect leakages
within the pump. For these cases the following leak-
check, procedure is suggested: make a 10-minute calibra-
tion run at 0.00057 m '/mln (0.02 eta); at the end of the
run, take the difference of the measured wet test meter
and dry gas meter volumes: divide the difference by 10.
to get the leak rate. The leak rate should not exceed
0.00057 m >/min (0.02 elm).
After each field use, the calibration of the metering
system shall be checked by performing three calibration
runs at a single, intermediate orifice setting (based on
the previous field test), with the vacuum set at the
maximum value reached during the test series. To
adjust the vacuum, insert a valve between the wet test
meter and the inlet of the metering system. Calculate
the average value of the calibration factor. If the calibra-
tion has changed by more than 5 percent, recalibrate
the meter over the lull range of orifice settings, as out-
lined in APTD-0576.
Alternative procedures, e.g., using the orifice meter
coefficients, may be used, subject to the approval of the
Administrator.
NOTE.—If the dry gas meter coefficient values obtained
before and after a test series differ by more than 5 percent,
the test series shall either be voided, or calculations for
the test series shall be performed using whichever meter
coefficient value (I.e., before or after) gives the lower
value of total sample volume.
6.4 Probe Heater Calibration. The probe heating
system shall be calibrated before its Initial use In the
field according to the procedure outlined in APTD-0576.
Probes constructed according to APTD-0581 need not
be calibrated If the calibration curves In APTD-0576
are used.
5.5 Temperature Gauges. Use the procedure In
Section 4.3 of Method 2 to calibrate in-stack temperature
gauges. Dial thermometers, such as are used for the dry
gas meter and condenser outlet, shall be calibrated
against merciiry'ln-glass thermometers.
5.6 Leak Check of Metering System Shown In Figure
5-1. That portion of the sampling train from the pump.
to the orifice meter should be leak checked prior to initial
use and after each shipment. Leakage after ihe pump will
result in less volume being recorded than Is actually
sampled. The following procedure is suggested (see
Figure 5-4): Close the main valve on the meter box.
Insert a one-hole rubber stopper with rubber tubing
attached into the orifice exhgust pipe. Disconnect and
vent the low side of the orifice manometer. Close off the
low side orifice tap. Pressurize the system to 13 to 18 cm
(6 to 7 in.) water column by blowing Into the rubber
tubing. Pinch off the tubing and observe the manometer
for one minute. A loss of pressure on the manometer
Indicates a leak In the meter box; leaks, If present, must
be corrected.
£.7 Barometer. Calibrate against a mercury barom-
eter.
6. Calculations
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after the final calculation. Other forms of the
equations may be used as long as they give equivalent
results. ^
VACUUM
GAUGE '
Figure 5-4. Leak check of meter box.
ai Nomenclature R
XIn =Cross-secUooal area of nozzle, m> (ft').
Bra "Water vapor ID the gas stream, proportion TD <
by volume.
Ca "Acetone blank residue concentrations, ms/g. T. <
. e, = Concentration of paniculate matter in stack
BC3. dry bests, corrected to standard oondi- T,a >
tlons, g/dscm (g/dscf).
' "Percent of IsokTnetic sampling. V0 i
La "Maximum acceptable leakage rate for either a V00 >
pretest leak check or for a leak check follow- V,,
IDS o component change; equal to 0.00057
m'/mln (0.02 cfm) or 4percent of the average Va
campling rate, whichever is less.
Li "Individual leakage rate observed during the Foj.m)
leak check conducted prior to the ' I""
component change (1=1, 2, 8 .... o),
• m»/min(cfm). V0(.,,i>>
X>> "Leakage rate observed during the post-test
lead check, m'/mln (cfm). V.<
do a Total amount of paniculate motter collected,
mg.
Mo "Molecular weight of water, 18.0 B/g-mole I7o<
(IS.Olb/lbtmole). y.
Oo =M£(a of residue of ccetono after evaporation, AH'
IPtxj "Barometric pressure ot tts csmplin-7 alto, p0<
mm Hg (In. Hg).
PC «AbcaluteBteckgaspre^nro,mmHg(ln. Hs); PO<
JPcM oStcndard abeolnu pressure, 7CO mm Hn
. (23.03 in, Hs). . 0.
=Ideal gas constant, 0.08238 mm Hg-m»/°K-g-
mole (21.85 In. Hg-ft>/°R-lb-mole).
Absolute average dry gas meter tempareture
(see Figure 5-2), °K (°R).
Absolute average stack gas temperature (sea
Figure 5-2), °K(°R).
Standard absolute temperature, 293° K
(528° R). -
Volume of acetone blank, ml.
Volume of acetone used in wash, ml.
Total volume of liquid collected in Implngers
end sillco gel (see Figure 5-3), ml.
Volume of gas sample as measured by dry gas
meter, dcm (dcf).
3Volume of gas sample measured by the dry
BBS meter, corrected to standard conditions,
dscrn (dscfr
Volume of water vapor In the gas sample,
corrected to standard conditions, scm (set).
8tacl£ ROS velocity, calculated by Method 2,
Kquatior, 2-0, using data obtained from
Method 6, m/ssc (ftfcec).
*Weight of residue in acetone wash, rag.
Dry gas meter calibration factor.
Average pressure differential across the orifice
meter (CM Figure 5-2), mm HiO (In. HiO).
Denaity of coatone, ma/ml (cs> label on
bottle).
Density ef OTitor, 0.6832 a/ml (0.002201
Ib/ml).
Total sampling time, nun.
0j=8ampling time Interval, from the beginning
of a run until the first component'change,
mm.
0t=Sampling tune Interval, between two cue-
cessive component changes, beginning TTlth
the interval between the first and second
changes, mln.
0,=Sampling time Interval, from the final (nlh)
component change until the end of the
campling run, min.
13.6=Specific gravity of mercury.
60=Sec/min.
100=Conversion to percent.
6.2 Average dry gas meter temperature and average
orifice pressure drop. See data sheet (Figure 5-2).
0.3 Dry Oos Volume. Correct the sample volume
measured by the dry gas meter to standard conditions
(20° C, 760 mm Hg or 68° F, 29.92 in. Hg) by using
Equation 5-1.
02, K)S>. 1 S@— WJUQSBAY,
V-197
HO.
-------
RULES AND REGULATIONS
*mf^0 3SA8 'K/ram Hg for metric unit*
-17.M°R/in. Hg for English unit*
NOTB.—Equation 5-1 can b« used as written unles*
the leakage rate observed during any of the mandatory
leak checks (I.e., the post-test leak check or leak checks
conducted prior to component changes) exceeds £.. II
t, or In exceeds L,, Equation 5-1 must be modified u
follows;
(a) Case I. No component changes made during
sampling nin. In this case, replace V. in Equation 5-1
with the expression; ,,
Vm-(L,-L.)t] .
Cb) Case II. One or more component changes made
during the sampling run. In this case, replace Vm in
Equation 5-1 by the expression:
Non.—In saturated or water droplet-laden BM
streams, two calculations of the moisture content of to*
stack gas shall be made, one from the Impingar analyel*
(Equation 5-3), and a second from the assumption ol
saturated conditions. The lower of the two values of
B_ shall be considered correct. The procedure f«r deter-
mining the moisture content based upon assumption ol
saturated conditions la given In the Note of Section LI
of Method 4. For the purposes of this method, the average
itack gas temperature from Figure 5-2 may be used to
make this determination, provided that the accuracy ol
the in-etack temperature sensor is ± 1° C (2° F).
66 Acetone Blank Concentration.
n —
\- a — Tr
\
6.7 Acetone Wash Blank.
Equation 5-4
and substitute only for those leakage rates (Li or L,)
which exceed L..
Equation 5-5
6.8 Total Partlculate Weight. Determine the total
paniculate catch from the sum of the weights obtained
from containers 1 and 2 less the acetone blank (see Fignn
5-3). Not*.— Refer to Section 4.1.5 to assist In calculation
of results Involving two or more, filter assemblies or two
or more sampling train*.
6.9 Paniculate Concentration.
6.4 Volume of water vapor.
where:
A")=0.001333 mi/ml for metric units
=0.04707 ft'/ml (or English units.
6.5 Moisture Content.
D Vu (,,d)
Equation 5-2
I'm (lid) + ^* <«!d)
6.10
From
Ml
g.W
g/ft«
c,= (0.001 glmg) (m
Conversion Factors:
To
m«
Rr/ft'
lb/ft«
£/m'
Equation 5-8*
Multiply by
0.02832
15.43
2.205X10-*
35.31
Equation 5-3
6.11 Isokinetic Variation. •
6.11.1 Calculation From Raw Data.
100 T.I
, + Aff/13.6)]
T.Vm ,„#
where:
Ki^o.003454 mm Hg— m'/ml— °K for metric units.
-0.002669 in. Hg-ftVml-°R for English units.
6.11.2 Calculation From Intermediate Values.
7=
Equation 5-8
whfre:
Jfi=4.320 for metric units
=0.09450 for English units. \
6.12 Acceptable Results. If 90 percent ). Although no upper limit has been
established, tests have shown that concentrations as
high as 80,000 mg/m> of SOi can be collected efficiently
in two midget impingcrs, each containing 15 milliliters
of 3 percent hydrogen peroxide, at a rate of 1.0 1pm for
20 minutes. Based on theoretical calculations, the upper
concentration limit in a 20-liter sample is about 93,300
mg/m3.
Possible interferents are free ammonia, water-soluble
cations, and fluorides. The cations and fluorides are
removed by glass wool filters and an isopropanol bubbler,
and hence do not affect the SO. analysis. When samples
are being taken from a gas stream with high concentra-
tions of very fine metallic fumes (snch as in inlets to
control devices), a high-efficiency glass fiber filter must
be used io place of the glass wool plug (i.e., the one in
the probe) to remove the cation interferents.
Free anunonia interferes by reacting with SOi to form
particulate sulfite and by reacting with the indicator.
If free ammonia is present (this can be determined by
knowledge of the process and noticing white particulate
matter in the probe and isopropanol bubbler), alterna-
tive methods, subject to the approval of the Administra-
tor, U.S. Environmental Protection Agency, are
required.
2. Apparatus
FEDERAL REGISTER. VOL 42, NO. 160—THURSDAY, AUGUST IS, 1977
V-198
-------
RULES AND REGULATIONS
PROBE (END PACKED'
WITH QUARTZ OR
PYREX WOOL)
•si,
j\
-j
* STACK WALL
X.
GLASS
fc
win
WOOL
V
-
V
MIDGET IMPINGERS
THERMOMETER
MIDGET BUBBLER
ICE BATH
THERMOMETER
SILICA GEL
DRYING TUBE
RATE METER NEEDLE VALVE
PUMP
Figure 6-1. Sp2 sampling train.
SURGE TANK
1.1
•-L and component parts «n discussed below'
tatter has the option of substituting sampling equip-
ment described In Method 8 In place of the midget Im-
plnger equipment of Method 6. However, the Method 8
train most be modified to include a heated JUWr between
the probe tod Isopropanol implnger, and the operation
of the sampling train and sample analysis most be at
the now rates and solution volumes defined In Method 8.
The tester also has the option of determining SOj
simultaneously with particnlate matter and moisture
determinations by (1) replacing the water in a Method S
Implnger system with 8 percent perioiide solution, or
8) by replacing the Method 6 water implnger system
with a Method 8 isopropanol-filter-peroxide system. The
analysis for SOi mutt be consistent with the procedure
in Method 8.
11.1 Probe. BorosQicate glass, or stainless steel (other
materials of construction may be used, subject to the
approval of the Administrator), approximately 6-mm
mode diameter, with a heating system to prevent water
condensation and a filter (either in-etack or heated out-
stack) to remove parUcnlate matter, Including sulfuric
•eld mist. A plug of glass wool Is a satisfactory filter.
2.1.2 Bubbler and Impingers. One midget bubbler,
wtth medium-coarse glass frit and borostlicate or quart*
flats wool packed In top (see Figure 6-1) to prevent
nMurlc add mist carryover, and three 30-ml midget
Impingers. The bubbler and midget impmgen must be
connected In series with leak-free glass connectors. 8111-
eone trease may be used. If necessary, to prevent leakage.
At the option of the tester, a midget Implnger may be
used in place of the midget bubbler.
Other collection absorbers and flow rates may be used,
but are subject to the approval of the Administrator.
Abo, collection efficiency must be shown to be at least
M percent for each test run and must be documented in
the report. If the efficiency is found to be acceptable after
a aeries of three tests, further documentation is not
required. To conduct the efficiency test, an extra ab-
sorber must be added and analyted separately. This
extra absorber must not contain more than 1 percent of
the total BCh.
2.1.3 Glass Wool. Boneilicate or quarto.
1.1.4 Stopcock Grease. Acetone-insoluble, heat-
stable silicons grease may be used. If necessary.
1.1.6 Temperature Gauge. Dial thermometer, or
equivalent, to measure temperature of fas leaving 1m-
pfnger train to within 1» C (fr.)
2.1.9 Drying Tube. Tube packed with 9-to 18-meah
Indicating type silica gel, or equivalent, to dry the fas
sample and to protect the meter and pump. If the atliac
eel has been used previously, dry at 175* C (350° F) lor
2 hours. New silica gel may be used as received. Alterna-
tively, other types of desiccants (equivalent or better)
may be used, subject to approval of the Administrator.
2.1.7 Value. Needle value, tojxfulate sample gas flow
rate.
2.1.8 Pump. Leak-free diaphragm pump, or equiv-
alent, to pull gas through the train. TnntftH a small tank
between the pump and rate meter to eliminate the
pulsation effect of the diaphragm pump on the rotameter.
2.1.9 Bate Meter. Rotameter, or equivalent, capable
of measuring flow rate to within 2 percent of the selected
flow rate of about 1000 eo/mln.
2.1.10 Volume Meter. Dry gas meter, sufficiently
accurate to measure the sample volume within 2 percent,
calibrated at the selected flow rate and conditions
actually encountered during sampling, and equipped
with a temperature gauge (dial thermometer, or equiv-
alent) oanable of measuring temperature to within
fc fart).
2.1.11 Barometer. Mercury, ameroid, or other barom-
eter capable of measuring atmospheric pressure to within
2.6 mm Hg (0.1 In. Bg). In many cases, the barometric
reading may be obtained from a nearby national weather
service station, In which case the station value (which
Is the absolute barometric pressure) shall be requested
and an adjustment (or elevation differences between
the weather station and sampling point shall be applied
eta rate of minus 2.3 mm Bg (0.1 In. Hg) per 80m (100 ft)
elevation Increase or vice versa for elevation decrease.
2.1.12 Vacuum Gauge. At least 760 mm Hg (80 In.
Hg) gauge, to be used for leak check of the sampling
train.
2.2 Sample Recovery.
2.2.1 Wash bottles. Polyethylene or glass, £00 ml,
two.
12.2 Storage Bottles. Polyethylene, 100 ml, to store
Implnger samples (one per sample).
2.3 Analysis.
2.8.1 Pipettes. Volumetric type, 6-ml, 30-ml (one per
sample), and 25-ml sites.
3.8.2 Volumetric Flasks. 100-ml site (one per sample)
and 100-ml site.
24.3 Burettes. S- and 80-ml sites.
2.8.4 Erlenmeyer Flasks. 290 mi-site (one for each
sample, blank, and standard).
2.3.6 Dropping Bottle. 125-ml site, to add Indicator.
U.« Graduated Cylinder. 100-ml slse.
2J.7 Spectrophotometer. To measure absorbance at
862 nanometers.
L Ratntt
Unless otherwise indicated, all reagents must conform
to the specifications established by the Committee on
Analytical Reagents of the American Chemical Society.
When such specifications are not available, use the best
available grade.
8.1 Sampling.
8.1.1 WaterTbelonlted. distilled to conform to A8TM
specification D1193-74, Type 3. At the option of the
analyst, the EMnOi test for oxldlcable organic matter
may be omitted when high concentrations of organic
matter are not expected to be present.
8.1.2 Isopropanol, 80 percent. Mix 80 ml of Isopropanol
with 20 ml of deionlted. distilled water. Check each lot of
Isopropanol for peroxide impurities as follows: shake 10
ml of Isopropanol with 10 ml of freshly prepared 10
percent potassium Iodide solution. Prepare a blank by
similarly treating 10 ml of distilled water. After 1 minute,
read the absorbance at 852 nanometers on a spectro-
photometer. If absorbance exceeds 0.1, reject alcohol for
use.
Peroxides may be removed from isopropanol by redis-
tilling or by passage through a column of activated
alumina; however, reagent grade isopropanol with
suitably low peroxide levels may be obtained from com-
mercial sources. Rejection of contaminated lots may,
therefore, be a more efficient procedure.
8.1.8 H>drogen Peroxide, 8 Percent. Dilute 80percent
hydrogen peroxide 1:9 (v/v) with delonited, distilled
water (30 ml is needed per sample). Prepare fresh dally.
8.1.4 Potassium Iodide Solution, 10 Percent. Dissolve
10.0 grams KI in delonlxed, distilled water and dilute to
100 ml. Prepare when needed.
8.2 Sample Recovery.
8.2.1 Water. Drloiuted, distilled, as In 8.1.1.
1.2.2 Isopropanol, 80 Percent. Mix 80ml of Isopropanol
with 20 ml of delonlxed, distilled water.
8.3 Analysis.
8.8.1 Water. Deionlted, distilled, as in 3.1.1.
8.8.2 Isopropanol, 100 percent.
8.8.3 Thorin Indicator. l-(o-areonophenylato)-2-
naphthol-3,6-dlsuUonlc acid, dlsodlum salt, or equiva-
lent. Dissolve 0.20 g in 100 ml of deionlted, distilled
water.
8.8.4 Barium Percblorate Solution, 0.0100 N. Dis-
solve 1.85 a of barium perchlorate trihydrate (Ba(ClOi)r
8HiO] in 200 ml distilled water and dilute to 1 liter with
aopropanol. Alternatively, 1.22 g of [BaCli-2HiO| may
be used instead of the perchlorate. Standardise as in
Section 6.6.
HDIKA1 MOISTO, VOL 42, NO. 1 «0—THURSDAY, AUOUST II, 1»77
V-1.99
-------
RULES AND REGULATIONS
3.3.5 Sulfurtc Acid Standard, 0.0100 N. Purchase or
standardize to *0.0002 N against 0.0100 N NaOH which
has previously been standardized against potassium
acid phthalate (primary standard grade).
4. Procedure.
4.1 Sampling.
4.1.1 Preparation of collection train. Measure 15 ml of
80 percent isopropanol into the midget bubbler and IS
ml of 3 percent hydrogen peroilde into each of the first
two midget implngers. Leave the final midget Impinger
dry. Assemble the train as shown In Figure 6-1. Adjust
probe heater to a temperature sufficient to prevent water
condensation. Place crushed ice and water around the
implngers.
4.1.2 Leak-check procedure. A leak check prior to the
sampling run is optional: however, a leak check after the
sampling run Is mandatory. The leak-check procedure Is
as follows:
With the probe disconnected, place a vacuum gauge at
the inlet to the bubbler and pull a vacuum of 250 mm
(10 in.) Hg: plug or pinch off the outlet of the flow meter,
and then turn off the pump. The vacuum shall remain
stable for at least 30 seconds. Carefully release the
vacuum gauge before releasing the now meter end to
prevent bark flow of the Impinger fluid.
Other leak check procedures may be used, subject to
the approval of the Administrator, U.S. Environmental
Protection Agency. The procedure used In Method 5 Is
not suitable for diaphragm pumps.
4.1.3 Sample collection. Record the Initial dry gas
meter reading and barometric pressure. To begin sam-
pling, position the tip of the probe at the sampling point,
connect the probe to the bubbler, and start the pump.
Adjust the sample flow to a constant rate of ap-
proximately 1.0 liter.'min as Indicated by the rotameter.
Maintain this constant rate (»10 percent) during the
entire sampling run. Take readings (dry gas meter,
temperatures at dry gas meter and at Impinger outlet
and rate meter) at least every 5 minutes. Add more ice
during the run to keep the temperature of the gases
leaving the last impinger at 20° C (68° F) or less. At the
conclusion of each run, turn off the pump, remove probe
from the stack, and record the final readings. Conduct a
leak check as In Section 4.1.2. (This leak check is manda-
tory.) If a leak is found, void the test run. Drain the Ice
bath, and purge the remaining part of the train by draw-
Ing clean ambient air through the system for 15 minutes
at the sampling rate.
Clean ambient air can be provided by passing air
through a charcoal filter or through an extra midget
Impinger with 15 ml of 3 percent HtOi. The tester may
opt to simply use ambient air, without purification.
4.2 Sample Recovery. Disconnect the Implngers after
purging. Discard the contents of the midget bubbler. Pour
the contents of the midget Impingers Into a leak-free
polyethylene bottle for shipment. Rinse the three midget
fmpingers and the connecting tubes with deioniied,
distilled water, and add the washings to the same storage
container. Mark the fluid level. Seal and identify the
sample container.
4.3 Sample Analysis. Note level of liquid In container,
and confirm whether any sample was lost during ship-
ment; note this on analytical data sheet. II a noticeable
amount of leakage has occurred, either void the sample
or use methods, subject to the approval of the Adminis-
trator, to correct the final results.
Transfer the contents of the storage container to a
100-ml volumetric flask and dilute to exactly 100 ml
with delonlzed, distilled water. Pipette a 20-ml aliquot of
this solution into a 250-ml Erlenmeyer flask, add 80 ml
of 100 percent Isopropanol and two to four drops of thorln
indicator, and titrate to a pink endpolnt using 0.0100 N
barium perchlorate. Repeat and average the tltration
volumes. Run a blank with each series of samples. Repli-
cate tltratlons must agree within 1 percent or 0.2 ml,
whichever is larger.
(NOTB.—Protect the 0.0100 N barium perchlorate
solution from evaporation at all times.)
5. Calibration
5.1 Metering System.
5.1.1 Initial Calibration. Before Us Initial use In the
field, first leak check the metering system (drying tube,
needle valve, pump, rotameter, and dry gas meter) as
follows: place a vacuum gauge at the inlet to the drying
tube and pull » vacuum of 250 mm (10 In.) Hg; plug or
pinch off the outlet or the flow meter, and then turn off
the pump. The vacuum shall remain stable for at least
30 seconds. Carefully release the vacuum gauge before
releasing the flow meter end.
Next, calibrate the metering system (at the sampling
flow rate specified by the method) as follows: connect
an appropriately sited wet test meter (e.g., 1 liter per
revolution) to the inlet of the drying tube. Make three
Independent calibration runs, using at least five revolu-
tions of the dry gas meter per run. Calculate the calibra-
tion factor, Y (wet test meter calibration volume divided
by the dry gas meter volume, both volumes adjusted to
the same reference temperature and pressure), for each
run, and average the results. If any r value deviates by
more than 2 percent from the average, the metering
system is unacceptable for use. Otherwise, use the aver-
age as the calibration factor for subsequent test runs.
5.1.2 Post-Test Calibration Check. After each field
test series, conduct a calibration check as In Section 5.1.1
above, except for the following variations: (a) the leak
check Is not to be conducted, (b) three, or more revolu-
tions of the dry gas meter may be used, and (c) only two
Independent runs need be made. If the calibration factor
does not deviate by more than 5 percent from the Initial
calibration factor (determined In Section 5.1.1), then the
dry gas meter volumes obtained during the test series
are acceptable. If the calibration factor deviates by more
than 5 percent, recalibrate the metering system as In
Section 5.1.1, and for the calculations, use the calibration
factor (initial or recalibration) that yields the lower gas
volume for each test run.
5.2 Thermometers. Calibrate against mercury-ln-
glass thermometers.
5.3 Rotameter. The rotameter need not be calibrated
but should be cleaned and maintained according to the
manufacturer's Instruction.
5.4 Barometer. Calibrate against a mercury barom-
eter.
5.5 Barium Perchlorate Solution. Standardly the
barium perchlorate solution against 25 ml of standard
sulfuric acid to which 100 ml of 100 percent isopropanol
has been added.
6. Calculation*
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculation.
6.1 Nomenclature.
C«,-Concentration of sulfur dioxide, dry basts
1 corrected to standard conditions, mg/dscm
. (Ib/dscf).
jV=Normality of barium perchlorate tltrant,
mllllequlvalents/ml.
Pb., = Barometric pressure at the exit orifice of the
dry gas meter, mm Hg (In. Hg).
Pud-Standard absolute pressure, 760 mm Hg
(29.92In. Hg).
Tm- Average dry gas meter absolute temperature,
°K (°R).
T.id-Standard absolute temperature, 293° K
(528° R).
V.-Volume of sample aliquot titrated, ml.
V.-Dry gas volume as measured by the dry gas
meter, dcm (dcf).
V»(.td)-Dry gas volume measured by the dry gas
meter, corrected to standard conditions,
dscm (dscf).
Vuin-Total volume of solution In which the sulfur
dioxide sample Is contained, 100 ml.
Vi=Volume of barium perchlorate tltrant used
for the sample, ml (average of replicate
tltratlons).
Vit-Volume of barium perchlorate tltrant used
for the blank, ml.
V=Dry gas meter calibration factor.
32.03=Equivalent weight of sulfur dioxide.
6.2 Dry sample gas volume, corrected to standard
conditions. ._.._. -. _
'm *b«r
where:
K>0.38S8 -KVmm Hg for metric unlU.
-17.64 "R/ln. Hg for English units,
6.3 Sulfur dioxide concentration.
-At
Equation 6-2
where:
Jfi-32.03 mg/meq. for metric units.
-7.0fllX10-»lb/meq. for English unit*.
7. Bibliosraphf
1. Atmospheric Emissions from Sulfurlc Add Mann-
facturing Processes. U.S. DHEW, PHS. Division of Air
Pollution. Public Health Service Publication No.
999-AP-13. Cincinnati, Ohio. 1985.
2. Corbett, P. F. The Determination of SOj and SO,
In Flue Oases. Journal of the Institute of Fuel. 14:2S7-
3! Matty, R. E. and E. K. Dlehl. Measuring Flue-Oa>
SOi and SOi. Power. 101:94-97. November 1957.
4. Pat ton, W. F. and J. A. Brink, Jr. New Equipment
and Techniques for Sampling Chemical Process Oases.
J. Air Pollution Control Association. IS: 162. 1963.
5. Rom, J. J. Maintenance, Calibration, and Operation
of Isokinetic Source-Sampling Equipment. Office of
Air Programs, Environmental Protection Agency.
Research Triangle Park, N.C. APTD-0576. March 1971.
6. Hamll, H. F. and D. E. Camann. Collaborative
Study of Method for the Determination of Sulfur Dioxide
Emissions from Stationary Sources (Fossil-Fuel Fired
Steam Generators). Environmental Protection Agency,
Research Triangle Park, N.C. EPA-«SO/4-74-02».
December 1973.
7. Annual Book of ASTM Standards. Part 31; Water,
Atmospheric Analysis. American Society for Testing
and Materials. Philadelphia, Pa. 1974. pp. 40-42.
8. Knoll, J. E. and M. R. Midgett. The Application of
EPA Method 6 to High Sulfur Dioxide Concentration!,
Environmental Protection Agency. Research Triangle
Park, N.C. EPA-600/4-76-038. July 1976.
METHOD 7—DETERMINATION or NITBOOIN OztDB
EMISSIONS FEOM STATIOKABT SOUBCU
' 1. Principle and AppHctttattt
1.1 Principle. A grab sample Is collected In an evacu-
ated flask containing a dilute sulfuric acid-hydrogen
peroxide absorbing solution, and the nitrogen oxides,
except nitrous oxide, are measured colorimetericaUy
using the phenoldlsulfonlc acid (PD8) procedure.
1.2 Applicability. This method Is applicable to the
measurement of nitrogen oxides emitted from stationary
sources. The range of the method has been determined
to be 2 to 400 milligrams NO, (as NOi) per dry standard
cubic meter, without having to dilute toe sample.
2. Apparatut
2.1 Sampling (see Figure 7-1). Other grab sampling
systems or equipment, capable of measuring sample
volume to within ±2.0 percent and collecting a sufficient
sample volume to allow analytical repnxfuclbllity to
within ±5 percent, will be considered acceptable alter-
natives, subject to approval of the Administrator, U.S.
Environmental Protection Agency. The following
equipment Is used in sampling:
2.1.1 Probe. BorosUlcate glass tubing, sufficiently
heated to prevent water condensation and equipped
with an In-stack or out-stack filter to remove paniculate
matter (a plug of glass wool is satisfactory for this
purpose). Stainless steel or Teflon * tubing may also be
used for the probe. Heating Is not necessary if the probe
remains dry during the purging period.
Equation 6-1
> Mention of trade names or specific products does not
constitute endorsement by the Environmental Pro-
tection Agency.
FEDERAL REGISTER, VOL. 42, NO. 160—THURSDAY, AUGUST II, 1977
V-200
-------
RULES AND REGULATIONS
EVACUATE
PROBE
FLASK VALVE'
y3
FILTER
GROUND-GLASS
§ NQ. 12/5
110mm
3-WAY STOPCOCK;
T-6ORE. i PYREX.
2-rnn BORE. 8-mm OD
FLASK
FLASK SHIELD-. .\
SQUEEZE BULB
IMP VALVE
PUMP
THERMOMETER
GROUND-GLASS CONE.
STANDARD TAPER.
§ SLEEVE NO. 24/40
210 mm
GROUND-GLASS
SOCKET. § NO. 12/S
PYREX
FOAM ENCASEMENT
BOILING FLASK •
2-LITER. ROUND-BOTTOM. SHORT NECK.
WITH J SLEEVE NO. 24/40
Figure 7-1. Sampling train, flask valve, and flask.
2.1.2 Collection Flask. Two-liter borosilicate, round
bottom flask, with short neck and 24/40 standard taper
opening, protected against Implosion or breakage.
2.1.3 Flask Valve. T-bore stopcock connected to a
24/40 standard taper Joint.
2.1.4 Temperature Gauge. Dial-type thermometer, or
other temperature gauge, capable of measuring 1° C
(2° F) Intervals from -5 to 60* C (25 to 126" F).
2.1.5 Vacuum Line. Tubing capable of withstanding
• vacuum of 75 mm Hg (3 in. Hg) absolute pressure, with
"T" connection and T-bore stopcock.
2.1.6 Vacuum Gauge. U-tube manometer, 1 meter
(86 in.), with 1-mm (0.1-in.) divisions, or other gauge
capable of measuring pressure to within ±2.5 mm Hg
(0.10 in. Hg).
2.1.7 Pump. Capable of evacuating the collection
flask to a pressure equal to or less than 75 mm Hg (3 in.
Hg) absolute.
2.1.8 Squeeze Bulb. One-way.
2.1.9 Volumetric Pipette. 25 ml.
2.1.10 Stopcock and Ground Joint Grease. A high-
vacuum, high-temperature chlorofluorocarbon grease Is
required. Halocarbon 25-58 has been found to be effective.
2.1.11 Barometer. Mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to within
2.5 mm Hg (0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby national weather
service station, in which case the station value (which Is
the absolute barometric pressure) shall be requested and
an adjustment for elevation differences between the
weather station and sampling point shall be applied at a
rate of minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100 ft)
elevation Increase, or vice versa for elevation decrease.
2.2 Sample Recovery. The following equipment Is
required for sample recovery:
$2.1 Graduated Cylinder. 50 ml with 1-ml divisions.
2^2 Storage Containers. Leak-free polyethylene
bottles.
2.2.3 Wash Bottle. Polyethylene or glass.
2.2.4 Glass Stirring Rod.
2.2.5 Test Paper for Indicating pH. To cover tbe pH
«ngeof7tol4. 7
2.3 Analysis. For the analysis, the following equip-
ment Is needed:
2A1 Volumetric Pipettes. Two 1 ml, two 2 ml, one
I ml, one 4 ml, two 10 ml, and one 25 ml for each sample
and standard.
2.3.2 Porcelain Evaporating Dishes. 175- to 250-ml
capacity with lip for pouring, one for each sample and
each standard. The Coors No. 45006 (shallow-form, 195
ml) has been found to be satisfactory. Alternatively,
polymethyl pentene beakers (Nalge No. 1203,150 ml), or
glass beakers (150 ml) may be used. When glass beakers
are used, etching of tbe beakers may cause solid matter
to be present in the analytical step; the solids should be
removed by filtration (see Section 4.3).
2.3.3 Steam Bath. Low-temperature ovens or thermo-
statically controlled hot plates kept below 70° C (160° F)
are acceptable alternatives.
2.3.4 Dropping Pipette or Dropper. Three required.
2.3.5 Polyethylene Policeman. One for each sample
and each standard.
2.3.6 Graduated Cylinder. 100ml with 1-ml divisions.
2.3.7 Volumetric Flasks. 50 ml (one for each sample),
100 ml (one for each sample and each standard, and one
for the working standard KNOi solution), and 1000 ml
(one).
2.3.8 Spectropbotometer. To measure absorbance at
410 nm.
2.3.9 Graduated Pipette. 10 ml with 0.1-ml divisions.
2.3.10 Test Paper for Indicating pH. To cover the
pB range of 7 to 14.
2.3.11 Analytical Balance. To measure to within 0.1
mg.'
Unless otherwise indicated, It Is Intended that all
reagents conform to the specifications established by the
Committee on Analytical Reagents of the American
Chemical Society, where such specifications are avail-
able; otherwise, use the best available grade.
3.1 Sampling. To prepare the absorbing solution,
cautiously add 2.8 ml concentrated HiSOi to 1 liter of
deionized, distilled water. Mix well and add 6 ml of 3
percent hydrogen peroxide, freshly prepared from 80
percent hydrogen peroxide solution. The absorbing
solution should be used within 1 week of Its preparation.
Do not expose to extreme heat or direct sunlight.
S.2 Sample Recovery. Two reagents are required for
sample recovery:
8.2.1 Sodium Hydroxide (IN). Dissolve 40 g NaOH
In deionized, distilled water and dilute to 1 liter.
8.2.2 Water. .Deionized, distilled to conform to A8TM
specification D1193-74, Type 3. At tbe option of the
analyst, the KMNO< test for oxldizable organic matter
may be omitted when high concentrations of organic
matter are not expected to be present.
3.3 Analysis. For tbe analysis, the following reagents
are required:
3.3.1 Fuming Sulfuric Acid. 15 to 18 percent by weight
free sulfur trioxide. HANDLE WITH CAUTION.
3.3.2 Phenol. White solid.
3.3.3 Sulfuric Acid. Concentrated, 95 percent mini-
mum assay. HANDLE WITH CAUTION.
3.3.4 Potassium Nitrate. Dried at 105 to 110° C (520
to 230° F) for a minimum of 2 hours Just prior to prepara-
tion of standard solution.
3.3.5 Standard KNOi Solution. Dissolve exactly
2.198 g of dried potassium nitrate (KNOi) in deionized,
distilled water and dilute to 1 liter with deionized,
distilled water in a 1,000-ml volumetric flask.
3.3.6 Working Standard KNOi Solution. Dilute 10
ml of the standard solution to 100 ml with deionized
distilled water. One mllliliter of the working standard
solution is equivalent to 100 Mg nitrogen dioxide (NOi).
8.3.7 Water. Deionized, distilled as in Section 3.2.2.
8.3.8 • Phenoldisulfonic Acid Solution. Dissolve 25 g
of pure white phenol in 150 ml concentrated sulfunc
acid on a steam bath. Cool, add 75 ml fuming sulfuric
add, and heat at 100° C (212° F) for 2 hours. Store in
a dark, stoppered Dottle.
4. Procedure*
4.1 Sampling.
4.1.1 Pipette 25 ml of absorbing solution into a sample
flask, retaining a sufficient quantity for use in preparing
the calibration standards. Insert the flask valve stopper
into the flask with the valve in the "purge" position.
Assemble the sampling train as shown in Figure 7-1
and place the probe at the sampling point. Make sure
that all fittings are tight and leak-free, and that all
ground glass Joints have been properly greased with a
high-vacuum, high-temperature chlorofluorocarhon-
based stopcock grease. Turn the flask valve and the
pump valve to their "evacuate" positions. Evacuate
the flask to 75 mm Hg (3 in. Hg) absolute pressure, or
less. Evacuation to a pressure approaching the vapor
pressure of water at the existing temperature is desirable.
Turn the pump valve to its "vent" position and turn
off the pump. Check for leakage by observing the ma-
nometer for any pressure fluctuation. (Any variation
FEDERAL KECISTER, VOL 42, NO. 160—THUHSDAY, AUGUST 18, 1977
V-201
-------
water, to the stopcock. Measure the volume of water to
±10 ml. Record this volume on the flask.
5.2 Spectrophotometer Calibration.
8.2.1 Optimum Wavelength Determination. For both
flied and variable wavelength spectrophotometere.
calibrate against standard certified wavelength of 410
nm, every 6 months. Alternatively, for variable wave
length spectrophotometers, scan the spectrum between
400 and 415 nm using a 20fl«S NOi standard solution (see
Section 5.2.2). If a peak does not occur, the spectropho-
tometer is probably malfunctioning, and should be re-
paired. When a peak is obtained within the 400 to 415 nm
range, the wavelength at which this peak occurs shall be
the optimum wavelength for the measurement of ab-
sorbance for both the standards and samples.
5.2.2 Determination of Spectrophotometer Calibra-
tion Factor K,. Add 0.0, 1.0, 2.0, 3.0. and 4.0 ml of the
KNOi working standard solution (1 ml=100Mg NOi) to
a series of flve porcelain evaporating dishes. To each, add
25 ml of absorbing solution, 10 ml deionized, distilled
water, and sodium hydroxide (IN), dropwise, until the
pH is between 9 and 12 (about 25 to 35 drops each).
Beginning with the evaporation step, follow the analy-
sis procedure of Section 4.3, until the solution has been
transferred to the 100 ml volumetric flask and diluted to
the mark. Measure the absorbance of each solution, at the
optimum wavelength, as determined in Section 5.2.1.
This calibration procedure must be repeated on each day
that samples arc analyzed. Calculate the Spectrophotom-
eter calibration factor as follows:
Ke= 100 ^
greater than 10 mm Hg (0.4 in. Hg) over a period of
1 minute is not acceptable, and the flask Is not to be
' used until the leakage problem Is corrected. Pressure
in the flask is not to exceed 75 mm Hg (3 in. Hg) absolute
at the time sampling is commenced.) Record the volume
of the flask and valve (V/1, the flask temperature (Ti).
and the barometric pressure. Turn the flask valve
counterclockwise to its "purge" position and do the
same with the pump valve. Purge the probe and the
vacuum tube using the squeeie bulb. If condensation
occurs in the probe and the flask valve area, heat the
probe and purge until the condensation disappears.
Next, turn the pump valve to its "vent" position. Turn
the flask valve clockwise to its "evacuate" position and
record the difference in the mercury levels In the manom-
eter. The absolute internal pressure in the flask (P,-)
is equal to the barometric pressure less the manometer
reading. Immediately turn the flask valve to the "sam-
ple" position and permit the gas to enter the flask until
pressures in the flask and sample line (i.e., duct, stack)
are equal. This will usually require about 15 seconds;
a longer period indicates a "plug" in the probe, which
must be corrected before sampling is continued. After
collecting the sample, turn the flafk valve to its "purge"
position and disconnect the flask from the sampling
train. Shake the flask for at least 5 minutes.
' 4.1.2 If the gas being sampled contains insufficient
oiygen for the conversion of NO to NO: (e.g., an ap-
plicable subpart of the standard may require taking a
sample of a calibration gas mixture of NO in Ni), then
oxygen shall be introduced into the flask to permit this
conversion. Oxygen may be Introduced into the flask
by one of three methods; (1) Before evacuating the
sampling flask, flush with pure cylinder oxygen, then
evacuate flask to 75 mm Hg (3 in. Hg) absolute pressure
or less; or (2) inject oxygen into the flask after sampling;
or (3) terminate sampling with a minimum of 50 mm
Hg (2 in. Hg) vacuum remaining in the flask, record
this final pressure, and then vent the flask to the at-
mosphere until the flask pressure is almost equal to
atmospheric pressure.
4.2 Sample Recovery. Let the flask set for a minimum
of 16 hours and then shake the contents for 2 minutes.
Connect the flask to a mercury filled U-tube manometer.
Open the valve from the flask to the manometer and
record the flask temperature (TV), the barometric
pressure, and the difference between the mercury levels
n the manometer. The absolute internal pressure in
the flask (P/) is the barometric pressure less the man-
ometer reading. Transfer the contents of the flask to a
leak-free polyethylene bottle. Rinse the flask twice
with 5-ml portions of deionized, distilled water and add
the rinse water to the bottle. Adjust the pH to between
9 and 12 by adding sodium hydroxide (1 N), dropwise
(about 25 to 35 drops). Check the pH by dipping a
stirring rod into the solution and then touching the rod
to the pH test paper. Remove as little material as possible
during this step. Mark the height of the liquid level so
that the container can be checked for leakage after
transport. Label the container to clearly identify its
contents. Seal the container for shipping.
4.3 Analysis. Note the level of the liquid in container
and confirm whether or not any sample was lost during
shipment; note this on the analytical data sheet. If a
noticeable amount of leakage has occurred, either void
the sample or use methods, subject to the approval of
the Administrator, to correct the final results. Immedi-
ately prior to analysis, transfer the contents of the
shipping container to a 50-ml volumetric flask, and
rinse the container twice with 5-ml portions of deionized.
distilled water. Add the rinse water to the flask and
dilute to the mark with deionized, distilled water; mix
thoroughly. Pipette a 25-ml aliquot into the procelaln
evaporating dish. Return any unused portion of the
sample to the polyethylene storage bottle. Evaporate
the 25-ml aliquot to dryness on a steam bath and allow
to cool. Add 2 ml phenoldlsulfonic acid solution to the
dried residue and triturate thoroughly with a poylethyl-
ene policeman. Make sure the solution contacts all the
residue. Add 1 ml deionized, distilled water and four
drops-of concentrated sulfuric acid. Ueat the solution
on a steam bath for 3 minutes with occasional stirring.
Allow the solution to cool, add 20 ml deionized, distilled
water, mix well by stirring, and add concentrated am-
monium hydroxide, dropwise, with constant stirring,
until the pH is 10 (as determined by pH paper). If the
sample contains solids, these must be removed by
filtration (centrifugation Is an acceptable alternative,
subject to the approval of the Administrator), as follows:
alter through Whatman No. 41 filter paper into a 100-ml
volumetric flask; rinse the evaporating dish with three
5-ml portions of deionized, distilled water; filter these
three rinses. Wash the filter with at least three 15-ml
portions of deionized, distilled water. Add the filter
washings to the contents of the volumetric flask and
dilute to the mark with deionized, distilled water. If
solids are absent, the solution can be transferred directly
to the 100-ml volumetric flask and diluted to the mark
with deionized, distilled water. Mix the contents of the
flask thoroughly, and measure the absorbance at the
optimum wavelength used for the standards (Section
5.2.1), using the blank solution as a zero reference. Dilute
the sample and the blank with equal volumes of deion-
ized, distilled water if the absorbance exceeds A,, the
absorbance of the 400 jig NOi standard (see Section 5.2.2).
5. Calibration
6.1 Flask Volume. The volume of the collection flask- NOTE.—If other than a 25-ml aliquot is used for analy-
flask valve combination must be known prior to sam- sis, the factor 2 must be replaced by a corresponding
pling. Assemble the flask and flask valve and fill with factor.
Equation 7-1
where:
Jfc=Calibration factor
<4i = Absorbance of the 100-tig NOt standard
X:=Absorbance of the 200-jig NO: standard
Ai=Absorbance of the 300-pg NO] standard
,4(=Absorbance of the 400-cg NOi standard
5.3 Barometer. Calibrate against a mercury barom-
eter.
5.4 Temperature Gauge. Calibrate dial thermometers
against mercury-in-glass thermometers.
5.5 Vacuum Gauge. Calibrate mechanical gauges, If
used, against a mercury manometer such as that speci-
fied in 2.1.6.
5.6 Analytical Balance. Calibrate against standard
weights.
6. Calculations
Carry out the calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculations.
6.1 Nomenclature.
A = Absorbance of sample.
C=Concentration of. NO, as NO), dry basis, cor-
rected to standard conditions, mg/dscm
(Ib/dscO.
F= Dilution factor (i e., 25/5, 35/10, etc., required
only if sample dilution was needed to reduce
the absorbance into the range of calibration).
K,=Spectrophotometer calibration factor.
m = Hass of NO, as NO» in gas sample. MR.
/*/=Final absolute pressure of flask, mm Hg (in. Hg).
Pi = Initial absolute pressure of flask, mm Hg (in.
HK).
P,,d=Standard absolute pressure, 760mm Ug (29.92 in.
H«).
Ti=Final absolute temperature of flask ,°K (°R).
7\ = Initial absolute temperature of flask. °K (°R).
T,td = Standard absolute temperature, 2U3° K (528° R)
V',, = Sample volume at standard conditions (dry
basis), ml.
V/=Volume of flask and valve, ml.
V0=Volume of absorbing solution, 25 ml.
2=60/25, the aliquot factor. (If other than a 25-ml
aliquot was used for analysi5, the correspond-
ing factor must he substituted).
6.2 Sample volume, dry basis, corrected to standard
conditions.
where:
, = 0.3858
°K
= 17.64 T
mm Hg
°R
Equation 7-2
for metric units
in. Hg
0.3 Total 11% NOi per sample.
m=2K,AF
for English units
Equation 7-3
6.4 Sample concentration, dry basis, corrected to
standard conditions.
Equation 7-4
where:
K}= 10* —-7—f for metric units
for English units
6.243X10-'
-
Mg/ml
7. BibHography
I. Standard Methods of Chemical Analysis. 6th ed.
New York, D. Vna Nostrand Co., Inc. 1882. Vol. 1,
p. 329-330.
2. Standard Method of Test for Oxides of Nitrogen In
Gaseous Combustion Products (Phenoldlsulfonic Add
Procedure). In: 1968 Book of ASTM Standards, Part 28.
Philadelphia, Pa. 1968. ASTM Designation D-1603-69,
p. 725-729.
3. Jacob, M. B. The Chemical Analysis of Air Pollut-
ants. New York. Interscience Publishers, Inc. 1980.
Vol. 10, p. 351-356.
4. Beatty, R. L., L. B. Berger, and H. H. Schrent.
Determination of Oxides of Nitrogen by the Phenoldlsul-
fonic Acid Method. Bureau of Mines, U.S. Dept. of
Interior. R. I. 3687. February 1943.
5. Hamil, H. F. and D. E. Camann. Collaborates
Study of Method for the Determination of Nitrogen
Oxide Emissions from Stationary Sources (Fossil Fuel-
Fired Steam Generators). Southwest Research Institute
report for Environmental Protection Agency. Research
Triangle Park, N.C. October 5, 1973.
6. Hamil, H. F. and R. E. Thomas. Collaborative
Study of Method for the Drtermlnation of Nitrogen
Oxide Emissions from Stationary Sources (Nitric Acid
Plants). Southwest Research Institute report for En-
vironmental Protection Agency. Research Triangle
Park, N.C. May 8, 1974.
METHOD 8— DETERMINATION OF SDLFUBIC Aero MIST
AND SUITOR DIOXIDE EMISSIONS FROM STATIONARY
SOURCES '
1. Principle and Applicability
1.1 Principle. A gas sample is extracted isokinetically
from the stack. The sulfuric acid mist (including sulfur
trioxide) and the sulfur dioxide are separated, and both
fractions are measured separately by the barium-thorin
titration method.
1.2 Applicability. This method is applicable for the
determination of sulfuric acid mist (including sulfur
trioiide, and in the absence of other paniculate matter)
and sulfur dioxide emissions from stationary sources.
Collaborative tests have shown that the minimum
detectable limits of the method are 0.05 milligrams/cubic
meter (0.03X10~T pounds/cubic foot) for sulfur trioxide
and 1.2 mg/m> (0.74 10-' lb/tt') for sulfur dioxide. No
upper limits have been established. Based on theoretical
calculations for 200 milliUters of 3 percent hydrogen
peroxide solution, the upper concentration limit for
sulfur dioxide in a 1.0 m> (35.3 fti) gas sample is about
12,500 mg/m> (7.7X10-< lb/ft>). The upper limit can be
extended by increasing the quantity of peroxide solution
in the impingers.
Possible interfering agents of this method are fluorides,
free ammonia, and dimethyl aniline. If any of these
interfering agents are present (this can be determined by
knowledge of the process), alternative methods, subject
to the apprdval of the Administrator, are required.
Filterable paniculate matter may be determined along
with SO i and SOi (subject to the approval of the Ad-
ministrator); however, the procedure used for paniculate
matter must be consistent with the specifications and
procedures given In Method 5.
2. Apparatus
2.1 Sampling. A schematic of the sampling train
used In this method Is shown In Figure 8-1; ft Is similar
to the Method 5 train except that the filter position is
different and the niter holder does not have to De heated.
Commercial models of this train are available. For those
who desire to build their own. however, complete con-
struction details are described In APTD-0581. Changes
from the APTD-0581 document and allowable modi-
fications to Figure 8-1 are discussed In the following
subsections.
The operating and maintenance procedures for the
sampling train are described In APT D-0576. Since correct
usage is important in obtaining valid results, all users
should read the APTD-0576 document and adopt the
operating and maintenance procedures outlined in It,
unless otherwise specified herein. Further details and
guidelines on operation and maintenance arc given In
Method 5 and should bo read and followed whenever
they are applicable.
2.1.1 Probe Nozzle. Same as Method 5, Section 2.1.1.
2.1.2 Probe Liner. Borosilicate or quart! glass, with o
heating system to prevent visible condensation during
sampling. Do not use metal probe liners.
2.1.3 Pitot Tube. Same as Method 5, Section 2.1.3.
FIDIfiAl REfJISTEU, VOL. 42, NO. 160—THUBSDAV, AUGUST 10, 1977
V-202
-------
RULES AND REGULATIONS
TEMPERATURE SENSOR
PROBE
FILTER HOLDER
PROBE
7
REVERSE TYPE
PITOT TUBE
PITOTTUBE
TEMPERATURE SENSOR
THERMOMETER
L
CHECK
VALVE
VACUUM
LINE
VACUUM
GAUGE
MAIN VALVE
DRY TEST METER
Figure 8-1. Sulfuric acid mist sampling train.
2.1.4 Differential Pressure Gauge. Same SB Method 5.
Section 2.1.4.
2.1.4 Filter Holder. Boralllcat* glass, with a glass
Mt filter rapport and a dlicone rubber gasket. Other
casket materials, e.g., Teflon or Vlton, may be used sub-
ject to the approval of the Administrator. The bolder
design shall provide a positive seal against leakage from
the outside or around the filter. The filter holder shall
be placed between the first and second Impingen. Note'
Do not heat the filter holder.
2.1.6 Impingers— Four, as shown In Figure 8-1. The
first and third shall be of the Oreenburg-Smith design
with standard tips. The second and fourth shall be of
the Oreenburg-Smlth design, modified by replacing the
Insert with an approximately 13 millimeter (0.5 InO ID
class tube, having an nnconstrlcted tip located 13 mm
(0.5 in.) from the bottom of the flask. Similar collection
systems, which have been approved by the Adminis-
trator, may be used.
*8'7 Metering System. Same as Method 5, Section
Z.1.8 Barometer. Same as Method 5, Section 2.1.8.
iqulpment- •—
2.2.4 Trip Balance. 500-gram capacity, to measure to
±0.5 g (necessary only if a moisture content analysis la
to be done).
2.3 Analysis.
2.8.1 Pipettes. Volumetric 25 ml, 100 ml.
2.3.2 Burrette. CO ml.
2.8.3 Erlenmeyer Flask. 290 ml. (one for each sample
blank and standard).
2.3.4 Graduated Cylinder. 100ml.
2.3.5 Trip Balance. 500 g capacity, to measure to
±0.5 g.
2.3.8 Dropping Bottle. To add Indicator solution,
125*ml sice.
1.1.10 Temperature Gauge. Thermometer, or equiva-
lent, to measure the temperature of the eas leavini the
Impinger train to within 1°C (2° F) •—"»'"«•"
2.2 Sample Recovery.
(two)1 W*"' Bottto§1 PolTrtnTl«ne <» «laaj, 500 ml.
\Tjnless otherwise Indicated, all reagents are to conform
to the specifications established by the Committee on
Analytical Reagents of the American Chemical Society,
where such specifications are available. Otherwise, use
the best available grade.
3.1 Sampling.
3.1.1 Filters. Same as Method 5, Section 3.1.1.
3.1.2 Silica Gel. Same as Method 5, Section 3.1.2.
8.1.3 Water. Deionlied, distilled to conform to ASTM
specification D1193-74, Type 3. At the option of the
analyst, the KMnOi test for oxldlzable organic matter
may be omitted when high concentrations of organic
matter are not eipected to be present.
1.1.4 laopropaool. 80 Percent. Mix 800 ml of Isopro-
panol with 200 ml of delonlted, distilled water.
NOTX.— Experience has shown that only A.C.8. grade
liopropanol is satisfactory. Tests have shown that
Ifopropanol obtained from commercial sources occa-
caslonally hat peroxide Impurities that will cause er-
roneonsly high sulfuric acid mist measurement. Use
the following test for detecting peroxides in each lot of
Isopropanol: Shake 10 ml of the Isopropanol with 10 ml
of freshly prepared 10 percent potassium Iodide solution.
Prepare a blank by similarly treating 10 ml of distilled
water. After 1 minute, read the absorbance on a spectro-
photometer at 352 nanometers. If tho absorbance exceeds
0.1, the isopropanol shall not be used. Peroxides may be
removed from Isopropanol by redistilling, or by passage
though a column of activated alumina. However, re-
agent-trade Isopropanol with suitably low peroxide levels
Is readily available from commercial sources; therefore,
rejection of contaminated lots may be more efficient
than following the peroxide removal procedure.
3.1.5 Hydrogen Peroxide, 3 Percent. Dilute 100 ml
of 30 percent hydrogen peroxide to 1 liter with delonlied,
distilled water. Prepare fresh dally.
3.1.6 Crushed Ice.
3.2 Sample Recovery.
8.2.1 Water. Same as 3.1.3.
3.2.2 Isopropanol, 80 Percent. Same as 3.1.4.
3.3 Analysis.
8.3.1 Water. Same as 3.1.3.
3.3.2 Isopropanol, 100 Percent.
8.8.8 Thorln Indicator. l-(o-arsonophenylaio)-2-naph-
thol-3, 8-disulfonic acid, dlsodium salt, or equivalent.
Dissolve 0.20 g In 100 ml of delonlied, distilled water.
8.3.4 Barium Perchlorate (0.0100 Normal). Dissolve
1.95 g of barium perchlorate trthydrale (Ba(C10i)>-3HiO)
In 200 ml delonlied, distilled water, and dilute to 1 liter
with Isopropanol; 1.22 g of barium chloride dihydrato
(BaCli-2HiO) may be used Instead of the barium per-
chlorate. Btandardite with sulfuric acid as In Section 5.2.
This solution must be protected against evaporation at
all times.
HDERAL UOISTH, VOL 42, NO. 160—THUUDAY, AUGUST II, 1977
V-203
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RULES AND REGULATIONS
3.3.5 Sulfuric Acid Standard (0.0100 N). Purchase or
standardise to ±0.0002 N against 0.0100 N NaOH that
has previously been standardized against primary
standard potassium acid phthalate.
4. Procedure
4.1 Sampling.
411 Pretest Preparation. Follow the procedure out-
lined in Method 5, Section 4.1.1; niters should be in-
spected, but need not be desiccated, weighed, or identl-
lied. If the effluent gas can be considered dry, i.e., mois-
ture tree, the silica gel need not be weighed.
4.1.2 Preliminary Determinations. Follow the pro-
cedure outlined in Method 5, Section 4.1.2.
413 Preparation of Collection Train. Follow the pro-
cedure outlined in Method 5, Section 4.1.3 (except for
the second paragraph and other obviously inapplicable
parts) and use Figure 8-1 instead of Figure 5-1. Replace
the second paragraph with: Place 100 ml of 80 percent
Isopropanol in the first Impinger, 100 ml of 3 percent
hydrogen peroiide in both the second and third im-
pingers; retain a portion of each reagent for use as •
blank solution. Place about 200 g of silica gel In the fourth
implnger.
NOTE.—If moisture content Is to be determined by
Implnger analysis, weigh each of the first three Impingen
(plus absorbing solution) to the nearest 0.5 g and record
these weights. The weight of the silica gel (or silica gel
plus container) must also be determined to the nearest
0.5 g and recorded.
4.1.4 Pretest Leak-Check Procedure. Follow the
basic procedure outlined In Method 5, Section 4.1.4.1,
noting that the probe heater shall be adjusted to the
minimum temperature required to prevent condensa-
tion, and also that verbage such as, • • • plugging the
inlet to the filter holder • * •," shall be replaced by,'
plugging the inlet to the first impinger • • V
The pretest leak-check Is optional.
4.1.5 Train Operation. Follow the basic procedures
outlined In Method 5, Section 4.1.5, in conjunction with
the following special instructions. Data shall be recorded
on a sheet similar to the one in Finn 8-2. The sampling
rate shall not exceed 0.030 m'/nun (1.0 cfm) during the
run. Periodically during the test, observe the connecting
line between the probe and first Impinger for signs of
condensation. If It does occur, adjust the probe beater
setting upward to the minimum temperature required
to prevent condensation. If component changes become
necessary during a run, a leak-check shall be done Im-
mediately before each change, according to the procedure
outlined in Section 4.1.4.2 of Method 5 (with appropriate
modifications, as mentioned in Section 4,1.4 of this
method); record all leak rate*. If the leakage rated)
exceed the specified rate, the tester shall either void the
run or shall plan to correct the sample volume a* out-
lined in Section 6.3 of Method 5. Immediately after com-
ponent changes, leak-checks are optional. It then
leak-checks are done, the procedure outlined In Section
4.1.4.1 qf Method £ (with appropriate modifications)
shall be used.
PLANT.
LOCATION.
OPERATOR.
DATE
RUN NO. _
SAMPLE BOX NO..
METER BOX NO. _
METER A Hg
C FACTOR
PITOT TUBE COEFFICIENT, Cp.
STATIC PRESSURE, mm H| (m. Hi).
AMBIENT TEMPERATURE
BAROMETRIC PRESSURE
ASSUMED MOISTURE, X
PROBE LENGTH, m (ft)
SCHEMATIC OF STACK CROSS SECTION
NOZZLE IDENTIFICATION NO
AVERAGE CALIBRATED NOZZLE DIAMETER, em(inj.
PROBE HEATER SETTING
LEAK RATE,m3/min((cfm) '
PROBE LINER MATERIAL
FILTER NO.
TRAVERSE POINT
NUMBER
TOTAL
SAMPLING
TIME
(8}. min.
AVERAGE
VACUUM
mm H|
(in. H|)
STACK
TEMPERATURE
ITS).
°C (*F)
VELOCITY
HEAD
(AP$),
mmHjO
(in. H20)
PRESSURE
DIFFERENTIAL
ACROSS
ORIFICE
METER.
mmH20
(in.H20)
GAS SAMPLE
VOLUME.
m3 (ft3)
GAS SAMPLE TEMPERATURE
AT DRY GAS METER
INLET.
°C (°F)
Avg
OUTLET.
«C I«F)
Avg
Avg
TEMPERATURE
OF GAS
LEAVING
CONDENSER OR
LAST IMPINGER.
°C(»F)
After turning off the pump and recording the final
readings at the conclusion of each run, remove the probe
from the stack. Conduct a post-test (mandatory) leak-
check as in Section 4.1.4.3 of Method 5 (with appropriate
modification) and record the leak rate. If the post-test
leakage rate exceeds the specified acceptable rate, the
tester shall either correct the sample volume, as outlined
in Section 6.3 of Method 5, or shall void the run.
Drain the ice bath and, with the probe disconnected,
purge the remaining part of the train, by drawing clean
ambient air through the system for 15 minutes at the
average flow rate used for sampling.
NOTK.—Clean ambient air can be provided by passing
air through a charcoal filter. At the option of the tester,
ambient air (without cleaning) may be used.
4.1.6 Calculation of Percent Isokinetic. Follow the
procedure outlined in Method 5, Section 4.1.6.
4.2 Sample Recovery.
4.2.1 Container No. 1. If a moisture content analysis
Figure 8-2. Field data.
is to be done, weigh the first impinger plus contents to
the nearest 0.5 g and record this weight.
Transfer the contents of the first implnger to a 250-ml
graduated cylinder. Rinse the probe, first impinger, all
connecting glassware before the filter, and the front half
of the filter holder with 80 percent isopropanol. Add the
rinse solution to the cylinder. Dilute to 250 ml with 80
percent isopropanol. Add the filter to the solution, mix,
and transfer to the storage container. Protect the solution
against evaporation. Mark the level of liquid on bet
container and Identify the sample container.
4.2.2 Container No. 2. If a moisture content analysis
is to be done, weigh the second and third impingers
(plus contents) to the nearest O.S g and record these
weights. Also, weigh the spent silica gel (or silica gel
plus impinger) to the nearest 0.5 g.
Transfer the solutions from the second and third
Impingers to a 1000-ml graduated cylinder. Rinse all
connecting glassware (including back ballot filter holder)
between the filter and silica gefimpinger with delonlud,
distilled water, and add this rinse water to the cylinder.
Dilute to a volume of 1000 ml with deionlted, distilled
water. Transfer the solution to a storage container. Mark
the level of liquid on the container. Seal and identify the
sample container.
4.3 Analysis.
Note the level of liquid In containers 1 and 2, and con-
firm whether or not any sample was lost during ship-
ment; note this on the analytical data sheet. If a notice-
able amount of leakage has occurred, either void the
sample or use methods, subject to the approval of the
Administrator, to correct the final results. • •
4.3.1 Container No. 1. Shake the container holding
the isopropanol solution and the filter. If the filter
breaks up, allow the fragments to settle for a few minutes
before removing a sample. Pipette a 100-ml aliquot of
this solution Into a 250-ml Erlenmeyer flask, add 2 to 4
drops of thorln Indicator, and titrate to a pink endpolnt
using 0.0100 N barium perchlorate. Repeat the titration
with a second aliquot of sample and average the titration
FEDERAL RESISTHt VOL. 42, NO. 160—THURSDAY, AUGUST It, 1977
V-204
-------
RULES AND REGULATIONS
values. Replicate titratlons must agree within 1 percent
or 03 ml, whichever Is greater.
18.2 Container No. 2. Thoroughly mix the solution
In tbe container holding the contents of the second and
third Implngers. Pipette a 10-ml aliquot of sample Into a
ISO-mi Erlenmeyer flask. Add ml of Isopropanol. 2 to
4 drops of thorln Indicator, and titrate to a pink endpolnt
oring 0.0100 N barium perchlorate. Repeat the tltratlon
with a second aliquot of sample and average the titratlon
Yaluee. Replicate titratlons must agree within 1 percent
or 0.2 mL whichever Is greater.
4JW Blanks. Prepare blanks by adding 2 to 4 drops
of thorln Indicator to 100 ml of 80 percent Isopropanol.
Titrate the blanks In tbe same manner as the samples.
5. CUftrrffe*
6.1 Calibrate equipment oslng the procedures speci-
fied In the tallowing sections of Method 6: Section 5-3
(metering system); Section &£ (temperature gauges):
Section 6.7 (barometer). Note that the recommended
leak-check of tbe metering system, described In Section
6.6 of Method 5, also applies to this method.
8.2 Standardly the barium perchlorate solution with
IS ml of standard sulfuric acid, to which 100 ml of 100
percent Isopropanol has been added.
6. CUeulotioni
Note.—Carry ont calculations retaining at least one
extra decimal figure beyond that of the acquired data.
Round off figures after final calculation.
8.1 Nomenclature.
X.—Cross-sectional area of nozzle, m1 (ft1).
B_—Water vapor In the gas stream, proportion
by volume.
CHtSOi-Suuurlc add (Including BOi) concentration,
g/dscm Ob/dscf).
CSOj—Sulfur dioxide concentration, g/dscm Ob/
dscf).
7—Percent of Isoktnetic sampling.
AT— Normality of barium perchlorate tltrant, g
equivalents/liter.
Fbar-Barometrlc pressure at the sampling site,
mm Hg (In. Hg).
/'.-Absolute stack gas pressure, mm Hg (In.
Pstd
Hg).
•Standard absolute pressure, 780 mm Hg
(29.92 in. Hg).
T.-Average absolute dry gas meter temperature
(seeFlgure8-2>,0K(°R).
r.-Average absolute stack gas temperature (see
Figure 8-2). °K(°B>.
ntd—Standard absolute temperature, 283° K
(528° E).
V.—Volume of sample aliquot titrated, 100 ml
for HjSOi and 10 ml for SOi.
Vi,-Total volume of liquid collected in Implngers
and silica gel, ml.
V.-Volume of gas sample as measured by dry
gas meter, dcm (dcf).
V.(sM) - Volume of gas sample measured by the dry
gas meter corrected to standard conditions,
dscm (dscf).
».—Average stack gas velocity, calculated by
Method 2, Equation 2-9. using data obtained
from Method 8, m/sec (ft/sec).
Vsoln-Total volume of solution in which tbe
anlfurlc acid or sulfur dioxide sample is
contained, 250 ml or 1,000 ml, respectively.
• V.-Volume of barium perchlorate tltrant used
for the sample. mL
Vu-Volume of barium perchlorate tltrant used
for the blank, ml.
X— Dry gas meter calibration factor.
AW-Average pressure drop across orifice meter,
mm (In.) H>O.
8-Total sampling tune, mm.
lS.B<-8peclfic gravity of mercury.
80-sec/mln. •
100— Conversion to percent.
8.2 Average dry gas meter temperature and average
orifice pressure drop. See data sheet (Figure 8-2).
8.8 Dry Gas Volume. Correct the sample volume
measured by tbe dry gas meter to standard conditions
B0° C and 780 nun Hg or 68° F and 29.92 in.Hg) by using
Equation 8-1.
* (.id)=
Equation 8-1
where:
J5T,=O.S858 °E7mm Hg for metric units.
-17.M °R/in. Hg for English units.
NOTI.—If the leak rate observed during any manda-
tory leak-checks exceeds the specified acceptable rate,
tbe tester shall either correct the value of Vm In Equation
S-l (as described in Section 8J of Method o), or shall
invalidate the test run.
8.4 Volume of Water Vapor and Moisture Content.
Calculate the volume of water vapor using Equation
6-2 of Method 6: the weight of water collected in the
Impingers and silica gel can be directly converted to
culate the moisture content of tbe stack gas, using Equa-
tion 6-3 of Method 6. The "Note" in Section 6.5 of Method
5 also applies to this method. Note that If the effluent gas
stream can be considered dry, the volume of water vapor
and moisture content need not be calculated.
&£ Snlfuric acid mist (including SOi) concentration.
N(V,-Va)
Equation 8-2
where:
lTi-0.04904 g/mUliequivalent for metric units.
-1.081XUH Ib/meq for English units.
8.8 Sulfur dioxide concentration.
N(V,-V,t)
Equation 8-3
where: _____
Ki" 0.03203 g/meq for metric units.
-7.081X10-* Ib/meq for English units.
(.7 Isokinetic Variation.
8.7.1 Calculation from raw data.
._ 100 T.[Kt Vlc+ (VJTJ P^ + Ag/13.6)]
. wev.P.A,
Equation 8-1
where:
£1-0.003464 mm Hg-m'/ml-°K for metric units.
-0.002878 in. Hg-ft'/mVR for English units,
8.7.2 Calculation from intermediate values.
-Kt
P.v.A.e(l-B..)
Equation 8-5
where:
Jifi—4.320 for metric ppifai
-0.09450 for English unite.
8.8 Acceptable Results. If 90 percent
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70
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
(FKL 784-7]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61—NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Delegation of Authority;
Review; State of M
New Source
ontana
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule will change the
address -to which reports and applica-
tions must be sent by operators of new
sources in the State of Montana. The
address change is the result of delegation
of authority to the State of Montana for
New Source Performance Standards (40
CFR Part 60) and National Emissions
Standards for Hazardous Air Pollutants
(40 CFR Part 61).
ADDRESS: Any questions or comments
should be sent to Director, Enforcement
Division, - Environmental Protection
Agency, 1860 Lincoln Street, Denver,
Colo. 80295.
FOR FURTHER INFORMATION CON-
TACT:
Mr. Trwln L. Dicksteln, 303-837-3868.
SUPPLEMENTARY INFORMATION:
The amendments below institute certain
address changes for reports and appli-
cations required from operators of new
sources. EPA has delegated to the State
of Montana authority to review new and
modified sources. The delegated author-
ity includes the review under 40 CFR
Part 60 for the standards of performance
for new stationary sources and review
under 40 CFR Part 61 for national emis-
sion standards for hazardous air
pollutants.
A Notice announcing the delegation of
authority is published today in the FED-
ERAL REGISTER (42FR. 44573). The amend-
ments provide that all reports, requests,
applications, submlttals, and communi-
cations previously required for the dele-
gated reviews will now be sent to the
Montana Department of Health and En-
vironmental Sciences Instead of EPA's
Region VXH.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional substantive
burdens are imposed on the parties af-
fected. The delegation which is reflected
by this administrative amendment was
effective on May 18, 1977, and it serves
no purpose to delay the technical change
of this addition of the State address to
the Code of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of sections 111 and 112 of the Clean Air
RULES AND REGULATIONS
Act, as amended, 42 U.S.C. 1857, 1857C-5.
6,7 and 1857g.
Dated: August 17,1977.
JOHN A. GREEN,
Regional 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 (BB) to read
as follows:
g 60.4 Address.
• • • • •
(b) • • •
(BB) State of Montana, Department of
Health and Environmental Services, Cogswell
Building, Helena, Mont. 69601.
Part 61 of Chapter I. Title 40 of the
Code of Federal Regulations is amended
as follows:
2. In { 61.04 paragraph (b) is amended
by revising subparagraph (BB) to read
as follows:
g 61.04 Address.
• • • • . •
(b) • • •
(BB) State of Montana, Department of
Health and Environmental Sciences, Cogs-
well Building. Helena, Mont. 69601.
[FR Doc.77-35827 Filed 9-9-77:8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 17J
TUESDAY, SEPTEMBER 6, 1977
71
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AHt PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Applicability Dates; Correction
AGENCY: Environmental .Protection
Agency.
ACTION: Correction.
SUMMARY: This document correcw
the final rule that appeared at page
87935 In the FEDERAL REGISTER of Mon-
day, July 25, 1977 (FR Doc. 77-21230).
EFFECTIVE DATE: September 7, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, N.C. 27711. telephone
No. 919-541-5271.
Dated: August 31,1977.
EDWARD F. TUERK,
Acting Assistant Administrator,
for Air and Waste Management.
In FR Doc. 77-21230 appearing at page
37935 in the FEDERAL REGISTER of Mon-
day, July 25, 1977, the following correc-
tions are made to §§ 60.250(b) and 60.270
(b) on page 37938:
I. The applicability date in 5 60.250(b)
is corrected to October 24,1974.
2. The applicability date In I 60.270 (b>
is corrected to October 21,1974.
(Sec. Ill, 301 (a) of the Clean Air Act as
amended (42 U.S.C. 1857C-6, 1857g(a)).)
[FR Doc.77-26023 Filed 8-6-77;8:45 am]
RDERAL REGISTER, VOL 42, NO. 173
WEDNESDAY, SEPTEMBER 7. 1977
V-206
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72
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
(FRL 790-4]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of-Authority to State of
Wyoming
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule will change the
address to which reports and applica-
tions must be sent by owners and opera-
tors of new and modified sources in the
State of Wyoming. The address change
is the result of delegation of authority
to the State of Wyoming for New Source
Performance Standards (40 CFR Part
60).
ADDRESS: Any questions or comments
should be sent to Director, Enforcement
Division, Environmental Protection
Agency, 1860 Lincoln Street, Denver,
Colo. 80295.
FOR FURTHER INFORMATION CON-
TACT:
Mr. Irwin L. Dickstein, 303-837-3868.
SUPPLEMENTARY INFORMATION:
The amendments below institute cer-
tain address changes for reports and
applications required from operators of
new and modified sources: EPA has del-
egated to the State of Wyoming au-
thority to review new and modified
sources. The delegated authority in-
cludes Hie review under 40 CFR Part 60
for the standards of performance for
new stationary sources.
A notice announcing the delegation of
authority Is published today in the FED-
ERAL REGISTER (Notices Section). The
amendments now provide that all re-
ports, requests, applications, submittals,
and communications previously required
for the delegated reviews will now be sent
to the Air Quality Division of the Wyo-
ming Department of Environmental
Quality instead of EPA's Region Vm.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
Immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegation which is reflected by this
administrative amendment was effective
on August 2, 1977, and it serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
(Sec. Ill," Clean Air Act, as amended (43
U.S.C. 1857, 18570-6, 6. 7. 18S7g).
Dated: August 25,1977.
JOHN A. GREEN,
Regional 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 (ZZ) to read
RULES AND REGULATIONS
as follows:
§ 60.4 Address.
*****
(b) • • •
(ZZ) State of Wyoming, Air Quality Di-
vision of the Department of Environmental
Quality, Hathaway Building, Cheyenne, Wyo.
82002.
* * • • •
(PR Doc.77-26905 Filed 0-14-77;8:45 am]
FEDERAL IEGISTEK, VOL. 42, NO. 179
THURSDAY, SEPTEMBER 15, 1977
V-207
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RULES AND REGULATIONS
73
Title 40—Protection of Environment
[PRL 770-7]
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Emission Guideline for Sulfuric Acid Mist
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action establishes
emission guidelines and times for com-
pliance for control of sulfuric acid mist
emissions from existing sulfuric acid
plants. Standards of performance have
been issued for emissions of sulfuric acid
mist, a designated pollutant, from new,
modified, and reconstructed sulfuric acid
plants. The Clean Air Act requires States
to control emissions of designated pollut-
ants from existing sources, and this
rulemaking initiates the States' action
and provides them guidelines for what
will be acceptable by EPA.
DATES: State plans providing for the
control of sulfuric acid mist from exist-
ing plants are due for submission to the
Administrator on July 18, 1978. The Ad-
ministrator has four months from the
date required for submission of the plans,
or until November 18, 1978, to take ac-
tion to approve or disapprove the plan
or portions of it.
ADDRESSES: Copies of the final guide-
line document are available by writing
to the EPA Public Information Center
(PM-215), 401 M Street SW., Washing-
ton, D.C. 20460. "Final Guidance Docu-
ment: Control of Sulfuric Acid Mist
Emissions From Existing Sulfuric Acid
Production Units," June 1977, should be
specified when requesting the document.
A summary of the comments and EPA's
responses may be obtained at the same
address. Copies of the comment letters
responding to the proposed rulemaking
published in the FEDERAL REGISTER on
November 4, 1976 (41 FR 48706) are
available for public inspection and copy-
ing at the U.S. Environmental Protection
Agency, Public Information Reference
Unit (EPA Library), Room 2922, 401 M
Street SW., Washington, D.C. 20460.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, N.C. 27711; telephone:
919-541-5271.
SUPPLEMENTARY INFORMATION:
On November 4, 1976 (41 FR 48706) EPA
proposed an emission guideline for sul-
furic acid mist emissions from existing
sulfuric acid plants and announced the
availability or a draft guideline docu-
ment for public comment. A discussion
of the background and comments re-
ceived follows:
BACKGROUND
Section lll(d) of the Clean Air Act
requires that "designated" pollutants
controlled under standards of perform-
ance for new stationary sources by sec-
tion 11 Kb) of the Act must also be con-
trolled at exsiting sources in the same
source category. New source standards of
performance for sulfuric acid mist were
promulgated December 23, 1971 (36 FR
24876). Sulfuric acid mist is considered
a designated pollutant; therefore, it
must be controlled under the provisions
of section lll(d).
As a step toward implementing the re-
quirements of section lll(d), Subpart B
of Part 60, entitled "State Plans for the
Control of Certain Pollutants From Ex-
isting Facilities," was published on No-
vember 17, 1975 (40 FR 53340).
Subpart B provides that once a stand-
ard of performance for the control of a
designated pollutant from a new source
category is promulgated, the Administra-
tor will then publish a draft emission
guideline and guideline .document ap-
plicable to the control of the same pollut-
ant from designated (existing) facilities.
For health-related pollutants, the emis-
sion guideline will be proposed and sub-
sequently be promulgated while emission
guidelines for welfare-related pollutants
will appear only in the applicable guide-
. line document. Sulfuric acid mist is con-
sidered a health-related pollutant; there-
fore, the proposed emission guideline and
the announcement that the draft guide-
line document was available for public
inspection and comment appeared in the
FEDERAL REGISTER November 4, 1976.
Subpart B also provides nine months
for the States to develop and submit
plans for control of the designated pol-
lutant from the date that the notice of
availability of a final guideline is pub-
lished; thus, the States will have nine
months from this date to develop their
plans for the control of sulfuric acid
mist at designated facilities within the
State.
Another provision of Subpart B is that
which provides the Administrator the
option of either approving or disapprov-
ing the State submitted plan or portions
of it within four months after the date
required for submission. If the plan or
a portion of it is disapproved, the Ad-
ministrator is required to promulgate a
new plan or a replacement of the inade-
quate portions of the plan. These and re-
lated provisions of Subpart B are essen-
tially patterned after section 110 of the
Act and 40 CFR Part 51 which sets forth
the requirements for adoption and sub-
mit'al of State implementation plans
under section 110 of the Act.
COMMENTS AND RESPONSES
During the 60-day comment period
following the publication of the proposed
emission guidelines on November 4,1976,
eleven comment letters were received;
four from State pollution control agen-
cies, five from industry and two from
other government agencies. None of the
comments warranted a change in the
emission guideline nor did any com-
ments justify any significant changes in
the guideline document.
One commenter believed that sulfuric
acid mist Is included within the defini-
tion of sulfur oxides as contained in the
Air Quality Criteria for Sulfur Oxides;
therefore, it is subject to control as a cri-
teria pollutant under State implemen-
tation plans, section 110 of the Clean
Act, and not as a designated pollutant
under section lll(d) of the Act. EPA
does not agree with this comment. Sul-
furic acid mist is only one of a number of
related compounds noted in the criteria
document defining sulfur oxides. Sulfuric
acid mist is not listed and regulated In
and of itself. In addition, although some
designr.ted pollutants controlled under
section lll(d) may occur in particulate
a? well as gaseous form and thus may
be controlled to some degree under State
implementation plan regulations requir-
ing control of particulate matter, specific
rather than Incidental control of such
pollutants is required under section
lll(d).
Several commenters were concerned
that the emission guideline was not based
on the health and welfare effects of sul-
furic acid mist or on such other factors
as plant site location and the hazard of
cumulative impacts where emissions
from other sources interacted. Another
commenter noted that since the toxico-
loglcal effects of exposure to sulfuric acid
mist are a function of concentration and
time, a daily maximum time-weighted
average concentration limitation should
be considered.
These comments appear to be based on
a misunderstanding of the intent and
purpose of section lll(d) of the Act. In
the preamble to the section lll(d) pro-
cedural regulation (40 FR 53340), it is
stated that section lll(d) requires emis-
sion controls based on the general prin-
ciple of the application of the best ade-
quately demonstrated control technology,
considering costs, rather than controls
based directly on health or welfare effects
or on other factors such as those men-
tioned in the comments. Section lll(b)
(1) (A) of the Act requires the Admin-
istrator to list categories of sources once
it is determined that they may con-
tribute to the endangerment of public
health or welfare. While this is a pre-
requisite for the development of stand-
ards under section lll(d), the emission
guideline Is technology-based rather
than tied specifically to protection of
health or welfare. The States, In devel-
oping regulations for the control of sul-
furic acid mist, have the prerogative
under 40 CFR 60.24 (f) and (g) to de-
velop standards which may be based on
health or welfare considerations or on
any other relevant factors.
Some of the comments addressed the
stringency of the emission guideline. One
commenter considered the emission
guideline inflexible to the point where Its
application will be too stringent in some
areas and inadequate in others. Another
commenter thought the guideline docu-
ment indicated that facilities using ele-
mental sulfur as feedstock can meet more
rigid emission standards and that the
FEDERAL REGISTER, VOL 42, NO. 201—TUESDAY, OCTOBER 18, 1977
V-208
-------
RULES AND REGULATIONS
emission guidelines should include more
stringent standards for these facilities.
EPA has provided a great deal of
flexibility in developing emission stand-
ards for the control of designated pollut-
ants under Subpart B of Part 60. Specifi-
cally, 40 CFR 60.24(b) provides that
nothing under Subpart B precludes any
State from adopting or enforcing more
stringent emission standards than those
specified in the guideline document. On
the other hand, 40 CPK Part 60.24 (f)
provides that States, "on a case-by-case
basis for particular designated facilities,
or classes of facilities • * * may provide
for the application of less stringent emis-
sion standards than those otherwise re-
quired • • •" provided certain conditions
are demonstrated by the State. The con-
ditions include unreasonable cost of con-
trol resulting from plant age, location or
basic process design, physical impossi-
bility of installing necessary control
equipment, and other factors specific to
the facility that make the application of
a less stringent standard significantly
more reasonable. To include more strin-
gent standards for facilities using ele-
mental sulfur as feedstock would cause
an unacceptable economic burden for
those sources which have already in-
stalled efficient emission control equip-
ment to meet a State regulation. To re-
quire these sources to retrofit additional
emission control equipment to meet a
more stringent standard would be in-
equitable.
MISCELLANEOUS
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Order 11821 and 11949 and
OMB Circular A-107.
Dated: September 22, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
by adding Subpart C as follows:
Subpart C—Emission Guidelines and
Compliance Times
Sec.
60.30 Scope.
60.31 Definitions.
60.32 Designated facilities.
60.83 Emission guidelines.
60.34 Compliance times.
AUTHORITY: Sections lll(d), 301 (a) of the
Clean Air Act as amended (42 U.S.C. 1857c-6
and 1857g(a)), and additional authority as
noted below.
Subpart C—Emission Guidelines and
Compliance Times
§ 60.30 Scope.
This subpart contains emission guide-
lines and compliance times for the con-
trol of certain designated pollutants from
certain designated facilities in accord-
ance with section lll(d> of the Act and
Subpart B.
§ 60.31 Definitions.
Terms used but not denned in this
subpart have the meaning given them
in the Act and in Subparts A and B of
this part.
§ 60.32 Designated facilities.
(a) Sulfuric acid production units.
The designated facility to which f § 60.33
(a) and 60.34(a) apply is each existing
"sulfuric acid production unit" as de-
fined in § 60.81 (a) of Subpart H.
§ 60.33 Emission guidelines.
(a) Sulfuric acid production units.
The emission guideline for designated
facilities is 0.25 gram sulfuric acid mist
(as measured by Reference Method 8, of
Appendix A) per kilogram of sulfuric
acid produced (0.5 Ib/ton), the produ«-
tion being expressed as 100 percent
HJSO..
§ 60.34 Compliance times.
(a) Sulfuric acid production units.
Planning, awarding of contracts, and
installation of equipment capable of
attaining the level of the emission guide-
line established under § 60.33 (a) can be
accomplished within 17 months after the
effective date of a State emission stand-
ard for sulfuric acid mist.
[PR Doc.77-80466 Filed 10-17-77:8:48 am]
FEDERAL REGISTER, VOL. 41, NO. 201
TUESDAY, OCTOBER 18, 1977
74
[PRL 793-4]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to General Provisions and
Copper Smelter Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule clarifies that ex-
cess emissions during periods of startup.
shutdown, and malfunction are not con-
sidered a violation of a standard. This
rule also clarifies that excess emissions
for no more than 1.5 percent of the time
during a quarter will not -be considered
Indicative of a potential violation of the
new source performance standard for
primary copper smelters provided the af-
fected facility and the air pollution con-
trol equipment are maintained and op-
erated consistent with good air pollution
control practice.
EFFECTIVE DATE: November 1. 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division. Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:
BACKGROUND
EPA promulgated standards of per-
formance for primary copper, zinc and
lead smelters on January 15. 1976. On
March 5, 1976, Kennecott Copper Cor-
poration filed a petition with the United
States Court of Appeals for the District
of Columbia Circuit requesting that EPA
reconsider the standards for copper
smelters. EPA proposed to make two
clarifying amendments to the standards,
and Kennecott agreed to withdraw its
court challenge providing these amend-
ments were made. The amendments
being made are in response to the follow-
ing two issues raised in the Kennecott
court appeal:
(1) The standards of performance fail
to provide for excessive emissions during
periods of startup, shutdown, and mal-
function.
(2) The standards of performance
prescribe averaging times too short to ac-
commodate the normal fluctuations in
sulfur dioxide emissions inherent in
smelting operations.
EXCESS EMISSIONS DURING STARTUP.
SHUTDOWN AKD MALFUNCTION
For all sources covered under 40 CFR
Part 60, compliance with numerical emis-
sion limits must be determined through
performance tests. 40 CFR 60.8(c) ex-
empts periods of startup, shutdown, and
malfunction from performance tests. By
implication this means compliance with
numerical emission limits cannot be de-
termined during periods of startup, shut-
down, and malfunction. EPA and Kenne-
cott have agreed that for clarification
V-209
-------
RULES AND REGULATIONS
purposes this should be specifically stated
In the regulation. Therefore, an amend-
ment to this effect is being made in 40
CPR 60.8(c).
This exemption from compliance with
numerical emission limits during startup,
shutdown and malfunction, however,
does not exempt the owner or operator
from compliance with the requirements
of 40 CPR 60.1 l(d) which says: "At all
times, including periods of startup, shut-
down, and malfunction, owners and op-
erators shall, to the extent practicable,
maintain and operate any affected fa-
cility Including associated air pollution
control equipment in a manner con-
sistent with good air pollution control
practice for minimizing emissions."
AVERAGING TIMES
Kennecott alleged that a six-hour
averaging time is not long enough to
average out periods of excessive emis-
sions of sulfur dioxide which normally
occur at smelters equipped with best con-
trol technology. According to Kennecott,
the six-hour averaging period simply
does not mask emission variations caused
by normal fluctuations in gas strengths
and volumes.
A performance test to determine com-
pliance with the numerical emission
limit included in the standard of per-
formance consists of the arithmetic
average of three consecutive six-hour
emission tests. EPA's analysis of the
emission data presented in the back-
ground document ("Background Infor-
mation for New Source Performance
Standards: Primary Copper, Zinc, and
Lead Smelters." October 1974) support-
ing the standards of performance for
copper smelters Indicates that the pos-
sibility of a performance test exceeding
the standard of performance under nor-
mal conditions is extremely low, less than
0.15 percent. This same analysis, how-
ever, indicates that the possibility of
emissions averaged over a single six-
hour period exceeding the numerical
emission limit included in the standard
of performance during normal operation
is about 1.5 percent. To reconcile this
situation with the excess. emission re-
porting requirements, which currently
require all six-hour periods in excess of
the level of the sulfur dioxide standard
to be reported as excess emissions, 40
CPR 60.165 is being amended to provide
that if emissions exceed the level of the
standard for no more than 1.5 percent
of the six-hour averaging periods during
a quarter, they will not be considered
Indicative of potential violation of 40
CPR 60.11'd); i.e., indicative of improper
maintenance or operation. This exemp-
tion applies, however, only if the owner
or operator maintains and operates the
affected facility and air pollution con-
trol equipment in a manner consistent
with good air pollution control practice
for minimizing emissions during these
periods. This ensures that the control
equipment will be operated and emis-
sions will be minimized during this time.
Excess emissions during periods of start-
up, shutdown, and malfunction are not
considered part of the 1.5 percent.
MISCELLANEOUS
The Administrator finds that good
cause exists for omitting prior notice and
public comment on these amendments
and for making them Immediately effec-
tive because they simply clarify the exist-
ing regulations and impose no additional
substantive requirements.
NOTE.—The EPA has determined that thl*
document does not contain a major proposal
requiring preparation of an Economic Impact
Statement under Executive Orders 11831 and
11949, and OMB Circular R-107.
Dated: October 25, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.8, paragraph (c) is amended
to read as follows:
§ 60.8 Performance tests.
(c) Performance tests shall be con-
ducted under such conditions as the Ad-
ministrator shall specify to the plant
operator based on representative per-
formance of the affected facility. The
owner or operator shall make available
to the Administrator such records as may
be necessary to determine the conditions
of the performance tests. Operations
during periods of startup, shutdown, and
malfunction shall not constitute repre-
sentative conditions for the purpose of a
performance test nor shall emissions in
excess of the level of the applicable emis-
sion limit during periods of 'startup,
shutdown, and malfunction be con-
sidered a violation of the applicable
emission limit unless otherwise specified
in the applicable standard.
2. In 560.165, paragraph (d)(2) is
amended to read as follows:
§60.165 Monitoring of operations.
'•••••
(d) * * •
(2) Sulfur dioxide. All six-hour periods
during which the average emissions of
sulfur dioxide, as measured by the con-
tinuous monitoring system Installed
under § 60.163. exceed the level of the
standard. The Administrator will not
consider emissions in excess of the level
of the standard for less than or equal to
1.5 percent of the six-hour periods dur-
ing the quarter as Indicative of a poten-
tial violation of 5 60.11(d) provided the
affected facility, including air pollution
control equipment, is maintained and
operated in a manner consistent with
good air pollution control practice for
minimizing emissions during these pe-
riods. Emissions in excess of the level of
the standard during periods of startup,
shutdown, and malfunction are not to be
included within the 1.5 percent.
(Sees. 111. 114, and 301(a) or the Clean Air
Act as amended (42 U.S.C. 1857C-6, 1857c-»,
18S7g(a)).)
|FB Doc.77-31506 Piled 10-31-77:8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 210
TUESDAY, NOVEMBER 1, 1977
V-210
-------
781-7i
PAKT BO—STANDARDS OF PERFORM-
ICE IFOR NEW STATIONARY SOURCES
Amendment to Subpart 0: Sewage Sludgo
Incinerators
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule revises the ap-
plicability of the standard of perform-
ance for sewage sludge incinerators to
cover any incinerator that burns wastes
containing more than 10 percent sewage
sludge (dry basis) produced by munici-
pal sewage treatment plants, or charges
more than 1000 kg (2205 Ib) per day
municipal sewage sludge (dry basis). The
State of Alaska requested that EPA re-
vise the standard because incinerators
small enough to meet the needs of small
communities in Alaska and comply with
the particulate matter standard are too
costly, and land disposal is not feasible
in areas with permafrost and high water
tables. The intended effect of the revi-
sion is to exempt from the standard
small incinerators for the combined dis-
posal of municipal wastes and sewage
sludge when land disposal, which is
normally a cheaper and preferable alter-
native, is infeasible due to permafrost,
high water tables, or other conditions.
3DATES: This amendment is effective
November 10, 1977, as required by
eilHbHlHB) of the Clean Air"Act as
amended.
FOR FURTHER INFORMATION CON-
(TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On January 26, 1977 (42 FR 4863). EPA
published a proposed amendment to
Subpart 0 of 40 CFR Part 60. An error
in that proposal necessitated a correc-
tion notice that was published on Feb-
ruary 18, 1977 (42 FR 10019). The pro-
posed amendment exempted any sewage
sludge incinerator located at a municipal
waste treatment plant having a dry
sludge capacity below 140 kg/hr (300
Ib/hr), and where it would not be
feasible to dispose of the sludge by land
application or in a sanitary landfill be-
cause of freezing conditions. Prompting
this amendment was a request by the
State of Alaska which noted (1) the
limited availability of small sludge in-
cinerators which can meet the particu-
late matter standard, and (2) the dif-
ficulty of using landfills as an alternative
means of sewage sludge disposal in some
Alaskan communities because of perma-
frost conditions.
During the comment period on that
proposal, four comment letters were re-
ceived. Copies of these letters and a sum-
mary of the comments with EPA's
responses are available for public in-
spection and copying at the EPA Public
Information Reference Unit, Room 2922
(EPA Library), 401 M Street SW., Wash-
ington, D.C. In addition, copies of the
comment summary and Agency re-
sponses may be obtained upon written
request from the Public Information
Center (PM-215), Environmental Pro-
tection Agency, 401 M Street SW..
Washington. D.C. 20460 (specify Public
Comment Summary: Amendment to
Standards of performance for Sewage
Treatment Plants).
One commenter requested that indus-
trial sludge incineration also be ex-
empted by this revision. Only incinera-
tors which bum sludge produced by mu-
nicipal sewage treatment plants are cov-
ered by Subpart O. Incineration of in-
dustrial sludges are not covered because
they may involve special metal, toxic and
radioactive waste problems which were
not addressed by the original study for
developing the standard.
Three other commenters questioned
the applicability of the proposed amend-
ment. One questioned the need for the
proposed exemption, arguing that small
incinerators with control devices suffi-
cient to meet the existing particulate
emission standard of 0.65 g/kg dry sludge
input are commercially available and
should be used. Two others recommended
wording to broaden the proposed exemp-
tion. They suggested that the amend-
ment as propossci is too restrictive, con-
sidering the c(: c'aioi faced by small
communities ir. Alaskt. One noted that
high water-table levels severely limit
land disposal of sludg? in many areas.
The other n.ade a simi :;r comment but
attributed the problem ix> high rainfall
&s well.
Based upon these comments, EPA re-
evaluated the need for the proposed ex-
emption. EPA recognizes that at least
one type of incinerator (the fluidized-
bed type) can be constructed in size cat-
egories of less than 140 kg/hr (300 Ib/hr)
and with emission control equipment ca-
pable of achieving the existing standard.
However, separate sludge disposal by an
Incinerator dedicated exclusively to sew-
age sludge is unduly costly for a small
community. This conclusion is based on
data contained in two EPA publications:
A Guide to the Selection of Cost-Effec-
tive Wastewater Treatment Systems
(EPA-430/9-75-002), and Municipal
Sludge Management: EPA Construction
Grants Program—An Overview of the
Sludge Management Situation (EPA-
430/6-76-009). Sludge incineration costs,
especially those for operation and main-
tenance, were compared for sewage
treatment plants of 1 and 10 million gal-
lons per day (mgd) capacity. Costs for a
1 mgd plant (about 1000 kg of dry sludge
per day) were 100 to 300 percent higher
than those for a 10 mgd facility. A small,
remote community which already incin-
erates its other municipal wastes would
bear the heaviest burden if forced to In-
cinerate its sewage sludge separately.
In most instances, neither municipal
waste nor sewage sludge incinerators are
constructed because land disposal is a
more cost-effective alternative. The co-
incineration of sewage sludge with solid
waste should be a cost-effective and
energy-efficient disposal alternative
whenever land disposal options are not
reasonably available. Since high water
table levels, high annual precipitation.
freezing conditions, and other factors
limit or preclude the land application or
sanitary landfllling of sludge, EPA has
decided to broaden the exemption. Only
freezing conditions were considered in
the proposed exemption. However, an ex-
emption based on these additional fac-
tors would be difficult to enforce due to
climatic variability.
Xn order to make the exemption suffi-
ciently broad and readily enforceable,
EPA has decided to exempt incinerators
that burn not more than 1000 kg per day
of sewage sludge from municipal sewage
treatment plants provided that the sew- '
age sludge (dry basis) does not comprise,
by weight, more than 10 percent of the
total waste burned. The exemption pro-
vides relief only when sewage sludge is
co-incinerated with municipal wastes,
since any incinerator combusting more
than 10 percent sewage sludge is affected
by the emission standard regardless of
the amount of sludge combusted. This
approach, is based principally on the eco-
nomics of sewage waste disposal and ap-
plies to any small community faced with
very difficult land disposal conditions. It
allows disposal of small quantities of
sewage sludge in incinerators primarily
combusting municipal refuse.
Currently, sludge incineration for
small communities is 50 to 100 percent
more costly per ton of dry sludge than
land application or sanitary landfllling.
Even though EPA is proposing criteria
for landfill design and operation, the
costs of incineration are expected to re-
main significantly higher. Thus, it is ex-
pected that this exemption will not cause
a shift to incineration, but will only pro-
V-211
-------
vide relief in areas where land disposal
Is either infeasible or very costly.
The purpose of the amendment is to
relieve small communities (<9,000 pop- •
ulation) of the burden of constructing
separate Incinerators for municipal
wastes and sewage sludge In areas where
land disposal is not feasible. Co-incinera-
tion of sewage sludge with solid wastes
Is less costly than separate sludge in-
cineration and provides an energy bene-
fit in lower auxiliary fuel consumption.
Without this amendment, any co-incin-
eration facility would have been consid-
ered a sludge incinerator under Subpart
0.
Since sludge incineration costs decline
•as the quantities disposed of Increase.
this amendment limits the exemption to
co-incineration units burning not more
than 1000 kg (2205 Ib) dry sludge per
day. At an average generation rate of
0.11 kg (0.25 Ib) dry sludge per person
per day, the 1000 kg limit represents a
population of approximately 9,000 per-
sons. The 10 percent sludge allowance in
such co-incineration is based on the fact
that an average community generates
about 14 times as much solid waste per
person as dry sludge. Thus the 10 percent
allowance should easily permit a small
community to co-incinerate all its sludge
and solid waste in one facility.
This amendment does not affect the
applicability of the National Emission
Standard for Mercury under 40 CFR Part
61. However, significant mercury wastes
are usually not found in sewage sludge
from small communities, but are more
commonly found in metropolitan wastes
from industrial activity.
It should be noted that standards of
performance for new sources established
under section 111 of the Clean Air Act
reflect emission limit* achievable with
the best adequately demonstrated sys-
tems of emission reduction considering
the cost of such systems. State Imple-
mentation plans (SIPs) approved or pro-
mulgated under section 110 of the Act,
on the other hand, must provide for
the attainment and maintenance of na-
tional ambient air 'quality standards
(NAAQS) designed to protect public
health and welfare. For that purpose
SIPs must in some cases require greater
emission reductions than those required
by standards of performance for new
sources.
States are free under section 116 of
the Act to establish even more stringent
emission limits than those necessary to
attain or maintain the NAAQS under
section 110 or those for new sources es-
tablished under section 111. Thus, new
sources may in some ns^es be subject
to limitations more stiS_,_.r-nt than EFA's
standards of performs. •;> under section
111, and prospective owners and opera-
tors of new sourc&s sh.,.M be aware of
this possibility in plnrr.jng for such
facilities.
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a malor proposal requiring
preparation of an Economic Impact Analysis
RULES AND REGULATIONS
under Executive Orders 11821 and 11949 and
OMB Circular A-107.
Dated: November 3,1977.
DOUGLAS M. COSTLE,
Administrator.
In 40 CFR Part 60, Subpart O la
amended by revising { 60.150 and i 60.-
153 as follows:
§ 60.150 Applicability and designation
of affected facility.
(a) The affected facility Is each in-
cinerator that combusts wastes contain-
ing more than 10 percent sewage sludge
(dry basis) produced by municipal sew-
age treatment plants, or each incinerator
that charges more than 1000 kg (2205
Ib) per day municipal sewage sludge (dry
basis).
.(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
Is subject to the requirements of this
subpart.
§ 60.153 Monitoring of operations.
(a) The owner or operator of any
sludge incinerator subject to the provi-
sions of this subpart shall:
(1) Install, calibrate, maintain, and
operate a flow measuring device which
can be used to determine either the mass
or volume of sludge charged to the in-
cinerator. The flow measuring device
shall have an accuracy of ±5 percent
over its operating range.
(2) Provide access to the sludge
charged so that a well mixed representa-
tive grab sample of the sludge can be ob-
tained.
(3) Install, calibrate, maintain, and
operate a weighing device for determin-
ing the mass of any municipal solid
waste charged to the incinerator when
sewage sludge and municipal solid waste
are incinerated together. The weighing
device shall have an accuracy of ±5 per-
cent over its operating range.
(Sections 111. 114, 301 (a) of the Clean Air
Act as amended (42 O.S.C. 1857c-6, 1857C-9.
1857g(a)].)
[FR Doc.77-32667 Piled 11-9-77:8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 217
THURSDAY, NOVEMBER 10, 1977
76
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
|FRL803-8|
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Opacity Provisions for Fossil-Fuel-Fired
Steam Generators
AGENCY: Environmental Protection
Agency (EPA).'
ACTION: Final rule.
SUMMARY: This rule revises the format
of the opacity standard and establishes
reporting requirements for excess emis-
sions of opacity for fossil-fuel-fired
steam generators. This action is nee'ded
to make the standard and reporting re-
quirements conform to changes in the
Reference Method for determining opac-
ity which were promulgated on Novem-
ber 12. 1974, (39 FR 39872). The in-
tended effect is to limit opacity of emis-
sions in order to insure proper operation
and maintenance of facilities subject to
standards of performance.
EFFECTIVE DATE: This rule is effective
on December 5, 1977.
ADDRESSES: A summary of the public
comments received on the September 10,
1975 (40 FR 42028), proposed rule with
EPA's responses is available for public
inspection and copying at the EPA Pub-
lic Information Reference Unit (EPA
Library), room 2922, 401 M Street SW.,
Washington, D.C.. 20460. In addition,
copies of the comment summary may be
obtained by writing to the EPA Public
Information Center (PM-215), Washing-
ton, D.C. 20460 (specify: "Public Com-
ment Summary: Steam Generator Opac-
ity Exception (40 FR 42028)").
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, N.C.
27711, telephone: 919-541-5271.
SUPPLEMENTARY INFORMATION:
The standards of performance for fossil-
fuel-flred steam generators as promul-
gated under Subpart D of Part 60 in De-
cember 23, 1971, (36 FR 24876) allow
emissions up to 20 percent opacity, ex-
cept 40 percent is allowed for two minutes
in any hour. On October 15, 1973. (38
FR 28564) a provision was added to Sub-
part D which required reporting as excess
emissions all hourly periods during
which there were three or more one-
minute periods when average opacity
exceeds 20 percent. Changes to the opa-
city provisions of Subpart A, General
Provisions, and to Reference Method 9,
Visual Determination of the Opacity of
Emissions from Stationary Sources, were
promulgated on November 12, 1974 (39
V-212
-------
RULES AND REGULATIONS
PR 39872). Among these changes is a
requirement that opacity be determined
by averaging 24 readings taken at 15-
second intervals. Because of this change,
the Agency reassessed the opacity stand-
ard originally promulgated under Sub-
part D, and on September 10, 1975, pro-
posed amendments to the opacity stand-
ard and reporting requirements. Specifi-
cally, these amendments would have de-
leted the permissible exemption (two.
minutes per hour of emissions of 40 per-
cent opacity) for gaseous and solid fossil
fuels.
The proposed amendment to the opac-
ity provisions was based on a review of
available data particularly with respect
to the challenge.to the opacity standards
for coal-fired steam generators (Essex
Chemical Corp. et al. v. Ruckelshaus, Ap-
palachian Power Co., et al. vs. EPA, 486
P.2d 427, September 10, 1973). Informa-
tion available at that time indicated that
the two-minute exception allowed under
§ 60.42(a) (2) was unnecessary for large
steam generators fired with solid and
gaseous fossil fuels.
Interested parties were invited to sub-
mit comments. A total of 10 interested
parties, including State agencies, electric
utility firms, and industrial firms sub-
mitted comments. Following a review of
the proposed amendments and consid-
eration of the comments, the amend-
ments have been revised and are being
promulgated today.
While no information was submitted
to show that the exception is needed for
large utility steam generators equipped
with conventional "cold side" electro-
static precipitators or with scrubbers or
fabric filters, commenters contended
that the two-minute "xception is needed
for industrial boilers and for all units
equipped with so-called "hot side" elec-
trostatic precipitators, (i.e., precipitators
installed upstream of the air heater
where temperatures are 590K to 700K).
For industrial boilers in the size range of
73 to 220 MW (250 x 10* to 750 x 10" BTU
per hour) heat input, commenters stated
that the frequency of soot blowing would
have to be increased significantly over
present practices if the exception were
deleted. More frequent soot blowing
would increase costs and energy require-
ments considerably without any decrease
in particulate emissions. Operators of
"hot side" precipitators pointed out that
where hot side precipitators are used,
soot-blowing opacity exceptions are nec-
essary to allow cleaning of the air heater.
They noted that since the air heaters are
downstream of "hot side" precipitators,
any particulate which is Removed by
soot-blowing will be released with ex-
haust gases and will contribute to opac-
ity.
EPA has concluded that lor steam gen-
erators designed for compliance with the
particulate matter standard of perform-
ance, there are legitimate reasons for
providing a limited exception to the
opacity standard, and thus, while the
format of the opacity standard is revised,
the opacity exemption for coal-fired
units is retained. The exception could be
deleted for gaseous fossil fuel, but since
opacity is not a problem from gas-fired
units, there is no need to further compli-
cate the regulation by deleting the ex-
ception for gas. The two-minute excep-
tion could be deleted for very large coal-
fired units O220 MW heat input i that
are not equipped with hot side precipita-
tors, but again the deletion would have
little effect and would needlessly compli-
cate the regulation.
Section 60.42(a) <2) is amended by ex-
pressing the two-minute 40 percent
opacity exception in terms of a six-min-
ute 27 percent average opacity (a
weighted average of two minutes at 40
percent opacity and four minutes at 20
percent opacity) for consistency with
Reference Method 9. This change does
not alter the stringency of the standard.
In addition, S 60.45 (1) which was re-
served on October 6, 1975, (40 FR 46250)
pending resolution of the opacity ex-
ception, is added to require reporting as
excess emissions any six-minute period
during which the average opacity of
emissions exceeds 20 percent opacity, ex-
cept for the one permissible six-minute
period per hour of up to 27 percent
opacity.
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Orders 11821 and 11949 and
OMB Circular A-l 07.
Dated: November 23,1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.42 <1) is added as fol-
lows:
§ 60.45 Emission and furl monitoring.
o * * » *
(g> * * *
(1) Opacity. Excess emissions are de-
fined as any six-minute period during
which the average opacity of emissions
exceeds 20 percent opacity, except that
one six-minute average per hour of up
to 27 percent opacity need not be re-
ported.
(Sec. 111. 114, 301(a), Clean Air Act as
amended (42 UJ5.C.' 7411. 7414, 7601).)
|FR Doc.77-34641 Filed 12-2-77:8:45 am)
FEDERAL REGISTER, VOL. 42, NO. 233
MONDAY, DECEMBER 5, 1977
V-213
-------
77
PART 6O—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the
Commonwealth of Puerto Rico
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: A notice announcing EPA's
delegation of authority for the New
Source Performance Standards to the
Commonwealth of Puerto Rico is pub1
lished at page 62196 of today's FEDERAL
REGISTER. In order to reflect this delega-
tion, this document amends EPA regula-
tions to require the submission of all no-
tices, reports, and other communications
called for by the delegated regulations
to the Commonwealth of Puerto Rico
as well as to EPA.
EFFECTIVE DATE: December 9, 1977.
FOR FURTHER INFORMATION CON-
TACT:
J. Kevin Healy, Attorney, U.S. Envi-
ronme_ntal Protection Agency, Region
II, General Enforcement Branch, En-
forcement Division. 26 Federal Plaza,
New York, N.Y. 10007, 212-264-1196.
SUPPLEMENTARY INFORMATION:
By letter dated "January 13, 1977 EPA
delegated authority to the Common-
wealth of Puerto Rico to implement and
enforce the New Source Performance
Standards. The Commonwealth accepted
this delegation by letter dated October
17,1977. A fujl account of the background
to this action and of the exact terms
of th» delegation appears in the Notice
of Delegation which is also published
in today's FEDERAL REGISTER.
This rulemaking is effective immedi-
ately, since the Administrator has found
good cause to forgo prior public notice.
This addition of the Commonwealth
of Puerto Rico address to the Code of
Federal Regulations is a technical change
and imposes no additional substantive
burden on the parties affected.
Dated: November 22. 1977.
ECKARDT C. BECK.
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
(1) In § 6Q.4 paragraph (b) is amended
by revising subparagraph (BBB) to read
as follows:
§ 60.4 Addrct*.
* * '
(AAA) ' • •
(BBB)—Commonwealth of Puerto Rico:
Commonwealth of Puerto Rico Environmen-
tal Quality Board. P.O. Box 11785, Santurce.
P.R. 00910.
|FR Doc.77-35162 Filed 12-8-77:8.45 am|
FEDERAL REGISTER, VOL 42, NO. 237
FRIDAY. DECEMBER 9. 1977
RULES AND REGULATIONS
78
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
(PRL 838-3]
AIR POLLUTION
Delegation of Authority to the State of
Minnesota for Prevention of Significant
Deterioration; Inspections, Monitoring
•nd Entry; Standards of Performance for
New Stationary Sources; and National
Emission Standards for Hazardous Air
Pollutants
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The amendment below in-
stitutes an address change for the imple-
mentation of technical and administra-
tive review and enforcement of Preven-
tion of Significant Deterioration provi-
sions; Inspections, Monitoring and Entry
provisions; Standards of Performance
for New Stationary Sources; and Nation-
al Emission Standards for Hazardous
Air Pollutants. The notice announcing
the delegation of authority is published
elsewhere in this issue of the FEDERAL
REGISTER.
EFFECTIVE DATE: October 6, 1977.
ADDRESSES: This amendment provides
that all reports, requests, applications.
and communications required for the
delegated authority will no longer be
sent to the US. Environmental Protec-
tion Agency, Region V Office, but will be
sent instead to: Minnesota Pollution
Control Agency, Division of Air Quality,
1935 West County Road B-2, RosevlUe,
Minn. 55113.
FOR FURTHER INFORMATION. CON-
TACT:
Joel Morblto, Air Programs Branch,
U.S. Environmental Protection Agency,
Region V, 230 South Dearborn St.,
Chicago, HI. 60604, 312-353-2205.
SUPPLEMENTARY INFORMATION:
The Regional Administrator finds good
cause for forgoing prior public notice
and for making this rulemaking effective
Immediately in that it is an adminis-
trative change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegations which are granted by
this administrative amendment were
effective October 6, 1977, and it serves
no purpose to delay the technical
change of this addition of the State ad-
dress to the Code of Federal Regulations.
This rulemaking is effective immediately
and is issued under authority of sections
101, 110, 111, 112, 114, 160-169 of the
Clean Air Act, as amended (42 U.S.C.
7401, 7410. 7411, 7412, 7414,—7470-79.
7491). Accordingly, 40 CFR Parts 52, 60
and 61 are amended as follows:
PART 52— APPROVAL AND PROMULGA
TION OF IMPLEMENTATION PLANS
Subpart Y — Minnesota
1. Section 52.1224 is amended by add-
ing a new paragraph (b) (5) as follows:
§ 52.1224 General requirements.
« • • • •
. (b) • • •
(5) Authority of the Regional Admin-
istrator to make available information
and data was delegated to the Minnesota
Pollution Control Agency effective Octo-
ber 6, 1977.
2. Section 52.1234 is amended by add-
ing a new paragraph (c) as follows:
§ 52.1234 Significant deterioration of
air quality.
* • • • •
(c) All applications and other infor-
mation required pursuant to 5 62.21 from
sources located in the State' of Minnesota
shall be submitted to the Minnesota Pol-
lution Control Agency, Division of Air
Quality, 1935 West County Road B-2,
RosevlUe, Minn. 55113.
PART 60 — STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Subpart A — General Provisions
1. Section 60.4 is amended by adding
a new paragraph (b) (Y) as follows:
§ 60.4 Addre».
(b) * • •
(T) Minnesota Pollution Control Agency,
Division of Air Quality, 1935 West County
Road B-2, Rosevllle, Minn. 65113.
FEDERAL REGISTER, VOL. 41, NO. 1
TUESDAY, JANUARY 3, 1978
V-214
-------
79
PART 60—STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Revision of Rcfertnce Method 11 '
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action revises refer-
ence method 11, the method for deter-
mining the hydrogen sulfide content
of fuel gas streams. The revision is
'made because EPA found that inter-
ferences resulting from the presence
of mercaptans in some refinery fuel
gases can lead to erroneous test data
when the current method is used. This
revision eliminates the problem of
mercaptan Interference and insures
the accuracy of the test data.
EFFECTIVE DATE: January 10, 1978.
ADDRESSES: Copies of the comment
letters responding to the proposed re-
vision published in the FEDERAL REGIS-
TER on May 23, 1977 (42 FR 26222),
and a summary of the comments with
EPA's responses are available for
public inspection and copying at the
U.S. Environmental Protection
Agency, Public Information Reference
Unit (EPA Library), Room 2922, 401 M
Street SW., Washington, D.C. 20460. A
copy of the summary of comments and
EPA's responses may be obtained by
writing the Emission Standards and
Engineering Division (MD-13), Envi-
ronmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
When requesting this document,
"Comments and Responses Summary:
Revision of Reference Method 11,"
should be specified.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, N.C. 27711,
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On March 8, 1974, the Environmental
Protection Agency promulgated stan-
dards of performance limiting emis-
sions of sulfur dioxide from new, modi-
fied, and reconstructed fuel gas com-
bustion devices at petroleum refiner-
ies. At the same time, reference
method 11 was promulgated as the
performance test method for measur-
ing H>S in the fuel gases. It was found
after the promulgation of method 11
that interference resulting from the
presence of mercaptans in some refin-
ery fuel gases can lead to erroneous
test results in those cases where mer-
captans were present in significant
concentrations.
RULES AND REGULATIONS
Following studies of the problems
related to reference method 11, it was
decided to revise the method and the
revision was proposed in the FEDERAL
REGISTER on May 23, 1977. The major
change in the proposed revision from
the-original promulgation was a sub-
stitution of a new absorbing solution
that is essentially free from mercap-
tan interference. New sections were
also added which described the range
and sensitivity, interferences, and pre-
cision and accuracy of the revision.
There were seven comments, received
concerning the proposed revision. Five
were received from industry, one from
a local environmental control agency
and one from a research'laboratory.
None of the comments warranted any
significant changes of the proposed re-
vision. The final revision differs from
the revision proposed on May 23, 1977,
in only one respect: Phenylarsine
oxide standard solution has been in-
cluded as an acceptable titrant in lieu
of sodium thiosulf ate.
The effective date of this regulation
is January 10, 1978, because section
HKbXlXB) of the Clean Air Act pro-
vides that standards of performance or
revisions of them become effective
upon promulgation.
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an economic impact analysis
under Executive Orders 11821 and 11949
and OMB Circular A-107.
Dated: December 29, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I of Title 40 of
the Code of Federal Regulations is
amended by revising Method 11 of Ap-
pendix A—Reference Methods as fol-
lows:
APPENDIX A.—REFERENCE METHODS
METHOD 11—DETERMINATION OF HYDROGEN
SULFIDE CONTENT OF FUEL GAS STREAMS IN
PETROLEUM REFINERIES
1. Principle and applicability. 1.1 Princi-
ple. Hydrogen sulfide (H,S) is collected from
a source in a series of midget impingers and
absorbed in pH 3.0 cadmium sulfate (CdSO.)
solution to form cadmium sulfide (CdS).
The latter compound is then measured iodo-
metrically. An impinger containing hydro-
gen peroxide is included to remove SO, as
an interfering species. This method is a revi-
sion of the H>S method originally published
in the FEDERAL REGISTER, Volume 39, No. 47,
dated Friday, March 8, 1974.
1.2 Applicability. This method is applica-
ble for the determination of the hydrogen
sulfide content of fuel gas streams at petro-
leum refineries.
2. Range and sensitivity. The lower limit
of detection is approximately 8 mg/m' (6
ppm). The maximum of the range is 740
mg/m' (520 ppm).
3. Interferences. Any compound that re-
duces iodine or oxidizes iodide ion will inter-
fere in this procedure, provide it is collected
in the cadmium sulfate impingers. Sulfur
dioxide in concentrations of up to 2,600 mg/
m" is eliminated by the hydrogen peroxide
solution. Thiols precipitate with hydrogen
sulfide. In the absence of HiS. only co-traces
of thiols a/e collected. When methane- and
ethane-thiols at a total level of 300 mg/m*
are present in addition to H,S, the results
vary from 2 percent low at an H«S conce'n-
tration of 400 mg/m1 to 14 percent high at
an HiS concentration of 100 mg/m'. Carbon
oxysulfide at a concentration of 20 percent
does not interfere. Certain carbonyl-con-
taining compounds react with iodine and
produce recurring end points. However, ac-
etaldehyde and acetone at concentrations of
1 and 3 percent, respectively, do not inter-
fere.
Entrained hydrogen peroxide produces a
negative interference equivalent to 100 per-
cent of that of an equimolar quantity of hy-
drogen sulfide. Avoid the ejection of hydro-
gen peroxide into the cadmium sulfate im-
pingers.
4. Precision and accuracy. Collaborative
testing has shown the within-laboratory co-
efficient of variation to be 2.2 percent and
the overall coefficient of variation to be 5
percent. The method bias was shown to be
—4.8 percent when only H,S was present. In
the presence of the interferences cited in
section 3, the bias was positive at low H»S
concentrations and negative at higher con-
centrations. At 230 mg H,S/ms, the level of
the compliance standard, the bias was +2.7
percent. Thiols had no effect on the preci-
sion.
5. Apparatus.
5.1 Sampling apparatus.
5.1.1 Sampling line. Six to 7 mm (Vt in.)
Teflon' tubing to connect the sampling
train to the sampling valve.
5.1.2 Impingers. Five midget impingers,
each with 30 ml capacity. The internal di-
ameter of the impinger tip must be 1 mm
±0.05 mm. The impinger tip must be posi-
tioned 4 to 6 mm from the bottom of the im-
pinger.
5.1.3 Glass or Teflon connecting tubing
for the impingers.
5.1.4 Ice bath container. To maintain ab-
sorbing solution at a low temperature.
5.1.5 Drying tube. Tube packed with 6- to
16-mesh indicating-type silica gel, or equiv-
alent, to dry the gas sample and protect the
meter and pump. If the silica gel has been
used previously, dry at 175' C (350* F) for 2
hours. New silica gel may be used as re-
ceived. Alternatively, other types of desic-
cants (equivalent or better) may be used,
subject to approval of the Administrator.
NOTE.—Do not use more than 30 g of silica
gel. Silica gel absorbs gases such as propane
from the fuel gas stream, and use of exces-
sive amounts of silica gel could result in
errors in the determination of sample
volume.
6.1.6 Sampling valve. Needle valve or
equivalent to adjust gas flow rate. Stainless
steel or other corrosion-resistant material.
5.1.7 Volume meter. Dry gas meter, suffi-
ciently accurate to measure the sample
volume within 2 percent, calibrated at the
selected flow rate (-1.0 liter/mm) and con-
ditions actually encountered during sam-
pling. The meter shall be equipped with a
temperature gauge (dial thermometer or
equivalent) capable of measuring tempera-
ture to within 3' C <5.V F). The gas meter
should have a petcock, or equivalent, on the
outlet connector which can be closed during
the leak check. Gas volume for one revolu-
tion of the meter must not be more than 10
liters.
'Mention of trade names of specific prod-
ucts does not constitute endorsement by the
Environmental Protection Agency.
V-215
-------
MILES AW9 SE©y[LA?Q©K)§
5.1.8 Plow meter. Rotameter or equiv-
alent, to measure flow rates In the range
from 0.5 to 2 llters/min (1 to 4 cfh).
5.1.9 Graduated cylinder. 25 ml size.
5.1.10 Barometer. Mercury, aneroid, or
other barometer capable of measuring at-
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby Na-
tional Weather Service station, in which
case, the station value (which is the abso-
lute barometric pressure) shall be requested
and an adjustment for elevation differences
between the weather station and the sam-
pling point shall be applied at a rate of
minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100
ft) elevation increase or vice-versa for eleva-
tion decrease.
5.1.11 U-tube manometer.. 0-30 cm water
column. For leak check procedure.
5.1.12 Rubber squeeze bulb. To pressur-
ize train for leak check.
5.1.13 Tee, pinchclamp, and connecting
tubing. For leak check.
5.1.14 Pump. Diaphragm pump, or equiv-
alent. Insert o small surge tank between the
pump and rate meter to eliminate the pulsa-
tion effect of the diaphragm pump on the
rotameter. The pump is used for the air
purge at the end of the sample run; the
pump is not ordinarily used during sam-
pling, because fuel gas streams are usually
sufficiently pressurized to force sample gas
through the train at the required flow rate.
The pump need not be leak-free unless it is
used for sampling.
5.1.15 Needle valve or critical orifice. To
set air purge flow to 1 liter/min.
5.1.16 Tube packed with active carbon.
To filter air during purge.
5.1.17 Volumetric flask. One 1,000 ml.
5.1.18 Volumetric pipette. One 15 ml.
5.1.19 Pressure-reduction regulator. De-
pending on the sampling stream pressure, a
pressure-reduction regulator may be needed
to reduce the pressure of the gas stream en-
tering the Teflon sample line to a safe level.
5.1.20 Cold trap. If condensed water or
amine is present in the sample stream, a
corrosion-resistant cold trap shall be used
Immediately after the sample tap. The trap
shall not be operated below 0* C (32° F) to
avoid condensation of C, or C. hydrocar-
bons.
5.2 Sample recovery.
5.2.1 Sample container. Iodine flask.
glass-stoppered: 500 ml size.
5.2.2 Pipette. 50 ml volumetric type.
5.2.3 Graduated cylinders. One each 25
and 250 ml.
5.2.4 Flasks. 125 ml, Erlenmeyer.
8.2.5 Wash bottle.
5.2.6 Volumetric flasks. Three 1,000 ml.
5.3 Analysis.
5.3.1 Flask. 500 ml glass-stoppered iodine
flask.
5.3.2 Burette. 50 ml.
5.3.3 Flask. 125 ml, Erlenmeyer.
8.3.4 Pipettes, volumetric. One 25 ml; two
each 50 and 100 ml.
5.3.5 Volumetric flasks. One 1.000 ml:
two 500 ml.
5.3.6 Graduated cylinders. One each 10
and 100 ml.
6. Reagents. Unless otherwise indicated, it
is intended that all reagents conform to the
specifications established by the Committee
on Analytical Reagents of the American
Chemical Society, where such specifications
are available. Otherwise, use best available
grade.
6.1 Sampling.
6.1.1 Cadmium sulfate absorbing solu-
tion. Dissolve 41 g of 3CdSO.-8H,O and 15
ml of 0.1 M sulfuric acid in a 1-liter volumet-
ric flask that contains approximately V, liter
of deionized distilled water. Dilute to
volume with deionized water. Mix thorough-
ly. pH should be 3 ±0.1. Add 10 drops of
Dow-Coming Antifoam B. Shake well before
use. If Antifoam B is not used, the alternate
acidified iodine extraction procedure (sec-
tion 7.2.2) must be used.
6.1.2 Hydrogen peroxide, 3 percent.
Dilute 30 percent hydrogen peroxide to 3
percent as needed. Prepare fresh daily.
6.1.3 Water. Deionized, distilled to con-
form to ASTM specifications Dl 193-72,
Type 3. At the option of the analyst, the
KMnO. test for oxidizable organic matter
may be omitted when high concentrations
of organic matter are not expected to be
present.
8.2 Sample recovery.
8.2.1 Hydrochloric acid solution (HC1),
8M. Add 240 ml of concentrated HC1 (specif-
ic gravity 1.19) to 500 ml of deionized. dis-
tilled water in a 1-liter volumetric flask.
Dilute to 1 liter with deionized water. Mix
thoroughly.
8.2.2 Iodine solution 0.1 N. Dissolve 20 g
of potassium iodi'de (KI) in 30 ml of deion-
ized. distilled water. Add 12.7 g of resub-
limed iodine (It) to the potassium Iodide so-
lution. Shake the mixture until the Iodine Is
completely dissolved. If possible, let the so-
lution stand overnight In the dark. Slowly
dilute the solution to 1 liter with deionized.
distilled water, with swirling. Filter the so-
lution if it is cloudy. Store solution In a
brown-glass reagent bottle.
6.2.3 Standard iodine solution, 0.01 N. Pi-
pette 100.0 ml of the 0.1 N iodine solution
into a 1-liter volumetric flask and dilute to
volume with deionized. distilled water. Stan-
dardize dally as In section 8.1.1. This solu-
tion must be protected from light. Reagent
bottles and flasks must be kept tightly stop-
pered.
6.3 Analysis.
6.3.1 Sodium thiosulfate solution, stan-
dard 0.1 N. Dissolve 24.8 g of sodium thio-
oulfate pentahydrate (Na»S,O,.5H,O> or 15.8
g of anhydrous sodium thiosulfate (Na&O>>
in 1 liter of deionized, distilled water and
add 0.01 g of anhydrous sodium carbonate
(Na,CO,) and 0.4 ml of chloroform (CHCl^)
to stabilize. Mix thoroughly by shaking or
by aerating with nitrogen for approximately
15 minutes and store in a glass-stoppered,
reagent bottle. Standardize as in section
8.1.2.
6.3.2 Sodium thiosulfate solution, stan-
dard 0.01 N. Pipette 50.0 ml of the standard
0.1 N thiosulfate solution into a volumetric
flask and dilute to 500 ml with distilled
water.
NOTE.—A 0.01 N phenylarsine oxide solu-
tion may be prepared instead of 0.01 N thio-
sulfate (see section 6.3.3).
6.3.3 Phenylarsine oxide solution, stan-
dard 0.01 N. Dissolve 1.80 g of phenylarsine
oxide (C.H.AsD) in 150 ml of 0.3 N sodium
hydroxide. After settling, decant 140 ml of
this solution into 800 ml of distilled water.
Bring the solution to pH 6-7 with 6N hydro-
chloric acid and dilute to 1 liter. Standard-
ize as in section 8.1.3.
6.3.4 Starch Indicator solution. Suspend
10 g of soluble starch in 100 ml of deionized,
distilled water and add 15 g of potassium
hydroxide (KOH) pellets. Stir until dis-
solved, dilute with 900 ml of deionized dis-
tilled water and let stand'for 1 hour. Neu-
tralize the alkali with concentrated hydro-
chloric acid, using an indicator paper similar
to Alkacid test ribbon, then add 2 ml of gla-
cial acetic acid as a preservative.
NOTE.—Test starch indicator colution for
decomposition by titrating, with 0.01 W
Iodine solution. 4 ml of starch solution in
200 ml of distilled water that contains 1 g
potassium iodide. If more than 4 drops of
the 0.01 N iodine solution are required to
obtain the blue color, a fresh solution must
be prepared.
7. Procedure.
7.1 Sampling.
7.1.1 Assemble the sampling train as
ohown in figure 11-1. connecting the five
midget impingers in series. Place 15 ml of 3
percent hydrogen peroxide solution in the
first impinger. Leave the second impinger
empty. Place 15 ml of the cadmium sulfate
absorbing solution in the third, fourth, and
fifth Impingers. Place the impinger assem-
bly in an Ice bath container and place
crushed Ice around the impingers. Add more
tee during the run. if needed.
7.1.2 Connect the rubber bulb and mano-
meter to first impinger. as shown in fimire
11-1. Close the petcock on the dry gas meter
outlet. Pressurize the train to 25-cm water
pressure with the bulb and close off tubing
connected to rubber bulb. The train must
hold a 25-cm water pressure with not more
than a 1-cm drop in pressure in a 1-minute
interval. Stopcock grease is acceptable for
sealing ground glass joints.
NOTE.—This leak check procedure is op-
tional at the beginning of the sample run.
but is mandatory at the conclusion. Note
also that If the pump is used for sampling. It
Is recommended (but not required) that the
pump be leak-checked separately, using a
method consistent with the leak-check pro-
cedure for diaphragm pumps outlined in
section 4.1.2 of reference method 8, 00 CFR
Part 60, Appendix A.
7.1.3 Purge the connecting line between
the sampling valve and first impinger, by
disconnecting the line from the first im-
pinger. opening the sampling valve, and al-
lowing process gas to flow through the line
for a minute or two. Then, close the sam-
pling valve and reconnect the line to the im-
pinger train. Open the petcock on the dry
gas meter outlet. Record the initial dry gas
meter reading.
7.1.4 Open the sampling valve and then
adjust the valve to obtain a rate of approxi-
mately 1 liter/min. Maintain a constant
(±10 percent) flow rate during the test.
Record the meter temperature.
7.1.5 Sample for at least 10 min. At the
end of the sampling time, close the sam-
pling valve and record the final volume and
temperature readings. Conduct a leak check
as described in Section 7.1.2 above.
7.1.6 Disconnect the impinger train from
the sampling line. Connect the charcoal
tube and the pump, as shown In figure 11-1.
Purge the train (at a rate of 1 llter/min)
with clean ambient air fpr 15 minutes to
ensure that, all HiS is removed from the hy-
drogen peroxide. For sample recovery, cap
the open ends and remove the impinger
train to a clean area that is aw*..< from
sources of heat. The area should be well
lighted, but not exposed to direct sunlight.
7.2 Sample recovery.
7.2.1 Discard the contents of the hydro-
gen peroxide impinger. Carefully rinse the
contents of the third, fourth, and fifth im-
pingers into a 500 ml Iodine flask.
V-216
-------
tULES AND REGULATIONS
VALVE
(FOR AIR PURGE)
Figure 11-1. H2S sampling train.
NOTE.—The Impingers normally have only
a thin film of cadmium sulfide remaining
'after a water rinse. If Antifoam B was not
used or if significant quantities of yellow
cadmium sulfide remain in the impingers.
the alternate recovery procedure described
below must be used.
7.2.2 Pipette exactly 50 ml of 0.01 N
iodine solution into a 125 ml Erlenmeyer
flask. Add 10 ml of 3 M HC1 to the solution.
Quantitatively rinse the acidified' iodine
Into the iodine flask. Stopper the flask im-
mediately and shake briefly.
7.2.2 (Alternate). Extract the remaining
cadmium sulfide from the third, fourth, and
fifth impingers using the acidified iodine so-
lution. Immediately after pouring the acidi-
fied iodine into an impinger, stopper it and
shake for a few moments, then transfer the
liquid to the iodine flask. Do not transfer
any rinse portion from one impinger to an-
other; transfer it directly to the iodine flask.
Once the acidified iodine solution has been
poured into any glassware containing cadmi-
um sulfide, the container must be tightly
stoppered at all times except when adding
more solution, and this must be done as
quickly and carefully as possible. After
adding any acidified iodine solution to the
iodine flask, allow a few minutes for absorp-
tion of the H.S before adding any further
rinses. Repeat the iodine extraction until all
cadmium sulfide is removed from the im-
pingers. Extract that part of the connecting
glassware that contains visible cadmium sul-
fide.
Quantitatively rinse all of the iodine from
the impingers. connectors, and the beaker
into the iodine flask using deionized, dis-
tilled water. Stopper the flask and shake
briefly.
7.2.3 Allow the iodine flask to stand
about 30 minutes in the dark for absorption
of the H.S into the iodine, then complete
the titration analysis as in section 7.3.
NOTE.—Caution! Iodine evaporates from
acidified iodine solutions. Samples to which
acidified iodine have been added may not be
stored, but must be analyzed in the time
schedule stated in section 7.2.3.
7.2.4 Prepare a blank by adding 45 ml of
cadmium sulfate absorbing solution to an
iodine flask. Pipette exactly 50 ml of 0.01 N
iodine solution into a 125-ml Erlenmeyer
flask. Add 10 ml of 3 M HC1. Follow the
same Impinger extracting and quantitative
rinsing procedure carried out in sample
analysis. Stopper the flask, shake briefly,
let stand 30 minutes in the dark, and titrate
with the samples.
NOTE.—The blank must be handled by ex-
actly the same procedure as that used for
the samples.
7.3 Analysis.
NOTE.—Titration analyses should be con-
ducted at the sample-cleanup area in order
to prevent loss of iodine from the sample.
Titration should never be made in direct
sunlight.
7.3.1 Using 0.01 N sodium thiosulfate so-
lution (or 0.01 N phenylarsine oxide, if ap-
plicable), rapidly titrate each sample in an
iodine flask using gentle mixing, until solu-
tion is light yellow. Add 4 ml of starch indi-
cator solution and continue titrating slowly
until the blue color just disappears. Record
VIT. the volume of sodium thiosulfate solu-
tion used, or VAT, the volume of phenylar-
sine oxide solution used (ml).
7.3.2 Titrate the blanks in the tame
manner as the samples. Run blanks each
day until replicate values agree within 0.05
ml. Average the replicate titration values
which agree within 0.05 ml.
8. Calibration and standards.
8.1 Standardizations.
8.1.1 Standardize the 0.01 N iodine solu-
tion daily as follows: Pipette 25 ml of the
Iodine solution into a 125 ml Erlenmeyer
flask. Add 2 ml of 3 M HC1. Titrate rapidly
with standard 0.01 N thiosulfate solution or
with 0.01 N phenylarsine oxide until the so-
lution is light yellow, using gentle mixing.
Add four drops of starch indicator solution
and continue titrating slowly until the blue
color just disappears. Record VT, the volume
of thiosulfate solution used, or VAS. the
volume of phenylarsine oxide solution used
(ml). Repeat until replicate values agree
within 0.05 ml. Average the replicate titra-
tion values which agree within 0.05 ml and
calculate the exact normality of the iodine
solution using equation 9.3. Repeat the
standardization daily.
8.1.2 Standardize the 0.1 N thiosulfate
solution as follows: Oven-dry potassium di-
chromate (K,Cr,O,) at 180 to 200° C (360 to
390' F). Weigh to the nearest milligram, 2 g
of potassium dichromate. Transfer the di-
chromate to a 500 ml volumetric flask, dis-
solve in deionized. distilled water and dilute
to exactly 500 ml. In a 500 ml iodine flask,
dissolve approximately 3 g of potassium
Iodide (KI) in 45 ml of deionized. distilled
water, then add 10 ml of 3 M hydrochloric
acid solution. Pipette 50 ml of the dichro-
mate solution into this mixture. Gently
swirl the solution once and allow It to stand
in the dark for 5 minutes. Dilute the solu-
tion with 100 to 200 ml of deionized distilled
water, washing down the sides of the flask
with part of the water. Titrate with 0.1 N
thiosulfate until the solution is light yellow.
Add 4 ml of starch indicator and continue ti-
trating slowly to a green end point. Record
V», the volume of thiosulfate solution used
(ml). Repeat until replicate analyses agree
within 0.05 ml. Calculate the normality
using equation 9.1. Repeat the standardiza-
tion each week, or after each test series,
' whichever time is shorter.
8.1.3 Standardize the 0.01 N Phenylar-
sine oxide (if applicable) as follows: oven
dry potassium dichromate (K,Cr,O,) at 180
to 200* C (360 to 390* F). Weigh to the near-
est milligram, 2 g of the K,Cr,O,; transfer
the dichromate to a 500 ml volumetric flask,
dissolve in deionized. distilled water, and
dilute to exactly 500 ml. In a 500 ml Iodine
flask, dissolve approximately 0.3 g of potas-
sium iodide (KI) in 45 ml of deionized, dis-
tilled water add 10 ml of 3M hydrochloric
acid. Pipette 5 ml of the K.Cr.O, solution
Into the iodine flask. Gently swirl the con-
tents of the flask once and allow to stand in
the dark for 5 minutes. Dilute the solution
with 100 to 200 ml of deionized, distilled
water, washing down the sides of the flask
with part of the water. Titrate with 0.01 N
phenylarsine oxide until the solution Is
light yellow. Add 4 ml of starch Indicator
and continue titrating slowly to a green end
point. Record VA, the volume of phenylar-
sine oxide used (ml). Repeat until replicate
analyses agree within 0.05 ml. Calculate the
normality using equation 9.2. Repeat the
standardization each week or after each test
series, whichever time is shorter.
V-217
-------
RULES AND REGULATIONS
8.2 Sampling train calibration. Calibrate
the sampling train components as follows:
8.2.1 Dry gas meter.
8.2.1.1 Initial calibration. The dry gas
meter shall be calibrated before Its Initial
use in the field. Proceed as follows: First, as-
semble the following components in series:
Drying tube, needle valve, pump, rotameter.
and dry gas meter. Then, leak-check the
system as follows: Place a vacuum gauge (at
least 760 mm Hg) at the inlet to the drying
tube and pull a vacuum of 250 mm (10 in.)
Hg; plug or pinch off the outlet of the flow
meter, and then turn off the pump. The
vacuum shall remain stable for at least 30
seconds. Carefully release the vacuum
gauge before releasing the flow meter end.
Next, calibrate the dry gas meter (at the
sampling flow rate specified by the method)
as follows: Connect an appropriately sized
wet test meter (e.g., 1 liter per revolution) to
the Inlet of the drying tube. Make three in-
dependent calibration runs, using at least
five revolutions of the dry gas meter per
run. Calculate the calibration factor, Y (wet
test meter calibration volume divided by the
dry gas meter volume, both volumes adjust-
ed to the same reference temperature and
pressure), for each run, and average the re-
sults. If any Y value deviates by more than 2
percent from the average, the dry gas meter
Is unacceptable for use. Otherwise, use the
average as the calibration factor for subse-
quent test runs.
8.2.1.2 Post-test calibration check. After
each field test series, conduct a calibration
check as in section 8.2.1.1. above, except lor
the following variations: (a) The leak check
Is not to be conducted, (b) three or more
revolutions of the dry gas meter may be
used, and (3) only two independent runs
need be made. If the calibration factor does
not deviate by more than 5 percent from
the initial calibration factor (determined in
section 8.2.1.1.), then the dry gas meter vol-
umes obtained during the test series are ac-
ceptable. If the calibration factor deviates
by more than 5 percent, recalibrate the dry
gas meter as in section 8.2.1.1, and for the
calculations, use the calibration factor (ini-
tial or recalibration) that yields the lower
gas volume for each test run.
8.2.2 Thermometers. Calibrate against
mercury-in-glass thermometers.
8.2.3 Rotameter. The rotameter need not
be calibrated, but should be cleaned and
maintained according to the manufacturer's
Instruction.
8.2.4 Barometer. Calibrate against a mer-
cury barometer.
9. Calculations. Carry out calculations re-
taining at least one extra decimal figure
beyond that of the acquired data. Round off
results only after the final calculation.
9.1 Normality of the Standard (-0.1 N)
Thiosulfate Solution.
N,=2.039 W/V,
where:
W=Weight of K,Cr,O, used. g.
Vs=Volume of Na,S,O, solution used, ml.
N,=Normality of standard thiosulfate solu-
tion, g-eq/liter.
2.039 = Conversion factor
(6 tq. 1,/mole K,Cr,O,> (1,000 ml/liter)/ =
(294.2 g K,Cr,O,/mole) (10 aliquot factor)
9.2 Normality of Standard Phenylarsine
Oxide Solution (If applicable).
- N»=0.2039W/VA
where:
W = Weight of K.Cr.O, used, g.
VA=Volume of C.H,A.O used, ml.
NA=Normality of standard phenylarsine
oxide solution, g = eq/liter.
0.2039 = Con version factor
(6 eq. 1,/mole K.Cr.O,) (1.000 ml/liter)/
(249.2 g K,Cr,O,/mole> (100 aliquot
factor)
9.3 Normality of Standard Iodine Solu-
tion.
N, = NTVT/V,
where:
N, = Normality of standard Iodine solution,
g-eq/liter.
V,=Volume of standard Iodine solution
used, ml.
N, = Normality of standard (-0.01 N) thio-
sulfate solution: assumed to be 0.1 N,, g-
eq/liter.
Vt= Volume of thiosulfate solution used, ml.
NOTE.— If phenylarsine oxide is used
intead of thiosulfate, replace NT and VT in
Equation 9.3 with N» and V«, respectively
(see sections 8.1.1 and 8.1.3).
9.4 Dry Gas Volume. Correct the sample
volume measured by the dry gas meter to
standard conditions (20f C) and 760 mm Hg.
where:
Vm(,ldi=Volume at standard conditions of gas
sample through the dry gas meter, stan-
dard liters.
Vw=Volume of gas sample through the dry
gas meter (meter conditions), liters.
T.u!=Absolute temperature at standard con-
ditions. 293' K.
Tm=Average dry gas meter temperature, "K.
P,,., = Barometric pressure at the sampling
site, mm Hg.
P,ta = Absolute pressure at standard condi-
tions. 760 mm Hg.
Y = Dry gas meter calibration factor.
9.5 Concentration of H.S. Calculate the
concentration of HiS in the gas stream at
standard conditions using the following
equation:
C,,» = K[(V,TN,-VTTNT) sample-
(V.TN.-VrrN,) blank ]/V.,,u)
where (metric units):
CH..s= Concentration of HiS at standard con-
ditions. mg/dscm.
K = Conversion factor= 17.04x10'
(34.07 g/mole H,S) (1,000 liters/m') (1.000
mg/g)/ = (1.000 ml/liter) (2H3 eq/mole)
Vrr = Volume of standard Iodine solu-
tion =50.0 ml.
Ni= Normality of standard iodine solution.
g-eq/liter.
Vr, = Volume of standard (-0.01 N) sodium
thiosulfate solution, ml.
NT= Normality of standard sodium thiosul-
• fate solution, g-eq/liter.
Vrei,uii = Dry gas volume at standard condi-
tions, liters.
NoTE.-»If phenylarsine oxide is used in-
stead of thiosulfate, replace NT and Vn In
Equation 9.5 with NA and V,T. respectively
(see Sections 7.3.1 and 8.1.3).
10. Stability. The absorbing solution Is
stable for at least 1 month. Sample recovery
.and analysis should begin within 1 hour of
sampling to minimize oxidation of the acidi-
fied cadmium sulfide. Once Iodine has been
added to the sample, the remainder of the
analysis procedure must be completed ac-
cording to sections 7.2.2 through 7.3.2.
11. Bibliography.
11.1 Determination of Hydrogen Sulfide.
Ammoniacal Cadmium Chloride Method.
API Method 772-54. In: Manual on Disposal
of Refinery Wastes. Vol. V: Sampling and
Analysis of Waste Gases and Paniculate
Matter, American Petroleum Institute,
Washington, D.C.. 1954.
11.2 Tentative Method of Determination
of Hydrogen Sulfide and Mercaptan Sulfur
In Natural Gas. Natural Gas Processors As-
sociation, Tulsa. Okla., NGPA Publication
No. 2265-65, 1965.
11.3 Knoll, J. E.. and M. R. Mldgett. De-
termination of Hydrogen Sulfide in Refin-
ery Fuel Gases, Environmental Monitoring
Series. Office of Research and Develop-
ment, USEPA, Research Triangle Park, N.C.
27711, EPA 600/4-77-007.
11.4 Scheill, G. W.. and M. C. Sharp.
Standardization of Method 11 at a Petro-
leum Refinery. Midwest Research Institute
Draft Report for USEPA. Office of Re-
search and Development. Research Triangle
Park. N.C. 27711. EPA Contract No. 68-02-
1098. August 1976. EPA 600/4-77-088a
(Volume 1) and EPA 600/4-77-088b (Volume
2).
(Sees. 111. 114, 301(a). Clean Air Act as
amended (42 U.S.C. 7411. 7414. 7601).)
fFR Doc. 78-482 Filed 1-9-78: 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. «
TUESDAY, JANUARY 10, 197(
V-218
-------
80
TH)« 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL PROTECTION
AGENCY
SUtCHAPTH C—A« MOGKAMS
[FRL 846-7]
NEW SOURCE REVIEW
Delegation of Authority to th« Commonwealth
of Kentucky
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The amendments below
Institute certain address changes for
reports and applications required from
operators of new sources. EPA has del-
egated to the Commonwealth of Ken-
tucky authority to review new and
modified sources. The delegated au-
thority includes the reviews under 40
CFB Part 52 for the prevention of sig-
nificant deterioration. It also includes
the review under 40 CFR Part 60 for
the standards of performance for new
stationary sources and reviewed under
40 CFR Part 61 for national emission
standards for hazardous air pollutants.
A notice announcing the delegation of
authority was published in the Notices
section of a previous issue of the FED-
KRAI. REGISTER. These amendments
provide that all reports, requests, ap-
plications, submittals, and communica-
tions previously required for the dele-
gated reviews will now be sent to the
Division of Air Pollution Control, De-
partment for Natural Resources and
Environmental Protection, West
Frankfort Office Complex, U.S. 127,
Frankfort. Ky. 40601, instead of EPA's
Region IV.
EFFECTIVE DATE: January 25, 1978.
FOR FURTHER INFORMATION,
CONTACT:
John Eagles, Air Programs Branch,
Environmental Protection Agency,
Region IV, 345 Courtland Street
NE., Atlanta. Oa. 30308, phone 404-
881-2864.
SUPPLEMENTARY INFORMATION:
The Regional 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 administra-
tive amendment was effective on April
12, 1977, and it serves no purpose to
delay the technical change of this ad-
dition of the state address to the Code
of Federal Regulations.
(Sees. 101. 110. 111. 112, 301. Clean Air Act.
as amended. (42 U.S.C. 7401. 7410. 7411.
7412. 7601).)
Dated: January 10.1978.
JOHN C. WHITE.
Regional Administrator.
RULES AND REGULATIONS
PART 57—APPROVAL AND PROMULGATION
OF IMPLEMENTATION PLANS
Part 52 of Chapter I. Title 40, Code
of Federal Regulations, is amended as
follows:
Subport S—Kentucky
1. Section 52.920(0 is amended by
adding a new paragraph (c)(ll) as fol-
lows:
5 52.920 Identification of plan.
(c) • • •
<11) Letters requesting delegation of
Federal authority for the administra-
tive and technical portions of the Pre-
vention of Significant Deterioration
program were submitted on May 5 and
July 13, 1976 by the Secretary of the
Department for Natural Resources
and Environmental Protection.
2. Section 52.931 Is amended by
adding a new paragraph (c) as follows:
{52.931 Significant deterioration of air
quality.
(c) All applications and other infor-
mation required pursuant to §52.21
from sources located in the Common-
wealth of Kentucky shall be submitted
to the Division of Air Pollution Con-
trol, Department for Natural Re-
sources and Environmental Protection,
West Frankfort Office Complex, U.S.
127. Frankfort, Ky. 40601. Instead of
the EPA Region IV office.
PART 60—STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Part 60 of Chapter I, Title 40, Code
of Federal Regulations, is amended as
follows:
3. In §60.4. paragraph (bXS) is
added as follows:
§60.4 Address.
(S) Division of Air Pollution Control. De-
partment for Natural Resources and Envi-
ronmental Protection. U.S. 127. Frankfort.
Ky. 40601.
PART 61—NATIONAL EMISSION STANDARDS
FOR HAZARDOUS AIR POLLUTANTS
Part 61 of Chapter I, Title 40, Code
of Federal Regulations, is amended as
follows:
4. In §61.04. paragraph (b)(S) is
added as follows:
§61.04 Address.
(b) * • •
(8) Division of Air Pollution Control. De-
partment for Natural Resources and Envi-
ronmental Protection, UJS. 127, Frankfort.
Ky. 40601.
CFR Doc. 78-2032 Filed 1-24-78: 8:45 am]
FEDERAL IKMSTBt VOL 4X NO. IT
WEDNESDAY, JANUARY 25, 1971
V-219
-------
81
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL PROTECTION
AGENCY
SUBCHAFTCR C—Alt MOGtAMS
rPRL 856-1)
PART 60—STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Delegation of Authority to Slat* of Delaware
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends
regulations concerning air programs to
reflect delegation to the State of Dela-
ware of authority to implement and
enforce certain Standards of Perfor-
mance for New Stationary Sources.
EFFECTIVE DATE: February 16,
1978.
FOR FURTHER INFORMATION
CONTACT:
Stephen R. Wassersug, Director, En-
forcement Division, Environmental
Protection Agency, Region III, 6th
and Walnut Streets, Philadelphia.
Pa. 19106, 215-597-4171.
SUPPLEMENTARY INFORMATION:
I. BACKGROUND
On September 7, 1977, the State of
Delaware requested delegation of au-
thority to implement and enforce cer-
tain Standards of Performance for
New Stationary Sources. The reque:'
was reviewed and on September 30,
1977 a letter was sent to Pierre S.
DuPont IV, Governor, State of Dela-
ware, approving the delegation and
outlining its conditions. The approval
letter specified that if Governor
DuPont 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 objec-
tions have been received.
II. REGULATIONS AFFECTED BY THIS
DOCUMENT
Pursuant to the delegation of au-
thority for certain Standards of Per-
formance for New Stationary Sources
to the State of Delaware, EPA is today
amending 40 CFR 60.4, Address, to re-
flect this delegation. A Notice an-
nouncing this delegation (was) pub-
lished on February 15, 1978, in the
FEDERAL REGISTER. The amended
§60.4, which adds the address of the
Delaware Department of Natural Re-
sources and Environmental Control, to
which all reports, requests, applica-
tions, submittals, and communications
to the Administrator pursuant to this
part must also be addressed, is set
forth below.
RULES AND REGULATIONS
III. GENERAL
The Administrator finds good cause
for foregoing prior public notice and
for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional substantive
burdens are imposed on the parties af-
fected. The delegation which is reflect-
ed by this administrative amendment
was effective on September 30, 1977,
and it serves no purpose to delay the
technical change of this address to the
Code of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the author-
ity of Section 111 of the Clean Air Act,
as amended, 42 U.S.C. 1857C-6.
Dated: January 31,1978.
JACK J. SCHRAMM,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. In § 60.4, paragraph (b) is amend-
ed by revising subparagraph (I) to
read as follows:
§60.4 Address.
(b)**»
(A)-(H) • • •
(I) State of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants: asphalt concrete plants: storage ves-
sels for petroleum liquids; and sewage treat-
ment plants only): Delaware Department of
Natural Resources and Environmental Con-
trol, Edward Tatnall Building, Dover, DeL
19901.
[FR Doc. 78-4268 Piled 2-15-78; 8:45 am]
FEDERAL REGISTER, VOL 43, NO. *3
THURSDAY, FEBRUARY, 16, 1971
V-220
-------
TMIo C@—PrsJoeJiea of too
©3APTEB I—EMVIBONMENTAl PROTECTION
A6ENCY
SUDCMAPTOH C—Ala PQOGQAMS
[FRL 833-1]
PAST 60—STANBABBS OF PEBFOBMANCE
. POa MEW STATIONARY SOURCES
Kre>« Pulp Milto
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The standards limit emis-
sions of total reduced sulfur (TRS)
and participate matter from new,
modified, and reconstructed kraft pulp
mills. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from kraft pulp mills con-
tribute significantly to air pollution.
The intended effect of these standards
is to require new, modified, and recon-
structed kraft pulp mills to use the
best demonstrated system of continu-
ous emission reduction.
EFFECTIVE DATE: February 23,
1078.
ADDRESSES: The Standards Support
and Environmental Impact Statement
(SSEIS) may be obtained from the
U.S. EPA Library (MD-35), Research
Triangle Park, N.C. 27711 (specify
"Standards Support and Environmen-
tal Impact Statement, Volume 2: Pro-
mulgated Standards of Performance
for Kraft Pulp Mills" (EPA-450/2-76-
014b)). Copies of all comment letters
received from Interested persons par-
ticipating in this rulemakLng are avail-
able for inspection and copying during
normal business hours at EPA's Public
Information Reference Unit, Room
2622 (EPA Library). 401 M Street SW..
Washington, D.C.
K5R FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Emission Stan-
dards and Engineering Division, En-
vironmental Protection Agency, Re-
search Triangle Park, N.C. 27711,
telephone No. 919-541-5271.
SUPPLEMENTARY INFORMATION:
On September 24, 1976 (41 PR 42012),
otandards of performance were pro-
posed for new, modified, and recon-
structed kraft pulp mills under section
Ell of the Clean Air Act, as amended.
The significant comments that were
received during the public comment
gs^riod have been carefully reviewed
and considered and, where determined
B>y the Administrator to be appropri-
ate, changes have been included in
fchis notice of final rulemaking.
THE STANDARDS
The standards limit emissions of par-
ticulate matter from three affected fa-
cilities at kraft pulp mills. The limits
are: 0.10 gram per dry standard cubic
meter (g/dscm) at 8 percent oxygen
for recovery furnaces, 0.10 gram per
kilogram of black liquor solids (dry
weight) (g/kg BLS) for smelt dissolv-
ing tanks, 0.15 g/dscm at 10 percent
oxygen for lime kilns when burning
gas, and 0.30 c/dscm at 10 percent
oxygen for lime kilns when burning
oil. Visible emissions from recovery
furnaces are limited to 35 percent
opacity.
The standards also limit emissions of
TRS from eight affected facilities at
kraft pulp mills. The limits are: 5 parts
per million (ppm) by volume at 10 per-
cent oxygen from the digester sys-
tems, multiple-effect evaporator sys-
tems, brown stock washer systems,
black liquor oxidation systems, and
condensate stripper systems; 5 ppm by
volume at 8 percent oxygen from
straight kraft recovery furnaces, 8
ppm by volume at 10 percent oxygen
from lime kilns; and 25 ppm by volume
at 8 percent oxygen from cross recov-
ery furnaces, which are defined as fur-
naces burning at least 7 percent neu-
tral sulfite semi-chemical (NSSC)
liquor and having a green liquor sulfi-
dity of at least 28 percent. In addition,
TRS emissions from smelt dissolving
tanks are limited to 0.0084 g/kg BLS.
The proposed TRS standard for the
lime kiln has been changed, a separate
TRS standard for cross recovery fur-
naces has been developed, and the pro-
posed format of the standards for
smelt dissolving tanks, digesters, mul-
tiple-effect evaporators, brown stock
washers, black liquor oxidation and
condensate strippers have been
changed. The TRS, particulate matter
and opacity standards for the other fa-
cilities, however, are essentially the
same as those proposed.
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Clean
Air Act reflect emission limits achiev-
able with the best adequately demon-
strated technological system of con-
tinuous emission reduction considering
the cost of achieving such emission re-
ductions and any sionair quality
health, environmental, and energy im-
pacts. State implementation plans
(SIP's) approved or promulgated
under section 110 of the Act, on the
other hand, must provide for the at-
tainment and maintenance of national
ambient air quality standards
(NAAQS) designed to protect public
health and welfare. For that purpose
SIP's must in some cases require
greater emission reductions than those
required by standards of performance
for new sources. Section 173(2) of the
Clean Air Act, as amended in 1977, re-
quires, among other things, that a new
or modified source constructed in an
area which exceeds the NAAQS must
reduce emissions to the level which re-
flects the "lowest achievable emission
rate" for such category of source,
unless the owner or operator demon-
strates that the source cannot achieve
such an emission rate. In no event can
the emission rate exceed any applica-
ble standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (Part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology. The term "best available con-
trol technology" (BACT) means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines it
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, cost
of achivement may be an important
factor in determining standards of per-
formance applicable to all areas of the
country (clean as well as dirty). Costs
must be accorded far less weight in de-
termining the "lowest achievable emis-
sion rate" for new or modified sources
locating in areas violating statutorily-
mandated health and welfare stan-
dards. Although there may be emis-
sion control technology available that
can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition. States are free under
section 116 of the Act to establish even
more stringent emission limits than
PBBEOAl QEeiSTGQ, V©<_ 08. K». 87—TOyQSSAV, K2DQUAQV 23, 1979
V-221
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RULES AND REGULATIONS
those established under section 111 or
those necessary to attain or maintain
the NAAQS under section 110. Thus,
new sources may in some cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility In planning
for such facilities.
ENVIRONMENTAL AND ECONOMIC IMPACT
The promulgated standards will
reduce particulate emissions about 50
percent below requirements of the
average existing State regulations.
TRS emissions will be reduced by
about 80 percent below requirements
of the average existing State regula-
tions, and this reduction will prevent
odor problems from arising at most
new kraft pulp mills. The secondary
environmental impacts of the promul-
gated standard will be slight Increases
in water demand and wastewater
treatment requirements. The energy
impact of the promulgated standards
will be small, increasing national
energy consumption in 1980 by the
equivalent of only 1.4 million barrels
per year of No. 6 oil. The economic
impact will be small with fifth-year
annualized costs being estimated at
$33 million.
PUBLIC PARTICIPATION
Prior to proposal of the standards,
interested parties were advised by
public notice in the FEDERAL REGISTER
of a meeting of the National Air Pollu-
tion Control Techniques Advisory
Committee. In addition, copies of the
proposed standards and the Standards
Support and Environmental Impact
Statement (SSEIS) were distrubited to
members of the kraft pulp industry
and several environmental groups at
the time of proposal. The public com-
ment period extended from September
24, 1976, to March 14, 1977, and result-
ed in 42 comment letters with 28 of
these letters coming from the indus-
try, 12 from various regulatory agen-
cies, and two from U.S. citizens. Sever-
al comments resulted in changes to
the proposed standards. A'detailed dis-
cussion of the comments and changes
which resulted is presented in Volume
2 of the SSEIS. A summary is present-
ed here.
SIGNIFICANT COMMENTS AND CHANGES
MADE IN THE PROPOSED REGULATIONS
Most of the comment letters re-
ceived contained multiple comments.
The most significant comments and
changes made to the proposed re^'.iia-
tions are discussed below.
IMPACTS OP THE PROPOSED STANDARDS
Several commenters expressed con-
cern about the increased energy con-
sumption which would result from
compliance with proposed standards.
These commenters felt that this would
conflict with the Department of Ener-
gy's goal to reduce total energy con-
sumption in the pulp and paper indus-
try by 14 percent. This factor was con-
sidered in the analysis of the energy
impact associated with the standards
and is discussed in the SSEIS. Al-
though the standards will increase the
difficulty of attaining this energy re-
duction goal, the 4.3 percent increase
in energy usage that will be required
by new, modified, or reconstructed by
kraft pulp mills to comply with the
standards is considered reasonable in
comparison to the benefits which will
result from the corresponding reduc-
tion in TRS and particulate matter
emissions.
EMISSION CONTROL TECHNOLOGY
Most of the comments received re-
garding emission control technology
concerned the application of this tech-
nology to either lime kilns or recovery
furnaces. A few comments, however,
expressed concern with the use of the
oxygen correction factor included in
the proposed standards for both lime
kilns and recovery furnaces. These
commenters pointed out that adjust-
ing the concentration of particulate
matter and TRS emissions to 10 per-
cent oxygen for lime kilns and 8 per-
cent oxygen for recovery furnaces
only when the oxygen concentration
exceeded these values effectively
placed more stringent standards on
the most energy-efficient operators.
To ensure that the standard is equita-
ble for all operators, these com-
menters suggested that the measured
particulate matter and TRS concen-
trations should always be adjusted to
10 percent oxygen for the lime kiln
and 8 percent oxygen for the recovery
furnace.
These comments are valid. Requir-
ing a lime kiln or recovery furnace
with a low oxygen concentration to
meet the same emission concentration
as a lime kiln or recovery furnace with
a high oxygen concentration would ef-
fectively place a more stringent emis-
sion limit on the kiln or furnace with
the low oxygen concentration. Conse-
quently, the promulgated standards
require correction of particulate
matter and TRS concentrations to 10
percent or 8 percent oxygen, as. appro-
priate, in all cases.
Lime Kilns. Numerous comments
were received on the emission control
technology for lime kilns. The main
points questioned by the commenters
were: (a) Whether caustic scrubbing is
effective in reducing TRS emissions
from lime kilns; (b) whether an over-
design of the mud washing facilities at
lime kiln E was responsible for the
lower TRS emissions observed at this
lime kiln; and (c) the adequacy of the
data base used in developing the TRS
standard.
The effectiveness of caustic scrub
blng is substantiated by comparison
TRS emissions during brief peri
when caustic was not being added to
the scrubber at lime kiln E, with TRS
emissions during normal operation at
lime kiln E when caustic is being
added to the scrubber. These observa-
tions clearly indicate that TRS emis-
sions would be higher if caustic was
not used in the scrubber. The ability
of caustic scrubbing to reduce TRS
emissions is also substantiated by the
experience at another kraft pulp mill
which was able to reduce TRS emis-
sions from its lime kiln from 40-50
ppm to about 20 ppm merely by
adding caustic to the scrubber. These
factors, coupled with the emission
data showing higher TRS emissions
from those lime kilns which employed
only efficient mud washing and good
lime kiln process control, clearly show
that caustic scrubbing reduces TRS
emissions.
The mud washing facilities at lime
kiln E are larger than those at other
kraft pulp mills of equivalent pulp ca-
pacity. This "overdesign" resulted
from initial plans of the company to
process lime mud from waste water
treatment. These waste water treat-
ment plans were later abandoned.
Since the quality or efficiency of mud
washing has been shown to be a sig-
nificant factor in reducing TRS emis-
sions from lime kilns, the larger mud
washing facilities at lime kiln E un-
doubtedly contributed to the low TRS
emissions observed at this kiln. With
the data available, however, it is not
possible to separate the relative contri-
bution of these mud washing facilities
to the low TRS emissions observed
from the relative contributions of
good process operation of the lime kiln
and caustic scrubbing.
Comments questioning the adequacy
of the data base used in developing
the standards for lime kilns • were
mainly directed toward the following
points: the TRS standard was based on
only one lime kiln; sampling losses
which may have occurred during test-
ing were not taken into account; and
no lime k»n met both the TRS stan-
dard and the particulate standard.
As mentioned above, the TRS stan-
dard is based upon the emission con-
trol system installed at lime kiln E
(i.e., efficient mud washing, good lime
kiln process operation, and caustic
scrubbing). While it is true that no
other lime kiln in the United States is
currently achieving the TRS emission
levels observed at lime kiln E, there is
no other lime kiln in the United States
which is using the same emission con-
trol system that is employed at this fa-
cility. As discussed in the SSEIS, an
analysis of the various parameters in-
fluencing TRS emissions from lime
kilns indicates that this system of
emission reduction could be applied to
FEDERAL REGISTER, VOL 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-222
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all new, modified, or reconstructed
lime kilns and achieve the same reduc-
"tion in emissions as observed at lime
kiln E. Section 111 of the Clean Air
Act requires that "standards of perfor-
mance reflect the degree of emission
reduction achievable through the ap-
plication of the best system of con-
tinuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, and
any nonair quality health and environ-
mental impact and energy require-
ments) the Administrator determines
has been adequately demonstrated for
that category of sources." Litigation of
standards of performance has resulted
in clarification of the term "adequate-
ly demonstrated." In Portland Cement
Association v. Ruckelshaus (486 F. 2d
876. D.C. Circuit, 1973), the standards
of performance were viewed by the
Court as "technology-forcing." Thus,
while a system of emission reduction
must be available for use to be consid-
ered adequately demonstrated, it does
not have to be In routine use. Howev-
er, In order to ensure that the numeri-
cal emission limit selected was consis-
tent with proper operation and main-
tenance of the emission control system
on lime kiln E, continuous monitoring
fiats, was examined. This analysis indi-
cated that an emission source test of
lime kiln E would have found TRS
emission above 5 ppm greater than 5
percent of the time. This analysis also
indicated, however, that it was very
unlikely that an emission source test
Of lime kiln E would have found TRS
emissions above 8 ppm. Thus, it ap-
peared that the 5 ppm TRS numerical
emission limit • included in the pro-
posed standard for lime kilns was too
stringent. Accordingly, the numerical
emission limit included in the promul-
gated TRS standard for lime kilns has
been -revised to 8 ppm. As discussed
later in this preamble, consistent with
this change in the numerical emission
limit, the excess emissions allowance
included within the emission monitor-
ing requirements has been eliminated.
This does not reflect a change in the
tests for the standard. The standard is
still based on the best system of emis-
sion reduction, considering coats, for
controlling TRS emissions from lime
kilns (i.e., efficient mud washing, good
lime kiln process operation, and caus-
tic scrubbing). This system, or one
equivalent to it, will still be required
to comply with the standard.
Since proposal of the standards,
cample losses of up to 30 percent
during emission source testing have
been confirmed. Although these losses
were not considered in selecting the
numerical emission limit Included In
the proposed TRS emission standard,
they have been considered in selecting
the numerical emission limit Included
in the promulgated standard. Also,
since the amount of sample loss that
occurs within the TRS emission mea-
surement system during source testing
can be determined, procedures have
been added to Reference Method 16
requiring determination of these losses
during each source test and adjust-
ment of the emission data obtained to
take these losses into account.
With regard to the ability of a lime
kiln to comply with both the TRS
emission standard and the partlculate
emission standard simultaneously,
caustic scrubbing will tend to Increase
paniculate emissions due to release of
sodium fume from the scrubbing
liquor. Compared to the concentration
of particulate matter permitted in the
gases discharged to the atmosphere,
however, the potential contribution of
sodium fume from caustic scrubbing is
quite small. Consequently, with proper
operation and maintenance, sodium
fume due to caustic scrubbing will not
cause particulate emissions from a
lime kiln to exceed the numerical
emission limit Included in the promul-
gated standard.
Recovery Furnace. A number of com-
ments were received regarding both
the proposed TRS emission standard
and the proposed particulate emission
standard for recovery furnaces. Basi-
cally, the major issue was whether a
cross recovery furnace could comply
with the 5 ppm TRS standard or
whether a separate standard was nec-
essary.
Review of the data and Information
submitted with these comments Indi-
cates that the operation of cross recov-
ery furnaces is substantially different
from that of straight kraft recovery
furnaces. The sulfidity of the black
liquor burned In cross recovery fur-
naces and the heat content of the
liquor, "both of which are significant
factors Influencing TRS emissions, are
considerably different from the levels
found in straight kraft recovery fur-
Analysis of the data Indicated that
TRS emissions were generally less
then 25 ppm, with only occasional ex-
cursions exceeding this level. Conse-
quently, the promulgated TRS emis-
sion standard has been revised to in-
clude a separate TRS numerical emis-
sion limit of 25 ppm for cross recovery
furnaces.
Smelt Dissolving Tank. Numerous
comments were received concerning
the format of the proposed TRS and
particulate emission standards for
smelt dissolving tanks. These com-
ments pointed out that standards in
terms of emissions per unit of air-dried
pulp were inequitable for kraft pulp
mills which produced low-yield pulps
since both TRS and particulate emis-
sions from the smelt dissolving tanks
are proportional to the tons of black
liquor solids fed into the tanks. The
black liquor solids produced per ton of
air-dried pulp, however, can vary sub-
stantially from mill to mill. A standard
in terms of emissions per unit of air-
dried pulp, therefore, requires greater
control of emissions at krait pulp mills
which use low-yield pulps (higher
solids-to-pulp ratio).
Review of these comments does
indeed indicate that the format of the
proposed standards was inequitable.
The format of the promulgated stan-
dards, therefore, has been revised to
emissions per unit of black liquor
solids fed to the smelt dissolving
tanks. Since the percent solids and
black liquor flow rate to the recovery
furnace is routinely monitored at kraft
pulp mills, the weight of black liquor
solids corresponding to a particular
emissions period will be easy to deter-
mine.
Brown Stock Washers. Several com-
ments expressed concern about com-
bustion of the high volume-low TRS
concentration gases discharged from
brown stock washers and black liquor
oxidation facilities in recovery fur-
naces without facing a serious risk of
explosions. As discussed in the SSEIS,
information obtained from two kraft
pulp mill operators indicates that this
practice is both safe and reliable when
it is accompanied by careful engineer-
ing and operating practices. Danger of
an explosion occurring is essentially
eliminated by introducing the gases
high in the furnace. Since some older
furnaces do not have the capability to
accept large volumes of gases at
higher combustion ports, this practice
may not be safe for some existing fur-
naces. In addition, the costs associated
with altering these furnaces to accept
these gases are frequently prohibitive.
Consequently, the promulgated stan-
dards include an exemption for new,
modified, or reconstructed brown
stock washers and black liquor oxida-
tion facilities within existing kraft
pulp mills where combustion of these
gases in an existing facility is not fea-
sible from a safety or economic stand-
point.
COMTHTOOUS MOOTTORIHO
Numerous comments were received
concerning the proposed continuous
monitoring requirements. Generally,
these comments questioned the re-
quirement to Install TRS monitors in
light of the absence of performance
specifications for these monitors.
At the time of proposal of the stan-
dards, both EPA and the kraft pulp
mill industry were engaged in develop-
ing performance specifications for
TRS continuous emission monitoring
systems. It was expected that this
work would lead to performance speci-
fications for these monitoring systems
by the time the standards of perfor-
'mance were promulgated. Unfortu-
nately, this is not the case. In a joint
EPA/industry effort, the compatibility
of various TRS emission monitoring
QBSdSYEO,
28,
V-223
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BUlliS AM®
methods with Reference Method 16,
which is the performance test method
to determine TRS emissions, is still
under study. There is little doubt but
that these TRS emission monitoring
systems will be shown to be compati-
ble with Reference Method 16, and
that performance specifications for
these systems will be developed. Con-
sequently, the promulgated standards
Include TRS continuous emission mon-
itoring requirements. These require-
ments, however, wiU not become effec-
tive until performance specifications
for TRS continuous emission monitor-
Ing systems have been developed. To
accommodate this situation, not only
for the promulgated standards for
kraft pulp mills, but also for standards
of performance that may be developed
in the future that may also face this
situation, section 60.13 of the General
Provisions for subpart 60 is amended
to provide that continuous monitoring
systems need not be installed until
performance specifications for these
systems are promulgated under Ap-
pendix B to subpart 60. This will
ensure that all facilities which are cov-
ered by standards of performance will
eventually install continuous emission
monitoring systems where required.
EXCESS EMISSIONS
Numerous comments were received
which were concerned with the excess
emission allowances and the reporting
requirements for excess emissions. In
general, these comments reflected a
lack of understanding with regard to
the concept of excess emissions. Con-
sequently, a brief review of this con-
cept is appropriate.
Standards of performance have two
major objectives. The first is installa-
tion of the best system of emission re-
duction, considering costs; and the
second is continued proper operation
and maintenance of the system
throughout its useful life. Since the
numerical emission limit included in
standards of performance is selected
to reflect the performance of the best
system of emission reduction under
conditions of proper operation and
maintenance, the performance test,
under 40 CFR 60.8 represents the abil-
ity of the source to meet these objec-
tives. Performance tests, however, are
often time consuming and complex. As
a result, while the performance test is
an excellent mechanism for achieving
these objectives, it is rather cumber-
some and inconvenient for routinely
achieving these objectives. Therefore,
the Agency believes that continuous
monitors must play an important role
in meeting these objectives.
Excess emissions are defined as emis-
sions exceeding the numerical emis-
sion limit included In a standard of
performance. Continuous emission
monitoring, therefore, identifies peri-
ods of excess emissions and when com-
bined with the requirement that these
periods be reported to EPA, it provides
the Agency with a useful mechanism
for achieving the previously men-
tioned objectives.
Continuous emission monitoring,
however, will identify all periods of
excess emissions, including those
which are not the result of Improper
operation and maintenance. Excess
emissions due to start-ups, shutdowns,
and malfunctions, for example, are un-
avoidable or beyond the control of an
owner or operator and cannot be at-
tributed to improper operation and
maintenance. Similarly, excess emis-
sions as a result of some inherent vari-
ability or fluctation within a process
which influences emissions cannot be
attributed to improper operation and
maintenance, unless these fluctations
could be controlled by more carefully
attending to those process operating
parameters during routine operation
which have, little effect on operation
of the process, but which may have a
significant effect on emissions.
To quantify the potential for excess
emissions due to Inherent variability
in a process, continuous monitoring
data are used whenever possible to cal-
culate an excess emission allowance.
For TRS emissions at kraft pulp mills,
this allowance is defined as follows. If
a calendar quarter is divided into dis-
crete contiguous 12-hour time periods,
the excess emission allowance is ex-
pressed as the percentage of these
time periods. Excess emissions may
occur as the result of unavoidable vari-
ability within the kraft pulping pro-
cess. Thus, the excess emissions
allowance represents the potential for
excess emissions under conditions of
proper operation and maintenance In
the absence of start-ups, shutdowns
and malfunctions, and is used as a
guideline or screening mechanism for
interpreting the data generated by the
excess emission reporting require-
ments.
Although the excess emission report-
ing requirements provide a mechanism
for achieving the objective of proper
operation and maintenance of the best
system of emission reduction, this
mechanism is not necessarily & direct
indicator of improper operation and
maintenance. Consequently, excess
emission reports must be reviewed and
interpreted for proper decisionmaking.
In general, the comments received
concerning the excess emission report-
ing requirements questioned: (1) The
adequacy of the TRS excess emission
allowance for lime kilns and (2) the
lack of a TRS excess emission
allowance for recovery furnaces.
With regard to the adequacy of the
TRS excess emissions allowance for
lime kilns, a reevaluation of the TRS
emission data from lime kiln S led the
Agency to the conclusion that, for a
TRS emission limit of 5 ppm, an
excess emission allowance of 6 percent
was appropriate. However, a similar
analysis also indicates that an excess
emission allowance is not appropriate
at a TRS emission level of 8 ppm. Ac-
cordingly, the excess emission report-
ing requirements included in the pro-
mulgated standard for lime kilns con-
tains no excess emission allowance.
This does not represent a change in
the basis of the standard. The stand-
ard will still require Installation of the
best system of emission reduction, con-
sidering costs
-------
is based consists of efficient mud
washing, good process operation of the
lime kiln, and caustic scrubbing of the
gases discharged from the lime kiln.
As with the emission control system
upon which the standard for recovery
furnaces is based, the first two emis-
sion control techniques (i.e., mud
washing and good process operation)
are not particularly well suited to con-
trolling fluctuations In the kraft pulp-
ins process. The third emission control
technique, however, caustic scrubbing,
is on "add-on" emission control tech-
nique that can be designed to accom-
modate fluctuations in TRS emissions
and minimize or essentially eliminate
these fluctuations.
OMISSION TESTING
A few comments were received
which questioned the validity of the
results obtained by Reference Method
16, due to sample losses and sulfur
dioxide (SO,) Interference.
With regard to the validity of the re-
sults obtained by Reference Method
13, as mentioned earlier, during the
emission testing program, it was not
widely known that sample losses could
occur within the TRS emission mea-
surement system. Since proposal of
the standards, however, sample losses
of up to 20 percent during emission
source testing have been confirmed.
Although these losses were not consid-
ered in selecting the numerical emis-
sion limits included in the proposed
TRS emission standards, they have
been considered in selecting the nu-
merical emission limit included in the
promulgated standards. Also, since the
amount of sample loss that occurs
within the TRS emission measure-
ment system during source testing can
be determined, procedures have been
added to Reference Method 16 requir-
ing determination of these losses
during each source test and adjust-
ment of the emission data obtained to
take these losses into account. This
will ensure that the TRS emission
data obtained during a performance
test are accurate.
It has also been confirmed that high
concentrations of SO, will interfere
with the determination of TRS emis-
sions to some extent. At this point,
however, it is not known what SO,
concentration levels will result in a sig-
nificant loss of accuracy in determin-
ing TRS emissions. The ability of a ci-
trate scrubber to selectively remove
SOj prior to measurement of TRS
emissions is now being tested. In addi-
tion, various chromatographic col-
umns might exist which would effec-
tively resolve this problem. As soon as
an appropriate technique is developed
to overcome this problem. Reference
Method 16 will be amended.
This problem of SO. interference
will not present major difficulties to
the use of Reference Method 16. Rela-
tively high SO» concentration levels
were observed in only one EPA emis-
sion source test. Accordingly, high SO,
concentration levels are probably not
a frequent occurrence within kraft
pulp mills. More importantly, howev-
er, high SO. concentrations only inter-
fere with the determination of methyl
mercaptan in the emission measure-
ment system outlined in Reference
Method 16. Since methyl mercaptan is
usually only & small contributor to
total TRS emissions, neglecting
methyl mercaptan where this interfer-
ence occurs should not seriously affect
the determination of TRS emissions.
Consequently, Reference Method 16
can be used to enforce the promulgat-
ed standards without major difficul-
ties.
Miscellaneous: The effective date of
this regulation is February 24, 1976.
Section HKbXlXB) of the (Clean Air
Act provides that standards of perfor-
mance or revisions of them become ef-
fective upon promulgation and apply
to affected facilities, construction or
modification of which was commenced
after (he date of proposal (September
24, 1976).
MOTS.—An economic assessment has been
prepared as required under section 317 of
the Act. This also satisfies the requirements
of Executive Orders 11821 and OMB Circu-
lar A-107.
Dated: February 10,1978.
BARBARA BLUM,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
Sufepar! A—©onoral Pravloiono
1. Section 60.13 is amended to clarify
the provisions in paragraph (a) by re-
vising paragraph (a) to read as follows:
§60.13 Monitoring requirements.
(a) For the purposes of this section,
all continuous monitoring systems re-
quired under applicable subparts shall
be subject to the provisions of this sec-
tion upon promulgation of perfor-
mance specifications for continuous
monitoring system under Appendix B
to this part, unless:
(1) The continuous monitoring
system is subject to the provisions of
paragraphs (c)(2) and (c)(3) of this
section, or
(2) otherwise specified in an applica-
ble subpart or by the Administrator.
2. Part 60 is amended by adding sub-
part BB as follows:
Ea&pwrt OB—Standards of Performance tor Kraft Pulp
DIllo
Sec.
60.280 Applicability and designation of af-
fected facility.
60.281 Definitions.
60.282 Standard for particulate matter.
60.283 Standard for total reduced sulfur
(TRS).
60.284 Monitoring of emissions and oper-
ations.
60.285 Test methods and procedures.
AUTHORITY: Sees. Ill, 301(a) of the Clean
Air Act. as amended [42 U.S.C. 7411,
7601(a>], end additional authority as noted
below.
Subpert DO—Standards oJ PorJoirasmco (or
Kraft Pulp ftllllo
50.280 Applicability and designation of Ef-
fected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in kraft pulp mills: digest-
er system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, recov-
ery furnace, smelt dissolving tank,
lime kiln, and condensate stripper
system. In pulp mills where kraft
pulping is combined with neutral sul-
fite semlchemical pulping, the provi-
sions of this subpart are applicable
when any portion of the material
charged to an affected facility is pro-
duced by the kraft pulping operation.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after Sep-
tember 24, 1976, is subject to the re-
quirements of this subpart.
§ 60.281 Definitions.
As used in this subpart, all terms not
defined herein shall have the same
meaning given them in the Act and in
Subpart A.
(a) "Kraft pulp mill" means any sta-
tionary source which produces pulp
from wood by cooking (digesting)
wood chips in a water solution of
sodium hydroxide and sodium sulfide
(white liquor) at high temperature
and pressure. Regeneration ^of the
cooking chemicals through a recovery
process Is also considered part of the
kraft pulp mill.
(b) "Neutral sulfite semlchemical
pulping operation" means any oper-
ation in which pulp is produced from
wood by cooking (digesting) wood
chips in a solution of sodium sulfite
and sodium bicarbonate, followed by
mechanical defibrating (grinding).
(c) "Total reduced sulfur (TRS)"
means the sum of the sulfur com-
pounds hydrogen sulfide, methyl mer-
captan, dimethyl sulfide, and dimethyl
disulfide, that are released during the
kraft pulping operation and measured
by Reference Method 16.
(d) "Digester system" means each
continuous digester or each batch di-
gester used for the cooking of wood in
white liquor, and associated flash
tank(s), below tank(s), chip steamer(s),
and condenser(s).
(e) "Brown stock washer system"
means brown stock washers and associ-
ated knotters, vacuum pumps, and fil-
HM1GAS, OGOlSTaa, V©L OS, NO. 37—TOUOSBAV, PGDaWAQY 23, WO
V-225
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RULES AND REGULATIONS
trate tanks used to wash the pulp fol-
lowing the digester system.
(f) "Multiple-effect evaporator
system" means the multiple-effect
evaporators and associated
condenser(s) and hotwell(s) used to
concentrate the spent cooking liquid
that is separated from the pulp (black
liquor).
(g) "Black liquor oxidation system"
means the vessels used to oxidize, with
air or oxygen, the black liquor, and as-
sociated storage tank(s).
(h) "Recovery furnace" means either
a straight kraft recovery furnace or a
cross recovery furnace, and includes
the direct-contact evaporator for a
direct-contact furnace.
(I) "Straight kraft recovery furnace"
means a furnace used to recover
chemicals consisting primarily of
sodium and sulfur compounds by
burning black liquor which on a quar-
terly basis contains 7 weight percent
or less of the total pulp solids from
the neutral sulfite semichemical pro-
cess or has green liquor sulfidity of 28
percent or less.
(J) "Cross recovery furnace" means a
furnace used to recover chemicals con-
sisting primarily of sodium and sulfur
compounds by burning black liquor
which on a quarterly basis contains
more than 7 weight percent of the
total pulp solids from the neutral sul-
fite semichemical process and has a
green liquor sulfidity of more than 28
percent.
(k) "Black liquor solids" means the
dry" weight of the solids which enter
the recovery furnace In the black
liquor.
(1) "Green liquor sulfidity" means
the sulfidity of the liquor which leaves
the smelt dissolving tank.
(m) "Smelt dissolving tank" means a
vessel used for dissolving the smelt
collected from the recovery furnace.
(n) "Lime kiln" means a unit used to
calcine lime mud, which consists pri-
marily of calcium carbonate, into
quicklime, which is calcium oxide.
(o) "Condensate stripper system"
means a column, and associated con-
densers, used to strip, with air or
steam, TRS compounds from conden-
sate streams from various processes
within a kraft pulp mill.
S 60.282 Standard for paniculate 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 provi-
sions of this subpart shall cause to be
discharged into the atmosphere:
(1) From any recovery furnace any
gases which:
(i) Contain particulate matter In
excess of 0.10 g/dscm (0.044 gr/dscf)
corrected to 8 percent oxygen.
(11) Exhibit 35 percent opacity or
greater.
(2) From any smelt dissolving tank
any gases which contain particulate
matter In excess of 0.1 g/kg black
liquor solids (dry weight)[0.2 Ib/ton
black liquor solids (dry weight)].
(3) From any lime kiln any gases
which contain particulate matter in
excess of:
(i) 0.15 g/dscm (0.067 gr/dscf) cor-
rected to 10 percent oxygen, when gas-
eous fossil fuel is burned.
(ii) 0.30 g/dscm (0.13 gr/dscf) cor-
rected to 10 percent oxygen, when
liquid fossil fuel is burned.
{60.283 Standard for total reduced sulfur
(TRS).
(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 provi-
sions of this subpart shall cause to be
discharged into the atmosphere:
(1) From any digester system, brown
stock washer system, multiple-effect
evaporator system, black liquor oxida-
tion system, or condensate stripper
system any gases which contain TRS
in excess of 5 ppm by volume on a dry
basis, corrected to 10 percent oxygen,
unless the following conditions are
met:
(i) The gases are combusted in a lime
kiln subject to the provisions of para-
graph (a)(5) of this section; or
(ii) The gases are combusted In a re-
covery furnace subject to the provi-
sions of paragraphs (aX2) or (a)(3) of
this section; or
(ill) The gases are combusted with
other waste gases In an incinerator or
other device, or combusted In a lime
kiln or recovery furnace not subject to
the provisions of this subpart, and are
subjected to a minimum temperature
of 1200* F. for at least 0.5 second; or
(iv) It has been demonstrated to the
Administrator's satisfaction by the
owner or operator that Incinerating
the exhaust gases from a new, modi-
fled, or reconstructed black liquor oxi-
dation system or brown stock washer
system in an existing facility Is tech-
nologically or economically not feasi-
ble. Any exempt system will become
subject to the provisions of this sub-
part If the facility is changed so that
the gases can be Incinerated.
(2) From any straight kraft recovery
furnace any gases which contain TRS
in excess of 5 ppm by volume on a dry
basis, corrected to 8 percent oxygen.
(3) From any cross recovery furnace
any gases which contain TRS in excess
of 25 ppm by volume on a dry basis,
corrected to 8 percent oxygen.
(4) From any smelt dissolving tank
any gases which contain TRS in excess
of 0.0084 g/kg black liquor solids (dry
weight) [0.0168 Ib/ton liquor solids
(dry weight)].
(5) From any lime kiln any gases
which contain TRS in excess of 8 ppm
by volume on a dry basis, corrected to
10 percent oxygen.
( 60.284 Monitoring of emissions and op-
erations.
(a) Any owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
the following .continuous monitoring
systems:
(DA continuous monitoring system
to monitor and record the opacity of
the gases discharged into the atmos-
phere from any recovery furnace. The
span of this system shall be set at 70
percent opacity.
(2) Continuous monitoring systems
to monitor and record the concentra-
tion of TRS emissions on a dry basis
and the percent of oxygen by volume
on a dry basis in the gases discharged
into the atmosphere from any lime
kiln, recovery furnace, digester
system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, or con-
densate stripper system, except where
the provisions of {60.283(aXl> (ill) or
(iv) apply. These systems shall be lo-
cated downstream of the control
devlce(s) and the span(s) of these con-
tinuous monitoring system(s) shall be
set:
(1) At a TRS concentration of 30
ppm for the TRS continuous monitor-
ing system, except that for any cross.
recovery furnace the span shall be set
at 50 ppm.
(11) At 20 percent oxygen for the
continuous oxygen monitoring system.
(b> Any owner or operator subject to
the provisions of this subpart shall in-'
stall, calibrate, maintain, and operate
the following continuous monitoring
devices:
(1) A monitoring device which mea-
sures the combustion temperature at
the point of incineration of effluent
gases which are emitted from any di-
gester system, brown stock washer
system, multiple-effect evaporator
system, black liquor oxidation system,
or condensate stripper system where
the provisions of J60.283(a)(l)(iii)
apply. The monitoring device is to be
certified by the manufacturer to be ac-
curate within ±1 percent of the tem-
perature being measured.
(2) For any lime kiln or smelt dis-
solving tank using a scrubber emission
control device:
(i) A monitoring device for the con-
tinuous measurement of the pressure
loss of the gas stream through the
control equipment. The monitoring
device is to be certified by the manu-
facturer to be accurate to within a
gage pressure of ±500 pascals (ca. ±2
Inches water gage pressure).
(ii) A monitoring device for the con-
tinuous measurement of the scrubbing
liquid supply pressure to the control
equipment. The monitoring device is
to be certified by the manufacturer to
be accurate within ±15 percent of
design scrubbing liquid supply pres-
sure. The pressure sensor or tap is to
FEDERAL REGISTER, VOL. 43, NO. 37—THURSDAY, FEBRUARY 23, r97l
V-226
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be located close to the scrubber liquid
discharge point. The Administrator
may be consulted for approval of alter-
native locations.
(c) Any owner or operator subject to
the provisions of this subpart shall,
except where the provisions of
§60.283(a)(l)(lv) ' or §60.283(a)(4)
apply.
(1) Calculate and record on a dally
basis 12-hour average TRS concentra-
tions for the two consecutive periods
of each operating day. Each 12-hour
average shall be determined as the
arithmetic mean of the appropriate 12
contiguous 1-hour average total re-
duced sulfur concentrations provided
by each continuous monitoring system
installed under paragraph (a)(2) of
this section.
(2) Calculate and record on a dally
basis 12-hour average oxygen concen-
trations for the two consecutive peri-
ods of each operating day for the re-
covery furnace and lime kiln. These
12-hour averages shall correspond to
the 12-hour average TRS concentra-
tions under paragraph (cXl) of this
section and shall be determined as an
arithmetic mean of the appropriate 12
contiguous 1-hour average oxygen con-
centrations provided by each continu-
ous monitoring system Installed under
paragraph (a)(2) of this section.
(3) Correct all 12-hour average TRS
concentrations to 10 volume percent
oxygen, except that all 12-hour aver-
age TRS concentration from a recov-
ery furnace shall be corrected to -8
volume percent using the following
equation:
Cam=CD=ax(2i-X/2l- Y)
where:
CCT=the concentration corrected for
oxygen.
Coca=the concentration unconnected for
oxygen.
X=the volumetric oxygen concentration In
percentage to be corrected to (8 percent
for recovery furnaces and 10 percent for
lime Iiilns, incinerators, or other de-
. vices).
y=the measured 12-hour average volumet-
ric oxygen concentration.
(d) For the purpose of reports re-
quired under §60.7(c), any owner or
operator subject to the provisions of
this subpart shall report periods of
excess emissions as follows:
(1) For emissions from any recovery
furnace periods of excess emissions
are:
(i) All 12-hour averages of TRS con-
centrations above 5 ppm by volume for
straight kraft recovery furnaces and
above 25 ppm by volume for cross re-
covery furnaces.
(11) All S-minute average opacities
'that exceed 35 percent.
(2) For emissions from any lime kiln,
periods of excess emissions are all 12-
hour average TRS concentration
obove 8 ppm by volume.
(3) For emissions from any digester
system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, or con-
densate stripper system periods of
excess emissions are:
(i) All 12-hour average TRS concen-
trations above 5 ppm by volume unless
the provisions of §60.283(a)Q) (i), (ii),
or (iv) apply; or
(11) All periods in excess of 5 minutes
and their duration during which the
combustion temperature at the point
of incineration Is less than 1200* F.
where the provisions of
g60.283(a)(l)(ii) apply.
(e) The Administrator will not con-
sider periods of excess emissions re-
ported under paragraph (d) of this sec-
tion to be indicative of a violation of
§ 60.ll(d) provided that:
(1) The percent of the total number
of possible contiguous periods of
excess emissions in a quarter (exclud-
ing periods of startup,'shutdown, or
malfunction and periods when the fa-
cility is not operating) during which
excess emissions occur does not
exceed:
(i) One percent for TRS emissions
from recovery furnaces.
(11) Six percent for average opacities
from recovery furnaces.
(2) The Administrator determines
that the affected facility, including air
pollution control equipment, is main-
tained and operated in a manner
which Is consistent with good air pol-
lution control practice for minimizing
emissions during periods of excess
emissions.
§ 60.285 Test methods and procedures.
(a) Reference methods in Appendix
A of this part, except as provided
under g 60.8(b), shall be used to deter-
mine compliance with §80.282(a) as
follows:
(1) Method 5 for the concentration
of particulate matter and the associat-
ed moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) When determining compliance
with g 60.282(a)(2), Method 2 for veloc-
ity and volumetric flow rate, 0
(4) Method 3 for gas analysis, and
(5) Method 9 for visible emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.85 dscm/hr (0.53 dscf/min)
except that shorter sampling times,
when necessitated by process variables
or other factors, may be approved by
the Administrator. Water shall be
used as the cleanup solvent instead of
acetone in the sample recovery proce-
dure outlined in Method 5.
(c) Method 17 (in-stack filtration)
may be used as an alternate method
for Method 5 for determining compli-
ance with g80.282(a)(l)(i): Provided,
That & constant value of 0.009 g/dscm
(0.004 gr/dscf) Is added to the results
of Method 17 and the stack tempera-
ture is no greater than 205° C (ca. 400°
F). Water shall be used as the cleanup
solvent instead of acetone in the
sample recovery procedure outlined in
Method 17.
(d) For the purpose of determining
compliance with §60.283(a) (1), (2),
(3), (4). and (5), the following refer-
ence methods shall be used:
(1) Method 16 for the concentration
of TRS,
(2) Method 3 for gas analysis, and
(3) When determining compliance
with §60.283(a)(4), use the results of
Method 2, Method 16, and the black
liquor solids feed rate in the following
equation to determine the TRS emis-
sion rate.
Where:
E = mass of TRS emitted per unity of black
liquor solids (g/kg> (Ib/ton)
Cms = average concentration of hydrogen
sulfide (HcS) during the test period.
PPM.
CB.SH = average concentration of methyl
mercaptan (MeSH) during the rtest
period, PPM.
CDHE = average concentration of dimethyl
sulfide (DMS) during the test period,
PPM.
CDMM = average concentration of dimethyl
dlsulfide (DMDS) during the test period.
PPM.
Fgt, = 0.001417 g/m" PPM for metric units
= 0.08844 lb/ft» PPM for English units
Pc^m = 0.00200 g/m' PPM for metric units
= 0.1248 lb/ff PPM for English units
fs-jj = 0.002583 g/m1 PPM for metric units
= 0.1612 lb/ff PPM for English units
Foam = 0.003917 g/m' PPM for metric units
= 0.2445 lb/ff PPM for English units
QM = dry volumetric stack gas flow rate cor-
rected to standard conditions, dscm/hr
(dscf/hr)
BLS = black liquor solids feed rate, kg/hr
(Ib/hr)
(4) When determining whether a
furnace Is straight kraft recovery fur-
nace or a cross recovery furnace,
TAPPI Method T.624 shall be used to
determine sodium sulfide, sodium hy-
droxide and sodium carbonate. These
'determinations shall be made three
times daily from the green liquor and
the daily average values shall be con-
verted to sodium oxide + CIMW + CMtco,
Where:
GLS = percent green liquor sulf idity
CMS = average concentration of No* ex-
pressed as Na,O (mg/1)
CMOH-= average concentration of NaOH
expressed as Na,O (mg/1)
Cn^CO. = average concentration of Wo, CO,
expressed as Na,O (mg/1)
(e) All concentrations of particulate
matter and TRS required to be mea-
sured by this section from lime kilns
or Incinerators shall be corrected 10
volume percent oxygen and those con-
centrations from recovery furnaces
KMHIAI DB©a8?BQ. V©!, O, Kl©. 8?—WXMJSOAV, PODQWAQY 23,
V-227
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RULES AND REGULATIONS
shall be corrected to 8 volume percent
oxygen. These corrections shall be
made in the manner specified in
§60.284(0(3).
APPENDIX A—REFERENCE METHODS
(3) Method 16 and Method 17 are
added to Appendix A as follows:
METHOD 16. SEMICONTINUOUS DETERMINATION
OF SULFUR EMISSIONS FROM STATIONARY
SOURCES
Introduction
The method described below uses the
principle of gas chromatographic separation
and flame photometric detection. Since
there are many systems or sets of operating
conditions that represent usable methods of
determining sulfur emissions, all systems
which employ this principle, but differ only
in details of equipment and operation, may
be used as alternative methods, provided
that the criteria set below are met.
1. Principle and Applicability.
1.1 Principle. A gas sample is extracted
from the emission source and diluted with
clean dry air. An aliquot of the diluted
sample is then analyzed for hydrogen sul-
fide (H,S), methyl mercaptan (MeSH), di-
methyl sulfide (DMS) and dimethyl disul-
fide CDMDS) by gas chromatographic (GO
separation and flame photometric detection
(FPD). These four compounds are known
collectively as total reduced sulfur (TRS).
1.2 Applicability. This method is applica-
ble for determination of TRS compounds
from recovery furnaces, lime kilns, and
smelt dissolving tanks at kraft pulp mills.
2. Range and Sensitivity.
2.1 Range. Coupled with a gas chromato-
graphic system utilizing a ten milliliter
sample size, the maximum limit of the FPD
for each sulfur compound is approximately
1 ppm. This limit is expanded by dilution of
the sample gas before analysis. Kraft mill
gas samples are normally diluted tenfold
(9:1), resulting in an upper limit of about 10
ppm for each compound.
For sources with emission levels between
10 and 100 ppm, the measuring range can be
best extended by reducing the sample size
to 1 milliliter.
2.2 Using the sample size, the minimum
detectable concentration is approximately
SO ppb.
3. Interferences.
3.1 Moisture Condensation. Moisture
condensation in the sample delivery system,
the analytical column, or the FPD burner
block can cause losses or interferences. This
potential is eliminated by heating the
sample line, and by conditioning the sample
with dry dilution air to lower its dew point
below the operating temperature of the
OC/FPD analytical system prior to analysis.
3.2 Carbon Monoxide and Carbon Diox-
ide. CO and CO, have substantial desensitiz-
ing effect on the flame photometric detec-
tor even after 9:1 dilution. Acceptable sys-
tems must demonstrate that they have
eliminated this Interference by some proce-
dure such as elutlng these compounds
before any of the compounds to be mea-
sured. Compliance with this requirement
can be demonstrated by submitting chroma-
tograms of calibration gases with and with-
out COt in the diluent gas. The CO, level
should be approximately 10 percent for the
case with COt present. The two chromato-
graphs should show agreement within the
precision limits of Section 4.1.
3.3 Paniculate Matter. Paniculate
matter in gas samples can cause Interfer-
ence by eventual clogging of the analytical
system. This interference must be eliminat-
ed by use of a probe filter.
3.4 Sulfur Dioxide. SO. is not a specific
interferent but may be present in such large
amounts that it cannot be effectively sepa-
rated from other compounds of Interest.
The procedure must be designed to elimi-
nate this problem either by the choice of
separation columns or by removal of SO,
from the sample.
Compliance with this section can be dem-
onstrated by submitting chromatographs of
calibration gases with SO, present in the
same quantities expected from the emission
source to be tested. Acceptable systems
shall show baseline separation with the am-
plifier attenuation set so that the reduced
sulfur compound of concern is at least 50
percent of full scale. Base line separation Is
defined as a return to zero ± percent in the
interval between peaks.
4. Precision and Accuracy.
4.1 OC/FPD and Dilution System Cali-
bration Precision. A series of three consecu-
tive injections of the same calibration gas.
at any dilution, shall produce results which
do not vary by more than ±3 percent from
the mean of the three injections.
4.2 GC/FPD and Dilution System Cali-
bration Drift. The calibration drift deter-
mined from the mean of three injections
made at the beginning and end of any 8-
hour period shall not exceed ± percent.
4.3 System Calibration Accuracy. The
complete system must quantitatively trans-
port and analyze with an accuracy of 20 per-
cent. A correction factor is developed to
adjust calibration accuracy to 100 percent.
5. Apparatus (See Figure 16-1).
6.1.1 Probe. The probe must be made of
Inert material such as stainless steel or
glass. It should be designed to incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
5.1.2 Sample Line. The sample line must
be made of Teflon,1 no greater than 1.3 cm
(V4) inside diameter. All parts from the
probe to the dilution system must be ther-
mostatically heated to 120' C.
5.1.3 Sample Pump. The sample pump
shall be a leakless Teflon-coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120* C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are made of inert materials (e.g..
stainless steel or Teflon). It must be heated
to 120' C. and be capable of approximately a
9:1 dilution of the sample.
5.3 Gas Chromatograph. The gas chro-
matograph must have at least the following
components:
5.3.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.
5.3.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±r C.
5.3.3 Flow System. Gas metering system
to measure sample, fuel, combustion gas,
and carrier gas flows.
•Mention of trade names or specific prod-
ucts does not constitute endorsement by the
Environmental Protection Agency.
5.3.4 Flame Photometric Detector.
5.3.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10-' to 10~4
amperes full scale.
5.3.4.2 Power Supply. Capable of deliver-
ing up to 750 volts.
5.3.4.3 Recorder. Compatible with the
output voltage range of the electrometer.
5.4 Gas Chromatograph Columns. The
column system must be demonstrated to be
capble of resolving the four major reduced
sulfur compounds: H.S, MeSH, DMS, and
DMDS. It must also demonstrate freedom
from known Interferences.
To demonstrate that adequate resolution
has been achieved, the tester must submit a
Chromatograph of a calibration gas contain-
ing all four of the TRS compounds in the
concentration range of the applicable stan-
dard. Adequate resolution will be defined as
base line separation of adjacent peaks when
the amplifier attenuation Is set so that the
smaller peak is at least 50 percent of full
scale. Base line separation is defined in Sec-
tion 3.4. Systems not meeting this criteria
may be considered alternate methods sub-
ject to the approval of the Administrator.
5.5. Calibration System. The calibration
system must contain the following compo-
nents.
5.5.1 Tube Chamber. Chamber of glass or
Teflon of sufficient dimensions to house
permeation tubes.
5.5.2 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lowest flow measurement. Calibra-
tion with a wet test meter before a test is
optional.
5.5.3 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±0.1' C.
5.5.4 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1- C.
6. Reagents.
6.1 Fuel. Hydrogen (H.) prepurified
grade or better.
6.2 Combustion Gas. Oxygen (O.) or air,
research purity or better.
6.3 Carrier Gas. Prepurified grade or
better.
6.4 Diluent. Air containing less than 50
ppb total sulfur compounds and less than 10
ppm each of moisture and total hydrocar-
bons. This gas must be heated prior to
mixing with the sample to avoid water con-
densation at the point of contact.
6.5 Calibration Gases. Permeation tubes,
one each of HJS, MeSH, DMS. and DMDS.
agravlmetrically calibrated and certified at
some convenient operating temperature.
These tubes consist of hermetically sealed
PEP Teflon tubing in which a liquified gas-
eous substance Is enclosed. The enclosed gas
permeates through the tubing wall at a con-
stant rate. When the temperature Is con-
stant, calibration gases Governing a wide
range of known concentrations can be gen-
erated by varying and accurately measuring
the flow rate of diluent gas passing over the
tubes. These calibration gases are used to
calibrate the GC/FPD system and the dilu-
tion system.
7. Pretest Procedures, The following proce-
dures are optional but would be helpful In
preventing any problem which might occur
later and invalidate the entire test.
FEDfkAl aEOIST£», VOL 43, NO. V—THURSDAY, FfMUARY 23, IfTI
V-228
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7.1 After the complete measurement
cyotem has been set up a' the site and
deemed to be operational, the following pro-
cedures should be completed before sam-
pling is initiated.
7.1.1 Leak Test. Appropriate leak test
procedures should be employed to verify the
Integrity of all components, sample lines.
and connections. The following leak test
procedure is suggested: For components up-
otream of the sample pump, attach the
probe end of the sample line to a ma- no-
meter or vacuum gauge, start the pump and
pull greater than 50 mm (2 in.) Hg vacuum,
close off the pump outlet, and then stop the
pump and ascertain that there is no leak for
1 minute. For components after the pump,
apply a slight positive pressure and check
for leaks by applying a liquid (detergent in
oater, for example) at each Joint. Bubbling
indicates the presence of a leak.
7.1.2 System Performance. Since the
complete system is calibrated following each
test, the precise calibration of each compo-
nent is not critical. However, these compo-
nents should be verified to be operating
properly. This verification can be performed
by observing the response of flowmeters or
of the OC output to changes in flow rates or
calibration gas concentrations and ascer-
taining the response to be within predicted
limits. In any component, or if the complete
oystem falls to respond In a normal and pre-
dictable manner, the source of the discrep-
ancy should be identified and corrected
baf ore proceeding.
3. Calibration. Prior to any sampling run,
calibrate the system using the following
procedures. (If more than one run is per-
formed during any 24-hour period, a calibra-
tion need not be performed prior to the
Dscond and any subsequent runs. The cali-
bration must, however, be verified as pre-
ccribed In Section 10, after the last run
mode within the 24-hour period.)
8.1 General Considerations. This section
outlines steps to be followed for use of the
OC/FPD and the dilution system. The pro-
cedure does not include detailed Instruc-
tions because the operation of these systems
is complex, and it requires a understanding
of the individual system being used. Each
cyotem should include a written operating
manual describing in detail the operating
procedures associated with each component
in the measurement system. In addition, the
operator should be familiar with the operat-
ing principles of the components; particular-
ly the GC/FPD. The citations in the Bib-
liojraphy at the end of this method are rec-
ommended for review for this purpose.
0.2 Calibration Procedure. Insert the per-
meation tubes into the tube chamber.
Check the bath temperature to assure
agreement with the calibration temperature
of the tubes within ±0.1* C. Allow 24 hours
tor the tubes to equilibrate. Alternatively
equilibration may be verified by injecting
camples of calibration sas at 1-hour inter-
vals. The permeation tubes can be assumed
to have reached equilibrium when consecu-
tive hourly samples agree within the precl-
oion limits of Section 4.1.
Vary the amount of air flowing over the
tubes to produce the desired concentrations
tor calibrating the analytical and dilution
oystems. The air flow across the tubes must
at all times exceed the flow requirement of
the analytical systems. The concentration In
porto per million generated by a tube con-
taining a specific permeant can be calculat-
ed C3 follows:
Equation 16-1
where:
C= Concentration of permeant produced in
ppm.
P,=Permeation rate of the tube in pg/min.
M=Molecular weight of the permeant (g/g-
mole).
L=Flow rate, 1/min, of air over permeant @
20' C, 760 mm Hg.
K=Gas constant at 20' C and 760 mm
Hg = 24.04 1/gmole.
8.3 Calibration of analysis system. Gen-
erate a series of three or more known con-
centrations spanning the linear range of the
FPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system. Inject these
standards Into the GC/FPD analyzers and
monitor the responses. Three Injects for
each concentration must yield the precision
described in Section 4.1. Failure to attain
this precision Is an indication of a problem
In the calibration or analytical system. Any
such problem must be Identified and cor-
rected before proceeding.
8.4 Calibration Curves. Plot the GC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gen-
erate a known concentration of hydrogen
sulfide using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution Is approximated. Inject the dilut-
ed calibration gas into the GC/FPD system
and monitor its response. Three injections
for each dilution must yield the precision
described in Section 4.1. Failure to attain
this precision in this step Is an indication of
a problem In the dilution system. Any such
problem must be identified and corrected
before proceeding. Using the calibration
data for H.S (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the GC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them Into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
be necessary. However, the precision re-
quirements of Section 4.1 are still applica-
ble.
9. Sampling and Analysis Procedure.
9.1 Sampling. Insert the sampling probe
into the test port making certain that no di-
lution air enters the stack through the port.
Begin sampling and dilute the sample ap-
proxlmtely 9:1 using the dilution system.
Note that the precise dilution factor is that
which Is determined in paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
9.2 Analysis. Aliquots of diluted sample
ore Injected Into the OC/FPD analyzer for
analysis.
9.2.1 Sample Run. A sample run is com-
posed of 16 individual analyses (injects) per-
formed over a period of not less than 3
hours or more than 6 hours.
9.2.2 Observation for Clogging of Probe.
If reductions in sample concentrations are
observed during a sample run that cannot
be explained by process conditions, the sam-
pling must be interrupted to determine if
the sample probe is clogged with paniculate
matter. If the probe is found to be clogged.
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing it with
a clean one. After each run, the sample
probe must be inspected and, If necessary,
dismantled and cleaned.
10. Post-Test Procedures.
10.1 Sample Line Loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard. ±20 percent, must
be Introduced Into the sampling system at
the opening of the probe in sufficient quan-
tities to insure that there is an excess of
sample which must be vented to the atmo-
sphere. The sample must be transported
through the entire sampling system to the
measurement system in the normal manner.
The resulting measured concentration
should be compared to the known value to
determine the sampling system loss. A sam-
pling system loss of more than 20 percent is
unacceptable. Sampling losses of 0-20 per-
cent must be corrected for by dividing the
resulting sample concentration by the frac-
tion of recovery. The known gas sample may
be generated using permeation tubes. Alter-
natively, cylinders of hydrogen sulfide
mixed in air may be used provided they are
traceable to permeation tubes. The optional
pretest procedures provide a good guideline
for determining if there are leaks in the
sampling system.
10.2 Recalibration. After each run. or
after a series of runs made within a 24-hour
period, perform a partial recalibration using
the procedures In Section 8. Only H,S (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).
10.3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration curves
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth in paragraph 4.2. If the drift exceeds
this limit, the Intervening run or runs
should be considered not valid. The tester.
however, may Instead have the option of
choosing the calibration data set which
would give the highest sample values.
11. Calculations.
11.1 Determine the concentrations of
each reduced sulfur compound detected di-
rectly from the calibration curves. Alterna-
tively, the concentrations may be calculated
using the equation for the least square line.
11.2 Calculation of TRS. Total reduced
sulfur will be determined for each anaylsis
made by summing the concentrations of
each reduced sulfur compound resolved
during a given analysis.
TRS=Z (H«S, MeSH. DMS, 2DMDS)d
Equation 16-2
where:
TRS=Total reduced sulfur in ppm, wet
basis.
HsS=Hydrogen sulfide, ppm.
MeSH=Methyl mercaptan. ppm.
DMS = Dimethyl sulfide, ppm.
DMDS = Dimethyl disulfide, ppm.
d=Dilution factor, dimenslonless.
KH330AIL
03,
, PEDQWAQV 28,
V-229
-------
RULES AND REGULATIONS
11.3 Average TRS. The average TRS will
be determined as follows:
I TRS1
Average TRS
Average TRS = Average total reduced suflur
in ppm, dry basis.
TRS,=Total reduced sulfur In ppm as deter-
mined by Equation 16-2.
N=Number of samples.
B,o=Fraction of volume of water vapor in
the gas stream as determined by method
4—Determination of Moisture in Stack
Gases (36 FR 24887).
11.4 Average concentration of individual
reduced sulfur compounds.
C =
Equation 16-3
where:
S,=Concentration of any reduced sulfur
compound from the ith sample injec-
tion, ppm.
C = Average concentration of any one of the
reduced sulfur compounds for the entire
run, ppm.
N = Number of injections in any run period.
12. Example System. Described below is a
system utilized by EPA in gathering NSPS
data. This system does not now reflect all
the latest developments in equipment and
column technology, but it does represent
one system that has been demonstrated to
work.
12.1 Apparatus.
12.1.1 Sampling System.
12.1.1.1 Probe. Figure 16-1 illustrates the
probe used in lime kilns and other sources
where significant amounts of particulate
matter are present, the probe is designed
with the deflector shield placed between the
sample and the gas inlet holes and the glass
wool plugs to reduce clogging of the filter
and possible adsorption of sample gas. The
exposed portion of the probe between the
sampling port and the sample line is heated
with heating tape.
12.1.1.2 Sample Line Via inch Inside diam-
eter Teflon tubing, heated to 120' C. This
temperature is controlled by a thermostatic
heater.
12.1.1.3 Sample Pump. Leakless Teflon
coated diaphragm type or equivalent. The
pump head is heated to 120' C by enclosing
it in the sample dilution box (12.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system is
given in Figure 16-2. The dilution system is
constructed such that all sample contacts
are made of inert materials. The dilution
system which is heated to 120' C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below:
12.1.2.1 Dilution Pump. Model A-150
Kohmyhr Teflon positive displacement
type, nonadjustable 150 cc/min. ±2.0 per-
cent, or equivalent, per dilution stage. A 9:1
dilution of sample is accomplished by com-
bining 150 cc of sample with 1.350 cc of
clean dry air as shown in Figure 16-2.
12.1.2.2 Valves. Three-way Teflon sole-
noid or manual type.
12.1.2.3 Tubing. Teflon tubing and fit-
tings are used throughout from the sample
probe to the GC/FPD to present an inert
surface for sample gas.
12.1.2.4 Box. Insulated 'box, heated and
maintained at 120* C, of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotameters or
equivalent to measure flow from 0 to 1500
ml/min ±1 percent per dilution stage.
12.1.3 Gas Chromatograph Columns.
Two types of columns are used for separa-
tion of low and high molecular weight
sulfur compounds:
12.1.3.1 Low Molecular Weight Sulfur
Compounds Column (GC/FPD-1).
12.1.3.1 Separation Column. 11 m by 2.16
mm (36 ft by 0.085 In) inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 5 percent polyphenyl
ether and 0.05 percent orthophosphoric
acid, or equivalent (see Figure 16-3).
12.1.3.1.2 Stripper or Precolumn. 0.6 m
by 2.16 mm (2 ft by 0.085 in) inside diameter
Teflon tubing packed as in 5.3.1.
12.1.3.1.3 Sample Valve. Teflon 10-port
gas sampling valve, equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).
12.1.3.1.4 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100' C. constant within
±1- C.
12.1.3.1.5 Temperature Monitor. Thermo-
couple pyrometer to measure column oven,
detector, and exhaust temperature ±1' C.
12.1.3.1.6 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, and oxygen flow (and nitrogen carrier
gas flow).
12.1.3.1.7 Detector. Flame photometric
detector.
12.1.3.1.8 Electrometer. Capable of full
scale amplification of linear ranges of 10"*
to 10"' amperes full scale. -
12.1.3.1.9 Power Supply. Capable of deli-
vering up to 750 volts.
12.1.3.1.10 Recorder. Compatible with
the output voltage range of the electrom-
eter.
12.1.3.2 High Molecular Weight Com-
pounds Column (GC/FPD-11).
12.1.3.2.1. Separation Column. 3.05 m by
2.16 mm (10 ft by 0.0885 in) Inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 10 percent Triton X-305.
or equivalent.
12.1.3.2.2 Sample Valve. Teflon 6-port gas
sampling valve equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).
12.1.3.2.3 Other Components. All compo-
nents same as in 12.1.3.1.4 to 12.1.3.1.10.
12.1.4 Calibration. Permeation tube
system (figure 16-4).
12.1.4.1 Tube Chamber. Glass chamber
of sufficient dimensions to house perme-
ation tubes.
12.1.4.2 Mass Flowmeters. Two mass
flowmeters In the range 0-3 1/min. and 0-10
1/min. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate in the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this flow rate as measured
by one flowmeter followed by injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not, then there Is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter, at
least once each year.
12.1.4.3 Constant Temperature Bath. Ca-
pable of maintaining permeation tubes at
certification temperature of 30' C. within
±O.V C.
12.2 Reagents
12.2.1 Fuel. Hydrogen (Hi) prepurified
grade or better.
12.2.2. Combustion Gas. Oxygen (O,) re-
search purity or better.
12.2.3 Carrier Gas. Nitrogen (N,) prepuri-
fied grade or better.
12.2.4 Diluent. Air containing less than
50 ppb total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons, and filtered using MSA filters
46727 and 79030, or equivalent. Removal of
sulfur compounds can .be verified by Inject-
ing dilution air only, described in Section
8.3.
12.2.5 Compressed Air. 60 psig for GC
valve actuation.
12.2.6 Calibrated Gases. Permeation
tubes gravimetrically calibrated and certi-
fied at 30.01 C.
12.3 Operating Parameters.
12.3.1 Low-Molecular Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system used for low molecular
weight compounds are as follows: nitrogen
carrier gas flow rate of 50 cc/min, exhaust
temperature of 110' C. detector temperature
of 105' C, oven temperature of 40' C, hydro-
gen flow rate of 80 cc/min. oxygen flow rate
of 20 cc/min, and sample flow rate between
20 and 80 cc/min.
12.3.2 High-Molecular "Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system for high molecular
weight compounds are the same as in 12.3.1
except: oven temperature of 70' C, and ni-
trogen carrier gas flow of 100 cc/min.
12.4 Analysis Procedure.
12.4.1 Analysis. Aliquots of diluted
sampje are injected simultaneously into
both GC/FPD analyzers for analysis. GC/
FPD-I is used to measure the low-molecular
weight reduced sulfur compounds. The low
molecular weight compounds include hydro-
gen sulfide, methyl mercaptan, and di-
methyl sulfide. GC/FPD-II is used to re-
solve the high-molecular weight compound.
The high-molecular weight compound is di-
methyl dlsulfide.
12.4.1.1 Analysis of Low-Molecular
Weight Sulfur Compounds. The sample
valve is actuated for 3 minutes in which
time an aliquot of diluted sample Is injected
into the stripper column and analytical
column. The valve Is then deactivated for
approximately 12 minutes in which time,
the analytical column continues to be fore-
flushed, the stripper column is backflushed,
and the sample loop Is refilled. Monitor the
responses. The elutlon time for each com-
pound will be determined during calibra-
tion.
12.4.1.2 Analysis of High-Molecular
Weight Sulfur Compounds. The procedure
Is essentially the same as above except that
no stripper column Is needed.
13. Bibliography.
13.1 O'Keeffe. A. E. and G. C. Ortman.
"Primary Standards for Trace Gas Analy-
FEDERAL REGISTER, VOL 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-230
-------
RULES AND REGULATIONS
sis." Analytical Chemical Journal, 38,760 Compounds Related to Kraft Mil) Activi- 13.5 Grimley. K. W., W. S. Smith, and R.
(1966). ties." Presented at the 12th Conference on M. Martin. "The Use of a Dynamic Dilution
13.2 Stevens, R. K., A. E. p'Keeffe, and Methods in Air Pollution and Industrial Hy- System in the Conditioning of Stack Gases
O. C. Ortman. "Absolute Calibration of a giene Studies, University of Southern Call- for Automated Analysis by a Mobile Sam-
Flame Photometric Detector to Volatile fomia, Los Angeles, CA. April 6-8, 1971. pling Van." Presented at the 63rd Annual
Sulfur Compounds at Sub-Part-Per-Million ., „-„„„,,,, n H R s Serenius and A^A Meeting in St. Louis, Mo. June 14-19,
Levels." Environmental Science and Tech- l~* Devonald. R. H.. R. S. Serenius. ana
nology. 3:7 (July. 1969). £• D. Mclntyre. "Evaluation of the Flame u_6 Genera) Reference. standard Meth-
13.3 Mulick, J. D., R. K. Stevens, and R. Photometric Detector for Analysis of Sulfur ^ o{ chemical Analysis Volume III A and
Baumgardner. "An Analytical System De- Compounds." Pulp and Paper Magazine of 3 Instrumental Methods. Sixth Edition.
signed to Measure Multiple Malodorous Canada, 73,3 (March, 1972). Van Nostrand Reinhold Co.
FEDERAL REGISTER, VOL. 4S, NO. V—THURSDAY, FEBRUARY 39, 1978
V-231
-------
U>
to
o
c
JO
o
c
>
Figure 16-1. Probe used for sample gas containing high particulate loadings.
-------
PROBE
STACK
V.lf.t •
TO GC/FPO ANALYZERS
10:1 102:1
FILTER
(GLASS WOOL)
I
to
OJ
U)
3
O
i
o
r
5
FILTER
i~
HEATED
SAMPLE
LINE
PuSi'fi'v't
DISPLACEMENT
- PUMP
(150ec/min)~
PERMEATION
TUBE
CALIBRATION
GAS
-£T
DIAPHRAGM
PUMP
(HEATED)
N -i
3-WAY
fy VALVE
DILUENT AIR
I
DILUTION BOX HEATED
TO 100°C
1350cc/min
I I
FLOWMETER
1
25PSI
CLEAN
DRY AIR
O
i
o
tn
VENT
Figure 16-2.Sampling and dilution apparatus.
-------
SAMPLING VALVE
GC/FPD-I
o
m
)O
O
I
to
10
>
-<
STRIPPER
SAMPLE .
OR
CALIBRATION
GAS
VACUUM
SAMPLING VALVE FOR
GC/FPD-II
VACUUM
SAMPLED
OR
CALIBRATION
GAS
•Es-VENT
FLAME PHOTOMETRIC DETECTOR
EXHAUST
750V
POWER SUPPLY
SEPARATION
COLUMN
H2
OVEN
i
I
5
_
• TO GC/FPO-II
Figure 16-3. Gas chromatographic-flarnc photometric analyzers..
-------
RULES AND REGULATIONS
TO INSTRUMENTS
AND
DILUTION SYSTEM
CONSTANT
TEMPERATURE
BATH
PERMEATION
TUBE
Figure 16-4. Apparatus for field calibration.
FEDERAL REOISTEI, VOl. 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-235
-------
VENT
VENT
PROBE
SAMPLE
LINE
SAMPI E
PUMP
£
M
m
O
o
<
to
o
•<
OBU
2
DILUTION
SYSTEM
o
in
O
_ I
VENT §
I
GAS
CHROMATOGRAPH
Figure 16- 5. Determination of sample line loss.
-------
;OD 11. DETERMINATION Of PAATICULATZ
EMISSIONS FROM STATIONARY SOURCES (IB-
STACK FILTRATION METHOD)
Introduction
Paniculate matter is not an absolute
quantity; rather. It is a function of tempera-
ture and pressure. Therefore, to prevent
variability In paniculate matter emission
regulations and/or associated test methods.
the temperature and pressure at which par-
tlculate matter is to be measured must be
carefully defined. Of the two variables (i.e.,
temperature and pressure), temperature has
the greater effect upon the amount of par-
ticulate matter in an effluent gas stream; In
most stationary source categories, the effect
of pressure appears to be negligible.
In method 5, 250* F Is established as a
nominal reference temperature. Thus.
where Method 5 is specified in an applicable
•ubpart of the standards, paniculate matter
is defined with respect to temperature. In
order to maintain a collection temperature
of 250' F. Method S employs a heated glass
RULES AND REGULATIONS
sample probe and a heated filter holder.
This equipment is somewhat cumbersome
and requires care in its operation. There-
fore, where paniculate matter concentra-
tions (over the normal range of temperature
associated with a specified source category)
are known to be independent of tempera-
ture, it is desirable to eliminate the glass
probe and heating systems, and sample at
•tack temperature.
This method describes an In-stack sam-
pling system arid sampling procedures for
use In such cases. It Is intended to be used
only when specified by an applicable sub-
part of the standards, and only within the
applicable temperature limits (if specified),
or when otherwise approved by the Admin-
istrator.
1. Principle and Applicability.
1.1 Principle. Paniculate matter is with-
drawn isoklnetically from the source and
collected on a glass fiber filter maintained
at stack temperature. The paniculate mass
is determined gravimetrically after removal
of uncombined water.
1.2 Applicability. This method applies to
the determination of paniculate emissions
from stationary sources for determining
compliance with new source performance
standards, only when specifically provided
for in an applicable subpart of the stan-
dards. This method is not applicable to
stacks that contain liquid droplets or are
saturated with water vapor. In addition, this
method shall not be used as written if the
projected cross-sectional area of the probe
extension-filter holder assembly covers
more than S percent of the stack cross-sec-
tional area (see Section 4.1.2).
2. Apparatus.
2.1 Sampling Train. A schematic of the
sampling train used in this method is shown
in Figure 17-1. Construction details for
many, but not all, of the train components
are given In APTD-0581 (Citation 2 in Sec-
tion 7); for changes from the APTD-0581
document and for allowable modifications
to Figure 17-1. consult with the Administra-
tor.
FfDERAl REGISTER, VOL 43, NO. 87—THURSDAY, FURUARY 23, 1978
V-237
-------
TEMPERATURE
SENSOR
IN STACK
FILTER HOLDER
x»y > 1.9cm (0.75in.)
z 5*7.6 cm (3 in.)"
I
to
OJ
00
o
m
»
^
i
v»
s
o
r
p
u
o
c
IMPINGER TRAIN OPTIONAL, MAY Bf REPLACED
BY AN EQUIVALENT CONDEH.SER
TYPES
PITOTTUBE
TEMPERATURE
SENSOR
SAMPLING
NOZZLE
IN STACK
FILTER
HOLDER
REVERSETYPE
PITOTTUBE
THERMOMETER
CHECK
VALVE
ORIFICE MANOMETER
> SUGGESTED (INTERFERENCE FREE) SPACINGS
VACUUM
LINE
>
O
O
AIR-TIGHT
PUMP
ORYGASMETER
Figure 17-1. Participate-Sampling Train, Equipped with In-Stack Filter.
-------
RULES AND REGULATIONS
The operating and maintenance proce-
dures for many of the sampling train com-
ponents are described In AFTD-0576 (Cita-
tion 3 in Section 7). Since correct usage is
important in obtaining valid results, all
users should read the APTD-0576 document
and adopt the operating and maintenance
procedures outlined in it, unless otherwise
specified herein. The sampling train con-
sists of the following components:
2.1.1 Probe Nozzle. Stainless steel (316)
or glass, with sharp, tapered leading edge.
The angle of taper shall be 030* and the
taper shall be on the outside to preserve a
constant internal diameter. The probe
nozzle shall be of the button-hook or elbow
design, unless otherwise specified by the Ad-
ministrator. If made of stainless steel, the
nozzle shall be constructed from seamless
tubing. Other materials of construction may
be used subject to the approval of the Ad-
ministrator.
A range of sizes suitable for Isoklnetic
sampling should be available, e.g., 0.32 to
1.27 cm (V4 to Vi in)—«r larger If higher
volume sampling trains are used—Inside di-
ameter (ID) nozzles in increments of 0.16 cm
(Vie In). Each nozzle shall be calibrated ac-
cording to the procedures outlined In Sec-
tion 5.1.
2.1.2 Filter Holder. The In-stack filter
holder shall be constructed of borosilicate
or quartz glass, or stainless steel; if a gasket
Is used, it shall be made of silicone rubber,
Teflon, or stainless steel. Other holder and
gasket materials may be used subject to the
approval of the Administrator. The filter
holder shall be designed to provide a posi-
tive seal against leakage from the outside or
around the filter.
2.1.3 Probe Extension. Any suitable rigid
probe extension may be used after the filter
holder.
2.1.4 Pitot Tube. Type S. as described in
Section 2.1 of Method 2, or other device ap-
proved by the Administrator; the pilot tube
shall be attached to the probe extension to
allow constant monitoring of the stack gas
velocity (see Figure 17-1). The impact (high
pressure) opening plane of the pilot tube
shall be even with or above the nozzle entry
plane during sampling (see Method 2,
Figure 2-6b). It is recommended: (1) that
the pitot tube have a known baseline coeffi-
cient, determined as outlined in Section 4 of
Method 2; and (2) that this known coeffi-
cient be preserved by placing the pitot tube
In an interference-free arrangement with re-
• ipect to the sampling nozzle, filter holder.
and temperature sensor (see Figure 17-1).
Note that the 1.9 cm (0.75 in) free-space be-
tween the nozzle and pitot tube shown in
Figure 17-1, is based on a 1.3 cm (0.5 in) ID
nozzle. If the sampling train is designed for
sampling at higher flow rates than that de-
scribed in APTD-0581. thus necessitating
the use of larger sized nozzles, the free-
space shall be 1.9 cm (0.75 in) with the larg-
est sized nozzle in place.
Source-sampling assemblies that do not
meet the minimum spacing requirements of
Figure 17-1 (or the equivalent of these re-
quirements, e.g.. Figure 2-7 of Method 2)
may be used; however, the pitot tube coeffi-
cients of such assemblies shall be deter-
mined by calibration, using methods subject
to the approval of the Administrator.
2.1.5 Differential Pressure Gauge. In-
clined manometer or equivalent device
(two), as described in Section 2.2 of Method
2. One manometer shall be used for velocity
head (Ap) readings, and the other, for ori-
fice differential pressure readings.
2.1.6 Condenser. It Is recommended that
the Impinger system described in Method 5
be used to determine the moisture content
of the stack gas. Alternatively, any system
that allows measurement of both the water
condensed and the moisture leaving the con-
denser, each to within 1 ml or 1 g, may be
used. The moisture leaving the condenser
can be measured either by: (1) monitoring
the temperature and pressure at the exit of
the condenser and using Dalton's law of
partial pressures; or (2) passing the sample
gas stream through a silica gel trap with
exit gases kept below 20" C (68* F) and de-
termining the weight gain.
Flexible tubing may be used between the
probe extension and condenser. If means
other than silica gel are used to determine
the amount of moisture leaving the con-
denser, it is recommended that silica gel still
be used between the condenser system and
pump to prevent moisture condensation in
the pump and metering devices and to avoid
the need to make corrections for moisture
In the metered volume.
2.1.7 Metering System. Vacuum gauge,
leak-free pump, thermometers capable of
measuring temperature to within 3* C (5.4*
F), dry gas meter capable of measuring
volume to within 2 percent, and related
equipment, as shown in Figure 17-1. Other
metering systems capable of maintaining
sampling rates within 10 percent of Isoklne-
tic and of determining sample volumes to
within 2 percent may be used, subject to the
approval of the Administrator. When the
metering system is used in conjunction with
a pilot tube, the system shall enable checks
of isokinetic rates.
Sampling trains utilizing metering sys-
tems designed for higher flow rates than
that described in APTD-0581 or APTD-0576
may be used provided that the specifica-
tions of this method are met.
2.1.8 Barometer. Mercury, aneroid, or
other barometer capable of measuring at-
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby na-
tional weather service station, in which case
the station value (which is the absolute
barometric pressure) shall be requested and
an adjustment for elevation differences be-
tween the weather station and sampling
point shall be applied at a rate of minus 2.5
mm Hg (0.1 in. Hg) per 30 m (100 ft) eleva-
tion increase or vice versa for elevation de-
crease.
2.1.9 Gas Density Determination Equip-
ment. Temperature sensor and pressure
gauge, as described in Sections 2.3 and 2.4 of
Method 2, and gas analyzer, if necessary, as
described in Method 3.
The temperature sensor shall be attached
to either the pitot tube or to the probe ex-
tension, In a fixed configuration. If the tem-
perature sensor is attached in the field; the
sensor shall be placed In an Interference-
free arrangement with respect to the Type
S pitot tube openings (as shown in Figure
17-1 or in Figure 2-7 of Method 2). Alterna-
tively, the temperature sensor need not be
attached to either the probe extension or
pitot tube during sampling, provided that a
difference of not more than 1 percent In the
average velocity measurement Is introduced.
This alternative is subject to the approval
of the Administrator.
2.2 Sample Recovery.
2.2.1 Probe Nozzle Brush. Nylon bristle
brush with stainless steel wire handle. The
brush shall be properly sized and shaped to
brush out the probe nozzle.
2.2.2 Wash Bottles—Two. Glass wash
bottles are recommended; polyethylene
wash bottles may be used at the option of
the tester. It is recommended that acetone
not be stored in polyethylene bottles for
longer than a month.
2.2.3 Glass Sample Storage Containers.
Chemically resistant, borosilicate glass bot-
tles, for acetone washes. 500 ml or 1000 ml.
Screw cap liners shall either be rubber-
backed Teflon or shall be constructed so as
to be leak-free and resistant to chemical
attack by acetone. (Narrow mouth glass bot-
tles have been found to be less prone to
leakage.) Alternatively, polyethylene bottles
may be used.
2.2.4 Petri Dishes. For filter samples:
glass or polyethylene, unless otherwise
specified by the Administrator.
2.2.5 Graduated Cylinder and/or Bal-
ance. To measure condensed water to within
1 ml or 1 g. Graduated cylinders shall have
subdivisions no greater than 2 ml. Most lab-
oratory balances are capable of weighing to
the nearest 0.5 g or less. Any of these bal-
ances is suitable for use here and in Section
2.3.4.
2.2.6 Plastic Storage Containers. Air
tight containers to store silica gel.
2.2.7 Funnel and Rubber Policeman. To
aid in transfer of silica gel to container; not
necessary if'silica gel is weighed in the field.
2.2.8 Funnel. Glass or polyethylene, to
aid in sample recovery.
2.3 Analysis.
2.3.1 Glass Weighing Dishes.
2.3.2 Desiccator.
2.3.3 Analytical Balance. To measure to
within 0.1 mg.
2.3.4 Balance. To measure to within 0.5
mg.
2.3.5 Beakers. 250 ml.
2.3.6 Hygrometer. To measure the rela-
tive humidity of the laboratory environ-
ment.
2.3.7 Temperature Gauge. To measure
the temperature of the laboratory environ-
ment.
3. Reagents.
3.1 Sampling.
3.1.1 Filters. The in-stack filters shall be
glass mats or thimble fiber filters, without
organic binders, and shall exhibit at least
99.95 percent efficiency (00.05 percent pene-
tration) on 0.3 micron dioctyl phthalate
smoke particles. The filter efficiency tests
shall be conducted in accordance with
ASTM standard method D 2986-71. Test
data from the supplier's quality control pro-
gram are sufficient for this purpose.
3.1.2 Silica Gel. Indicating type, 6- to 16-
mesh. If previously used, dry at 175* C (350'
F) for 2 hours. New silica gel may be used as
received. Alternatively, other types of desic-
cants (equivalent or better) may be used.
subject to the approval of the Administra-
tor.
3.1.3 Crushed Ice.
3.1.4 Stopcock Grease. Acetone-insoluble.
heat-stable silicone grease. This is not nec-
essary If screw-on connectors with Teflon
sleeves, or similar, are used. Alternatively.
other types of stopcock grease may be used.
subject to the approval of the Administra-
tor.
3.2 Sample Recovery. Acetone, reagent
grade, 00.001 percent residue, in glass bot-
tles. Acetone from metal containers general-
ly has a high residue blank and should not
be used. Sometimes, suppliers transfer ac-
etone to glass bottles from metal containers.
Thus, acetone blanks shall be run prior to
field use and only acetone with low blank
FEDERAL REGISTER, VOL 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-239
-------
IULES AND REGULATIONS
values (00.001 percent) shall be used. In no
case shall a blank value of greater than
0.001 percent of the weight of acetone used
be subtracted from the sample weight.
3.3 Analysis.
3.3.1 Acetone. Same as 3.2.
3.3.2 Desiccant. Anhydrous calcium sul-
fate, indicating type. Alternatively, other
types of desiccants may be used, subject to
the approval of the Administrator.
4. Procedure.
4.1 Sampling. The complexity of this
method is such that. In order to obtain reli-
able results, testers should be trained and
experienced with the test procedures.
4.1.1 Pretest Preparation. All compo-
nents shall be maintained and calibrated ac-
cording to the procedure described in
APTD-0576. unless otherwise specified
herein.
Weigh several 200 to 300 g portions ofj
silica gel in air-tight containers to the near-
est 0.5 g. Record the total weight of the
silica gel plus container, on each container.
As an alternative, the silica gel need not be
preweighed, but may be weighed directly in
its impinger or sampling holder just prior to
train assembly.
Check filters visually against light for ir-
regularities and flaws or plnhole leaks.
Label filters of the proper size on the back
side near the edge using numbering ma-
chine ink. As an alternative, label the ship-
ping containers (glass or plastic petri dishes)
and keep the filters in these containers at
all times except during sampling and weigh-
ing.
Desiccate the filters at 20±5.6' C <68±10-
F) and ambient pressure for at least 24
hours and weigh at Intervals of at least 6
hours to a constant weight, i.e.. 00.5 mg
change from previous weighing: record re-
sults to the nearest 0.1 mg. During each
weighing the filter must not be exposed to
the laboratory atmosphere for • period
greater than 2 minutes and a relative hu-
midity above 50 percent. Alternatively
(unless otherwise specified by the Adminis-
trator), the filters may be oven dried at 105*
C (220* F) for 2 to 3 hours, desiccated for 2
hours, and weighed. Procedures other than
those described, which account for relative
humidity effects, may be used, subject to
the approval of the Administrator.
4.1.2 Preliminary Determinations. Select
the sampling site and the minimum number
of sampling points according to Method 1 or
as specified by the Administrator. Make a
projected-area model of the probe exten-
sion-filter holder assembly, with the pilot
tube face openings positioned along the cen-
terline of the stack, as shown in Figure 17-2.
Calculate the estimated cross-section block-
age, as shown in Figure 17-2. If the blockage
exceeds 5 percent of the duct cross sectional
area, the tester has the following options:
(Da suitable out-of-stack filtration method
may be used instead of in-stack filtration; or
(2) a special in-stack arrangement, in which
the sampling and velocity measurement
sites are separate, may be used; for details
concerning this approach, consult with the
Administrator (see also Citation 10 in Sec-
tion 7). Determine the stack pressure, tem-
perature, and the range of velocity heads
using Method 2; it is recommended that a
leak-check of the pilot lines (see Method 2,
Section 3.1) be performed. Determine the
moisture* content using Approximation
Method 4 or its alternatives for the purpose
of making isokinetic sampling rate settings.
Determine the stack gas dry molecular
weight, as described In Method 2, Section
3.6; if Integrated Method 3 sampling is used
for molecular weight determination, the In-
tegrated bag sample shall be taken simulta-
neously with, and for the same total length
of time as, the particular sample run.
FEDERAL REGISTER, VOL 43, NO. 37—THURSDAY, FEUUARY », 1978
V-240
-------
RULES AND REGULATIONS
STACK
WALL
IN STACK FILTER
PROBE EXTENSION
ASSEMBLY
ESTIMATED
BLOCKAGE
fsHADED AREA]
|_ DUCT AREA J
X 100
Figure 17-2. Projected-area model of cross-section blockage (approximate average for
a sample traverse) caused by an in-stack filter holder-probe extension assembly.
FEDERAL IfOISHI, VOL. 43, NO. V—THURSDAY, KMUARY 2S, 1971
V-241
-------
RULES AND REGULATIONS
Select a nozzle size based on the range of
velocity heads, such that It Is not necessary
to change the nozzle size In order to main-
tain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure
that the proper differential pressure gauge
is chosen for the range of velocity heads en-
countered (see Section 2.2 of Method 2).
Select a probe extension length such that
all traverse points can be sampled. For large
stacks, consider sampling from opposite
sides of the stack to reduce the length of
probes.
Select a total sampling time greater than
or equal to the minimum total sampling
time specified In the test procedures for the
specific industry such that (1) the sampling
time per point is not less than 2 minutes (or
some greater time interval If specified by
the Administrator), and (2) the sample
volume taken (corrected to standard condi-
tions) will exceed the required minimum
total gas sample volume. The latter is based
on an approximate average sampling rate.
It is recommended that the number of
minutes sampled at each point be an integer
or an integer plus one-half minute, in order
to avoid timekeeping errors.
In some circumstances, e.g., batch cycles.
It may be necessary to sample for shorter
times at the traverse points and to obtain
smaller gas sample volumes. In these cases,
the Administrator's approval must first be
obtained.
4.1.3 Preparation of Collection Train.
During preparation and assembly of the
sampling train, keep all openings where con-
tamination can occur covered until Just
prior to assembly or until sampling is about
to begin.
If impingers are used to condense stack
gas moisture, prepare them as follows: place
100 ml of water in each of the first two Im-
pingers, leave the third Impinger empty.
and transfer approximately 200 to 300 g of
preweighed silica gel from its container to
the fourth impinger. More silica gel may be
used, but care should be taken to ensure
that it is not entrained and carried out from
the impinger during sampling. Place the
container in a clean place for later use in
the sample recovery. Alternatively, the
weight of the silica gel plus impinger may
be determined to the nearest 0.5 g and re-
corded.
If some means other than impingers Is
used to condense moisture, prepare the con-
denser (and, if appropriate, silica gel for
condenser outlet) for use.
Using a tweezer or clean disposable surgi-
cal gloves, place a labeled (identified) and
weighed filter In the filter holder. Be sure
that the filter Is properly centered and the
gasket properly placed so as not to allow the
sample gas stream to circumvent the filter.
Check filter for tears after assembly Is com-
pleted. Mark the probe extension with heat
resistant tape or by some other method to
denote the proper distance Into the stack or
duct for each sampling point.
Assemble the train as in Figure 17-1, using
a very light coat of sllicone grease on all
ground glass joints and greasing only the
outer portion (see APTD-0576) to avoid pos-
sibility of contamination by the silicone
grease. Place crushed ice around the im-
pingers.
4.1.4 Leak Check Procedures.
4.1.4.1 Pretest Leak-Check. A pretest
leak-check is recommended, but not re-
quired. If the tester opts to conduct the pre-
test leak-check, the following procedure
shall be used.
After the sampling train has been assem-
bled, plug the Inlet to the probe nozzle with
a material that will be able to withstand the
stack temperature. Insert the filter holder
into the stack and wait approximately 5
minutes (or longer, if necessary) to allow
the system to come to equilibrium with the
temperature of the stack gas stream. Turn
on the pump and draw a vacuum of at least
380 .mm Hg (15 in. Hg); note that a lower
vacuum may be used, provided that it is not
exceeded during the test. Determine the
leakage rate. A leakage rate in excess of 4
percent of the average sampling rate or
0.00057 m'/min. (0.02 cfm), whichever Is
less, is unacceptable.
The following leak-check Instructions for
the sampling train described in APTD-0576
and APTD-0581 may be helpful. Start the
pump with by-pass valve fully open and
coarse adjust valve completely closed. Par-
tially open the coarse adjust valve and
slowly .close the by-pass valve until the de-
sired vacuum Is reached. Do not reverse di-
rection of by-pass valve. If the desired
vacuum is exceeded, either leak-check at
this higher vacuum or end the leak-check as
shown below and start over.
When the leak-check is completed, first
slowly remove the plug from the inlet to the
probe nozzle and Immediately turn off the
vacuum pump. This prevents water from
being forced backward and keeps silica gel
from being entrained backward.
4.1.4.2 Leak-Checks During Sample Run.
If, during the sampling run, a component
(e.g., filter assembly or impinger) change be-
comes necessary, a leak-check shall be con-
ducted immediately before the change is
made. The leak-check shall be done accord-
Ing to the procedure outlined In Section
4.1.4.1 above, except that it shall be done at
a vacuum equal to or greater than the maxi-
mum value recorded up to that point in the
test. If the leakage rate is found to be no
greater than 0.00057 m'/min (0.02 cfm) or 4
percent of the average sampling rate
(whichever Is less), the results are accept-
able, and no correction will need to be ap-
plied to the total volume of dry gas metered;
if, however, a higher leakage rate is ob-
tained, the tester shall either record the
leakage rate and plan to -correct the sample
volume as shown in Section 6.3 of this
method, or shall void the sampling run.
Immediately after component changes,
leak-checks are optional; If such leak-checks
are done, the procedure outlined in Section
4.1.4.1 above shall be used.
4.1.4.3 Post-Test Leak-Check. A leak-
check is mandatory at the conclusion of
each sampling run. The leak-check shall be
done in accordance with the procedures out-
lined in Section 4.1.4.1, except that it shall
be conducted at a vacuum equal to or great-
er than the maximum value reached during
the sampling run. If the leakage rate is
found to be no greater than 0.00057 m'/min
(0.02 cfm) or 4 percent of the average sam-
pling rate (whichever is less), the results are
acceptable, and no correction need be ap-
plied to the total volume of dry gas metered.
If, however, a higher leakage rate is ob-
tained, the tester shall either record the
leakage rate and correct the sample volume
as shown in Section 6.3 of this method, or
shall void the sampling run.
4.1.5 Paniculate Train Operation.
During the sampling run, maintain a sam-
pling rate such that sampling is within 10
percent of true isokinetic, unless otherwise
specified by the Administrator.
For each run, record the data required on
the example data sheet shown in Figure 17-
3. Be sure to record the initial dry gas meter
reading. Record the dry gas meter readings
at the beginning and end of each sampling
time increment, when changes in flow rates
are made, before and after each leak check,
and when sampling is halted. Take other
readings required by Figure 17-3 at least
once at each sample point during each time
increment and additional readings when sig-
nificant changes (20 percent variation in ve-
locity head readings) necessitate additional
adjustments in flow rate. Level and zero the
manometer. Because the manometer level
and zero may drift due to vibrations and
temperature changes, make periodic checks
during the traverse.
FEDERAL REGISTER, VOL 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-242
-------
ID
m
O
I
to
>t*
UJ
o
c
•<
c
PLANT
LOCATION.
OPERATOR.
DATE
RUN NO
SAMPLE BOX NO..
METER BOX NO. _
METERAH<5>
C FACTOR
PITOT TUBE COEFFICIENT, Cp.
BAROMETRIC PRESSURE.
ASSUMED MOISTURE, %_
PROBE EXTENSION LENGTH. m(ft.)_
NOZZLE IDENTIFICATION NO
AVERAGE CALIBRATED NOZZLE DIAMETER cm (in.).
FILTER NO ^__
LEAK RATE, m3/min,(dm)
STATIC PRESSURE, mm Hg (in. Hg).
SCHEMATIC OF STACK CROSS SECTION
TRAVERSE POINT
NUMBER
TOTAL
SAMPLING
TIME
(01, min.
AVERAGE
VACUUM
mm Hg
(in. Hg)
.
STACK
TEMPERATURE
ITS).
°C (*F)
VELOCITY
HEAD
(A PS),
mmHjO
(in. H20)
PRESSURE
DIFFERENTIAL
ACROSS
ORIFICE
METER.
mm HjO
(in. HjO)
GAS SAMPLE
VOLUME,
m3 (ft3)
GAS SAMPLE TEMPERATURE
AT DRY GAS METER
INLET,
°C (°F)
/
Avq
OUTLET,
°C (°F)
Avg
Avg
TEMPERATURE
OF GAS
LEAVING
CONDENSER OR
LAST IMPINGER,
°C (°F)
m
O
Figure 17-3. Paniculate field data.
-------
RULES AND REGULATIONS
Clean the portholes prior to the test run
> minimize the chance of sampling the de-
osited material. To begin sampling, remove
tie nozzle cap and verify that the pilot tube
nd probe extension are properly posi-
loned. Position the nozzle at the first tra-
'erse point with the tip pointing directly
nto the gas stream. Immediately start the
pump and adjust the flow to teokinetic con-
ditions. Nomographs are available, which
aid in the rapid adjustment to the isokinetic
sampling rate without excessive computa-
tions. These nomographs are designed for
use when the Type S pilot tube coefficienl
is 0.85 ±0.02, and the stack gas equivalent
density (dry molecular weight) Is equal to
29 ±4. APTD-0576 details Ihe procedure for
using the nomographs. If Cp and M« are out-
side the above stated ranges, do not use the
nomographs unless appropriate steps (see
Citation 7 in Section 7) are taken to com-
pensate for Ihe deviations.
When the stack is under significant nega-
tive pressure (height of impinger stem),
take care to close the coarse adjust valve
before inserting the probe extension assem-
bly into the stack to prevent water from
being forced backward. If necessary, the
pump may be turned on with the coarse
adjust valve closed.
When the probe is in position, block off
the openings around the probe and porthole
to prevent unrepresentative dilution of the
gas stream.
Traverse the stack cross section, as re-
quired by Method 1 or as specified by the
Administrator, being careful not to bump
the probe nozzle into the stack walls when
sampling near the walls or when removing
or inserting the probe extension through
the portholes, to minimize chance of ex-
tracting deposited material.
During the test run. take appropriate
steps (e.g., adding crushed ice to the im-
pinger ice bath) to maintain a temperature
of less lhan 20° C (68' F) at the condenser
outlet; this will prevent excessive moisture
losses. Also, periodically check the level and
zero of the manometer.
If the pressure drop across the filter be-
comes too high, making isokinetic sampling
difficult to maintain, the filter may be re-
placed in the midst of a sample run. It Is
recommended that another complete filler
holder assembly be used rather than at-
tempting to change the filter Itself. Before a
new filter holder is installed, conduct a leak
check, as outlined in Section 4.1.4.2. The
total particu late weight shall include the
summation of all filter assembly catches.
A single train shall be used for the entire
sample run, '••uep' In cases where simulta-
neous sampling is required in two or more
separate ducts or at two or more different
locations within the same duct, or, in cases
where equipment failure necessitates a
change of trains. In all other situations, the
use of two or more trains will be subject to
the approval of the Administrator. Note
lhat when two or more trains are used, a
separate a^-.'ysis of the collected particu-
late from each train shall be performed,
unless identical nozzle sizes were used on all
trains, in which case the participate catches
from the individual trains may be combined
and a single analysis performed.
At the end of the sample run, turn off the
pump, remove the probe extension assembly
from the stack, and record the final dry gas
meter reading. Perform a leak-check, as out-
lined in Section 4.1.4.3. Also, leak-check the
pilot lines as described in Section 3.1 of
Method 2; the lines must pass this leak-
check, in order to validate the velocity head
data.
4.1.6 Calculation of Percent Isokinetic.
Calculate percent isokinetic (see Section
6.11) to determine whether another lest run
should be made. If there is difficulty in
maintaining isokinetic rates due to source
conditions, consult with Ihe Administrator
for possible variance on the isokinetic rates.
4.2 Sample Recovery. Proper cleanup
procedure begins as soon as the probe ex-
tension assembly is removed from the stack
at the end of the sampling period. Allow the
assembly to cool.
When the assembly can be safely handled,
wipe off all external parliculale matter near
the tip of the probe nozzle and place a cap
over It to prevent losing or gaining particu-
lale matter. 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, forcing condenser water back-
ward.
Before moving th« sample train to the
cleanup site, disconnect the filter holder-
probe nozzle assembly from the probe ex-
tension: cap the open inlet of the probe ex-
tension. Be careful not to lose any conden-
sa'te. If present. Remove the umbilical cord
from the condenser outlet and cap the
outlet. If a flexible line Is used between the
first impinger (or condenser) and Ihe probe
extension, disconnect Ihe line al the probe
extension and let any condensed water or
liquid drain into the Implngers or condens-
er. Disconnect Ihe probe extension from the
condenser; cap the probe extension outlet.
After wiping off Ihe silicone grease, cap off
the condenser inlet. Ground glass stoppers,
plastic caps, or serum caps (whichever are
appropriate) may be used to close these
openings.
Transfer both the filter holder-probe
nozzle assembly and the condenser to the
cleanup area. This area should be clean and
protected from the wind so that the chances
of contaminating or losing the sample will
be minimized.
Save a portion of the acetone used for
cleanup as a blank. Take 200 ml of this ac-
etone directly from Ihe wash bottle being
used and place it In a glass sample container
labeled "acetone blank."
- Inspect the train prior to and during dis-
assembly and note any abnormal conditions.
Treat the samples as follows:
Container No. 1. Carefully remove the
filter from the filter holder and place it in
its identified pelri dish container. Use a pair
of tweezers and/or clean disposable surgical
gloves to handle the filter. If it is necessary
to fold the filter, do so such thai Ihe parlic-
ulale cake is inside Ihe fold. Carefully trans-
fer to the pelri dish any paniculate mailer
and/or filler fibers which adhere to the
filter holder gaskel, by using a dry Nylon
bristle brush and/or a sharp-edged blade.
Seal Ihe container.
Container No. 2. Taking care to see that
dust on the outside of the probe nozzle or
other exterior surfaces does not get into the
sample, quantitatively recover particulate
matter or any condensate from the probe
nozzle, fitting, and front half of the filter
holder by washing Ihese components wilh
acetone and placing the wash in a glass con-
tainer. Distilled water may be used instead
of acetone when approved by the Adminis-
trator and shall be used when specified by
the Administrator; in these cases, save a
water blank and follow Administrator's di-
rections on analysis. Perform Ihe acetone
rinses as follows:
Carefully remove the probe nozzle and
clean the inside surface by rinsing with ac-j
etone from a wash bottle and brushing with'
a Nylon bristle brush. Brush unlil acetone
rinse shows no visible particles, after which
make a final rinse of the inside surface with
acetone.
Brush and rinse with acetone the inside
parts of the fitting in a similar way until no
visible particles remain. A funnel (glass or
polyethylene) may be used to aid in trans-
ferring liquid washes to the container. Rinse
the brush wilh acetone and quantitatively
collect these washings in the sample con-
tainer. Between sampling runs, keep
brushes clean and protected from contami-
nation.
After ensuring that all Joints are wiped
clean of silicone grease (if applicable), clean
the Inside of the front half of the filter
holder by rubbing the surfaces with a Nylon
bristle brush and rinsing with acetone.
Rinse each surface three times or more if
needed to remove visible particulate. Make
final rinse of the brush and filter holder.
After all acetone washings and particulate
matter are collected In the sample contain-
er, tighten the lid on the sample container
so that acetone will not leak out when it is
shipped to the laboratory. Mark the height
of the fluid level to determine whether or
not leakage occurred during transport.
Label the container to clearly Identify its
contents.
Container No. 3. if silica gel is used in the
condenser system for mositure content de-
termination, note Ihe color of Ihe gel to de-
termine if it has been completely spent;
make a notation of its condition. Transfer
the silica gel back to its original container
and seal. A funnel may make it easier to
pour the silica gel without spilling, and a
rubber policeman may be used as an aid in
removing the silica gel. It is not necessary to
remove the small amount of dust particles
that may adhere to the walls and are diffi-
cult 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, follow the procedure for Container
No. 3 under "Analysis."
Condenser Water. Treat the condenser or
Impinger water as follows: make a notation
of any color or film in the liquid catch. Mea-
sure the liquid volume to within ±1 ml by
using a graduated cylinder or. If a balance is
available, determine the liquid weight to
within ±0.5 g. Record the total volume or
weight of liquid present. This information is
required to calculate the moislure content
of the effluent gas. Discard the liquid after
measuring and recording the volume or
weight.
4.3 Analysis. Record the data required on
the example sheet shown in Figure 17-4.
Handle each sample container as follows:
Container No. 1. Leave the contents in the
shipping container or transfer the filler and
any loose particulate from the sample con-
tainer to a tared glass weighing dish. Desic-
cate for 24 hours In a desiccator containing
anhydrous calcium sulfate. Weigh to a con-
stant weight and report the results to the
nearest 0.1 mg. For purposes of this Section,
4.3, the term "constant weight" means a dif-
ference of no more than 0.5 mg or 1 percent
of total weight less tare weight, whichever is
greater, between two consecutive weighings,
with no less than 6 hours of desiccation
time between weighings.
Alternatively, the sample may be oven
dried at the average slack temperature or
FEDERAL REGISTER, VOL. 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-244
-------
RULES AND REGULATIONS
105' C (220* F). whichever is less, for 2 to 3 tied by the Administrator. The tester may whichever is less, for 2 to 3 hours, weigh the
hours, cooled in the desiccator, and weighed also opt to oven dry the sample at the aver- sample, and use this weight as a final
to a constant weight, unless otherwise speci- age stack temperature or 105* C (220* F), weight.
Plant.
Date.
Run No..
Fitter No.
Amount liquid lost during transport
Acetone blank volume, ml
Acetone wash volume, ml_;
Acetone black concentration, mg/mg (equation 17-4)
Acetone wash blank, mg (equation 17-5)
CONTAINER
NUMBER
1
2
TOTAL
WEIGHT OF PARTICIPATE COLLECTED.
mg
FINAL WEIGHT
^xd
TARE WEIGHT
^XCT
Less acetone blank
Weight of part icu late matter
WEIGHT GAIN
FINAL
INITIAL
LIQUID COLLECTED
TOTAL VOLUME COLLECTED
VOLUME OF LIQUID
WATER COLLECTED
IMPINGER
VOLUME.
ml
SILICA GEL
.WEIGHT.
9
9' ml
* CONVERT WEIGHT OF WATER TO VOLUME BY DIVIDING TOTAL WEIGHT
INCREASE BY DENSITY OF WATER (1g/ml).
INCREASE, g : VOLUME WAJER m)
1 g/ml
Figure 17-4. Analytical data.
FEDEKAl tt-G-STCI, VOL 43, NO. V—THIMSDAY, FCBRUAttr 23, 1978
V-245
-------
RULES AND REGULATIONS
Container No. 2. Note the level of liquid in
the container and confirm on the analysis
sheet whether or -not leakage occurred
during transport. If a noticeable amount of
leakage has occurred, either void the sample
or use methods, subject to the approval of
the Administrator, to correct the final re-
sults. Measure the liquid in this container
either volumetrically to ±1 ml or gravtme-
trically to ±0.5 g. Transfer the contents to a
tared 250-ml beaker and evaporate to dry-
ness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a con-
stant weight. Report the results to the near-
est 0.1 mg.
Container No. 3. This step may be con-
ducted in the field. Weigh the spent silica
gel (or silica gel plus impinger) to the near-
est 0.5 g using a balance.
"Acetone Blank" Container. Measure ac-
etone in this container either volumetrically
or gravimetrically. Transfer the acetone to a
tared 250-ml beaker and evaporate to dry-
ness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a con-
stant weight. Report the results to the near-
est 0.1 mg.
NOTE.—At the option of the tester, the
contents of Container No. 2 as well as the
acetone blank container may be evaporated
at temperatures higher than ambient. If
evaporation is done at an elevated tempera-
ture, the temperature must be below the
boiling point of the solvent; also, to prevent
"bumping," the evaporation process must be
closely supervised, and the contents of the
beaker must be swirled occasionally to
maintain an even temperature. Use extreme
care, as acetone is highly flammable and
has a low flash point.
5. Calibration. Maintain a laboratory log
of all calibrations.
5.1 Probe Nozzle. Probe nozzles shall be
calibrated before their initial use in the
field. Using a micrometer, measure the
inside diameter of the nozzle to the nearest
0.025 mm (0.001 In.). Make three separate
measurements using different diameters
each time, and obtain the average of the
measurements. The difference between the
high and low numbers shall not exceed 0.1
mm HO.004 In.). When nozzles become
nicked, dented, or corroded, they shall be
reshaped, sharpened, and recalibrated
before use. Each nozzle shall be permanent-
ly and uniquely identified.
5.2 Pilot Tube. If the pilot tube is placed
In an interference-free arrangement with re-
spect to the other probe assembly compo-
nents, its baseline (isolated tube) coefficient
shall be determined as outlined in Section 4
of Method 2. If the probe assembly is not in-
terference-free, the pilot tube assembly co-
efficient shall be determined by calibration,
using methods subjecl to the approval of
the Adminislralor.
5.3 Metering System. Before its Initial
use in the field, the metering system shall
be calibrated according to the procedure
outlined in APTD-0576. Instead of physical-
ly adjusting the dry gas meter dial readings
to correspond to the wet test meter read-
ings, calibration factors may be used to
mathematically correct the gas meter dial
readings to the proper values.
Before calibrating the metering system. It
Is suggested thai a leak-check be conducted.
For metering systems having diaphragm
pumps, the normal leak-check procedure
will not detect leakages within the pump.
For these cases the following leak-check
procedure is suggested: make a 10-minute
calibration run al 0.00057 m'/min (0.02
cfm); al the end of the run, take the differ-
ence of the measured wet test meter and
dry gas meter volumes; divide the difference
by 10, to gel the leak rate. The leak rate
should not exceed 0.00057 m'/min (0.02
cfm).
After each field use, the calibration of the
metering system shall be checked by per-
forming three calibration runs at a single,
intermediate orifice selling (based on Ihe
previous field lest), with the vacuum sel al
the maximum value reached during the tesl
series. To adjust the vacuum, insert a valve
between the wet lest meter and the inlet of
the metering syslem. Calculate Ihe average
value of the calibration factor. If Ihe cali-
bration has changed by more than 5 per-
cent, recalibrate the meler over Ihe full
range of orifice sellings, as outlined in
APTD-0576.
Alternative procedures, e.g., using the ori-
fice meter coefficients, may be used, subjecl
to the approval of the Administrator.
NOTE.—If the dry gas meter coefficient
values obtained before and after a test
series differ by more than 5 percent, the
test series shall either be voided, or calcula-
tions for the test series shall be performed
using whichever meter coefficient value
(i.e., before or after) gives the lower value of
total sample volume.
5.4 Temperature Gauges. Use the proce-
dure in Section 4.3 of Method 2 to calibrate
in-slack temperature gauges. Dial thermom-
eters, such as are used for Ihe dry gas meter
and condenser outlet, shall be calibrated
against mercury-in-glass Ihermomelers.
5.5 Leak Check of Metering System
Shown in Figure 17-1. Thai portion of Ihe
sampling Irain from Ihe pump lo Ihe orifice
meter should be leak checked prior to initial
use and after each shipment. Leakage after
the pump will result in less volume being re-
corded than Is actually sampled. The follow-
ing procedure is suggested (see Figure 17-5).
Close the main valve on Ihe meler box.
Insert a one-hole rubber stopper with
rubber tubing atlached into Ihe orifice ex-
haust pipe. Disconnect and vent the low side
of the orifice manometer. Close off the low
side orifice tap. Pressurize the system to 13
to 18 cm (5 to 7 in.) water column by blow-
ing into the rubber lubing. Pinch off the
tubing and observe the manometer for one
minute. A loss of pressure on the mano-
meter indicates a leak in Ihe meler box;
leaks, if presenl. must be corrected.
FEDERAL REGISTER, VOL. 43, NO. 37—THURSDAY, FEBRUARY 23, 1978
V-246
-------
I
N)
o
M
i
o
p
o
RUBBER
TUBING
BLOW INTO TUBING
UNTIL MANOMETER
READS 5 TO 7 INCHES
WATER COLUMN
RUBBER
STOPPER
ORIFICE
BY-PASS VALVE
VACUUM
GAUGE
ORIFICE
MANOMETER
O
ID
m
O
O
v>
Figure 17-5. Leak check of meter box.
-------
RULES AND REGULATIONS
5.6 Barometer. Calibrate against a mer-
cury barometer.
6. Calculations. Carry out calculations, re-
taining at least one extra decimal figure
beyond that of the acquired data. Round off
figures after the final calculation. Other
forms of the equations may be used as long
as they give equivalent results.
6.1 Nomenclature.
A,=Cross-sectional area of nozzle, m' (ft*).
Bi.=Wuit:r t'apa* \n the gas stream, propor-
tion by volume.
C.=Acetoiie blank rescue concentration,
mg/g.
c.=Concentration of participate matter in
stack gas. dry basis, corm.'.»d to stan-
dard condition^ g/dscra (g/d&f >.
I = Percent of isofcinetic sampling
L.-=Maximum ace...table leakage rate for
either a pretest lea* "heck or for a leak
. check following a compc^,,^ change;
.(equal to 0.00057 m'/mir {0 02 cfm) or 4
'percent1 of the averag > sampllng rate,
whichever is less. .
L,=Individual leakage rate observed during
the leak check condu.^ p_,or ^ the
"I1*" component chame (| = i, 3. 3 . . . Yl>.
mVC?-1" = Volume of water vapor in the gas
sample, corrected to standard condi-
tions, scm (scf). .'"
v.=Stack gas velocity, calculated by Method
2, Equation 2-9. using data obtained
from Method 17, m/sec (ft/sec).
W. = Weight of residue in acetone wash. mg.
Y = Dry gas meter calibration coefficient.
AH = Average pressure differential across
the orifice meter (see Figure 17-3), mm
H,O (in. H,O).
p. = Density of acetone, mg/ml (see label on
bottle).
= , = Density of water, 0.9982 g/ml (0.002201
Ib/ml).
9 = Total sampling time, min.
«i=Sampling time interval, from the begin-
ning of a run until the first component
change, min.
», = Sampling time Interval, between two
successive component changes, begin-
ning with the interval between the first
and second changes, min.
»B=Sampling time Interval, from the final
(nth) component change, until the end of
the sampling run. min.
13.6=Specific gravity of mercury.
60=Sec/mln.
100=Con version to percent.
6.2 Average dry gas meter temperature
and average orifice pressure drop. See data
sheet (Figure 17-3).
6.3 Dry Gas Volume. Correct the sample
volume measured by the dry gas meter to
standard conditions (20* C. 760 mm Hg or
68' F. 29.92 in. Hg) by using Equation 17-1.
6.6 Acetone Blank Concentration.
Vstd) • y(
-u
?•}
Y Pbar
Pbar + TT6
Pstd
+ (AH/13.6)
Equation 17-1
where:
K, =0.3858' K/mm Hg for metric units;
17.64' R/in. Hg for English units.
NOTE.— Equation 17-1 can be used as writ-
ten unless the leakage rate observed during
any of the mandatory leak checks (i.e., the
post-test leak check or leak checks conduct-
ed prior to component changes) exceeds L..
If Lp or L, exceeds L.. Equation 17-1 must be
modified as follows:
(a) Case I. No component changes made
during sampling run. In this case, replace
Vm in Equation 17-1 with the expression:
(b) Case II. One or more component
changes made during the sampling run. In
this case, replace V0 in Equation 17-1 by the
expression:
La) 91 -
1-2
* La) ei
a '
-La>
V
and substitute only for those leakage rates
(I* nr V which exceed L..
6.4 Volume of water vapor.
where:
K,=0.001333 mVm! for metric units; 0.04707
ft'/ml for English units.
6.5 Moisture Content.
V.
B
w(std)
ws Vm(std) + Vw(std)
Equation 17-4
6.7 Acetone Wash Blank.
W.=C.V»p.
Equation 17-5
6.8 Total Particulate Weight. Determine
the total particulate catch from the sum of
the weights obtained from containers 1 and
2 less the acetone blank (see Figure 17-4).
NOTE.—Refer to Section 4.1.5 to assist In
calculation of results involving two or more
filter assemblies or two or more sampling
trains.
6.9 Particulate Concentration.
c.=(0.001 g/mg) (m./V.ta,,))
Equation 17-6
6.10 Conversion Factors:
Prom
To
Multiply by
scf
g/lf
g/ff
g/ff
m'
gr/ff
lb/fp
g/m'.
0.02832
15.43
2.205x10-'
35.31
6.11 Isokinetic Variation.
6.11.1 Calculation from Raw Data.
'KV
3lc
V C'b.P*«H/13.6)|
Equation 17-7
where:
K,=0.003454 mm Hg-m'/ml-'K for metric
units; 0.002669 in. Hg-ft'/ml-'R for Eng-
lish units.
6.11.2 Calculation
Values.
from Intermediate
Vm(std)pstd 100_
_
Tstdws e An Ps60
= K.
_Ts Vm(std)
vs fln
Equation 17-2 where:
Equation 17-8
Equation 17-3
K. = 4.320 for metric units; 0.09450 for Eng-
lish units.
6.12 Acceptable Results. If 90 percent
010110 percent, the results are acceptable. If
the results are low In comparison to the
standard and I is beyond the acceptable
range, or, if I is less than 90 percent, the Ad-
ministrator may opt to accept the results.
Use Citation 4 in Section 7 to make Judg-
ments. Otherwise, reject the results and
repeat the test.
7. Bibliography.
FEDERAL REGISTER, VOL 43, NO. 37—THURSDAY, FEMUARY 33, 1978
V-248
-------
1. Addendum to Specifications for Inciner-
ator Testing at Federal Facilities. PHS.
NCAPC. December 6, 1967.
2. Martin, Robert M.. Construction Details
of Isokinetic Source-Sampling Equipment.
Environmental Protection Agency. Re-
search Triangle Park. N.C. APTD-0581.
April, 1971.
3. Rom, Jerome J., Maintenance. Calibra-
tion, and Operation of Isokinetic Source-
Sampling Equipment. Environmental Pro-
tection Agency. Research Triangle Park,
N.C. APTD-0576. March, 1972.
4. Smith, W. S.. R. T. Shigehara, and W.
F. Todd. A Method of Interpreting Stack
Sampling Data. Paper Presented at the 63rd
Annual Meeting of the Air Pollution Con-
trol Association. St. Louis, Mo. June 14-19.
1970.
5. Smith, W. S.. et al., Stack Gas Sampling
Improved and Simplified with New Equip-
ment. APCA Paper No. 67-119. 1967.
8. Specifications for Incinerator Testing at
Federal Facilities. PHS. NCAPC. 1967.
7. Shigehara, R. T., Adjustments in the
EPA Nomograph for Different Pitot Tube
Coefficients and Dry Molecular Weights.
Stack Sampling News 2:4-11. October. 1974.
8. Vollaro, R. F., A Survey of Commercial-
ly Available Instrumentation for the Mea-
surement of Low-Range Gas Velocities. U.S.
Environmental Protection Agency, Emission
Measurement Branch. Research Triangle
Park, N.C. November. 1976 (unpublished
paper).
9. Annual Book of ASTM Standards. Part
36. Gaseous Fuels; Coal and Coke; Atmo-
spheric Analysis. American Society for Test-
ing and Materials. Philadelphia, Pa. 1974.
PP. 617-622.
10. Vollaro. R. P.. Recommended Proce-
dure for Sample Traverses in Ducts Smaller
than 12 Inches In Diameter G-..S. -Environ-
mental Protection Ar^ncy, Emission Mea-
surement Branch. .Research Triangle Park,
N.C. November. )<*76.
tFR Doc. 78-^795 Filed 2-22-78; 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. 37
THURSDAY, FEBRUARY 23, 1978
RULES AND REGULATIONS
83
THIe 40—Protection of Environment
CTRL 848-2]
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
PART 6O—STANDARDS OF PERFOR-
MANCE FOR NEW STATIONARY
SOURCES
PART 61—NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS
Revision of Authority Citations
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action amends the
authority citlations for Standards of
Performance for New Stationary
Sources and National Emission Stan-
tards for Hazardous Pollutants. The
amendment adopts the ^designation
of classification numbers as changed
in the 1977 amendments to the Clean
Air Act. As amended, the Act formerly
classified to 42 U.S.C. 1857 et seq. has
been transferred and is now classified
to 42 U.S.C. 7401 et seq.
DATE: March 3, 1978.
INFORMATION
FOR
FURTHER
CONTACT:
Don R. Goodwin, Emission Stan-
dards and Engineering Division, En-
vironmental Protection Agency, Re-
search Triangle Park, N.C. 27711
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
This action Is being taken in accor-
dance with the requirements of 1 CFR
21.43 and is authorized under section
301(a) of the Clean Air Act, as amend-
ed, 42 U.S.C. 7601(a). Because the
amendments are clerical in nature and
affect no substantive rights or require-
ments, the Administrator finds it un-
necessary to propose and invite public
comment.
Dated: February 24, 1978.
DOUGLAS M. COSTLE,
Administrator.
Parts 60 and 61 of Chapter I, Title
40 of the Code of Federal Regulations
are revised as follows:
1. The authority citation following
the table of sections in Part 60 is re-
vised to read as follows:
AUTHORITY: Sec. Ill, 301(a) of the Clean
Air Act as amended (42 U.S.C. 7411,
7601
-------
84
PART 60—STANDARDS OF PERFOR.
MANCE FOR NEW STATIONARY
SOURCES
Lignite-Fired Steam Generators
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This final rule estab-
lishes standards of performance for
new or modified lignite-fired steam
generators with heat input rates great-
er than 73 megawatts (250 million Btu
per hour) and limits emissions of ni-
trogen oxides to 260 ng/J of heat
input except that 340 ng/J of heat
input is allowed from cyclone-fired
units which are fired with lignite
mined in North Dakota, South
Dakota, or Montana. Steam gener-
ators contribute significantly to air
pollution, and the intended effect of
this final rule is to require new steam
generators which burn lignite to use
the best control system for reducing
emissions of nitrogen oxides.
EFFECTIVE DATE: March 7,1978.
ADDRESSES: The "Standards Sup-
port and Environmental Impact State-
ment (SSEIS), Volume 2: Promulgated
Standards of Performance for Lignite-
Fired Steam Generators" (EPA-450/2-
76-030b) may be obtained by writing
the U.S. EPA Library (MD-35). Re-
search Triangle Park, N.C. 27711.
Volume 1 of the SSEIS, "Proposed
Standards of Performance for Lignite-
Fired Steam Generators" (EPA-450/2-
76-030a), is also available at the same
address. Please specify both the title
and EPA number of the document de-
sired. These documents and all public
comments may be inspected at the
Public Information Reference Unit
(EPA Library), Room 2922. 401 M
Street SW.. Washington, D.C.
FOR FURTHER INFORMATION
CONTACT:
tULES AND REGULATIONS
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park,
N.C. 27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On December 23, 1971 (36 FR 24877),
EPA established under Subpart D of
40 CFR Part 60 standards of perfor-
mance for new steam generators with
heat input rates greater than 73
megawatts (250 million Btu per hour).
Steam generators which burn llgnitie
were exempted from the emission
standards for nitrogen oxides (NO,)
because too little operating experience
was available to adequately character-
ize NO, emissions. (Lignite-fired steam
generators were not exempted from
the standards for sulfur oxides and
participate matter, however.) Since
1971, EPA has gathered additional in-
formation on lignite-fired facilities,
and on December 22, 1976 (41 FR
55791), the Agency proposed to amend
Subpart D by establishing a standard
of performance of 260 nanograms per
joule (ng/J) of heat input (0.6 pound
per million Btu) for NO, emissions
from new lignite-fired steam gener-
ators. Supporting information for the
proposed standard was published in
Volume 1 of the SSEIS for lignite-
fired steam generators. After review-
ing issues raised during the public
comment period which followed the
proposal, EPA decided to promulgate
standards which will permit the limit-
ed use of cyclone-fired facilities to
burn lignite mined in North Dakota,
South Dakota, and .Montana (which
causes severe fouling and slagging in
pulverized-fired units). Supporting in-
formation for these final standards of
performance appears in Volume 2 of
the SSEIS.
FINAL STANDARDS
NO, emissions from lignite-fired
steam generators are limited to 260
ng/J of heat in put (0.6 lb/10« Btu)
except that 340 ng/J (0.8 lb/10< Btu)
is allowed from cyclone-fired steam
generators burning lignite mined in
North Dakota, South Dakota, and
Montana. Both standards apply only
to boilers which burn lignite, with
heat input rates greater than 73
megawatts (250 million Btu per hour),
and for which construction or modifi-
cation began after December 21, 1976.
RATIONALE FOR FINAL STANDARDS
The NO, standard originally pro-
posed by EPA, 260, ng/J, may have
prevented the use of cyclone-fired
.boilers, since it has not.been demon-
strated that emisisons from these
units can be consistently controlled to
levels below 260 ng/J. During the
public comment period, several com-
menters argued that the utilization of
cyclone-fired boilers is necessary to
overcome the serious fouling and slag-
ging problems which develop when-
ever the sodium content of the lignite
burned exceeds about 5 percent, by
weight. These high sodium content re-
serves are believed to be widespread,
especially in North Dakota, and the
utilities claim that their low sodium
content reserves are being rapidly de-
pleted. The commenters said that cy-
clones have inherently lower fouling
and slagging rates than other large
boiler designs because much less ash is
carried through the boiler convective
passes. In addition, they contended
that In the Dakotas there has actually
been very little operating experience
with pulverlzed-flred boilers, the alter-
native .to large cyclones, and It is
doubtful that these units can burn
high sodium lignite without experienc-
ing severe problems. Thus, the com-
menters concluded that the proposed
standard might restrict the use of
valuable resources of high sodium lig-
nite fuel by prohibiting the utilization
of cyclone-fired boilers. The com-
menters also argued that the proposed
standard would place an economic
burden on the electirc power utilities
which burn lignite by limiting compe-
titve bidding for new boilers.
EPA agrees that at present there is
too little operating experience with
pulverized- or cyclone-fir;d boilers to
be able to predict their reliability
when burning high sodium lignite.
Furthermore, the Agency does not
want to establish a standard which
might inhibit future efforts to find a
successful way to burn this trouble-
some fuel. Consequently, EPA has es-
tablished a separate nitrogen oxides
emission standard of 340 ng/J (0.8 lb/
10* Btu) for new cyclone-fired boilers
which burn North Dakota, South
Dakota, or Montana lignite. This stan-
dard will permit the limited utlization
of cyclone-fired boilers and assure the
continued use of our country's abun-
dant resources of lignite. Lignite
mined in Texas, the only other known
major lignite formation, generally has
low sodium content and has been suc-
cessfully burned in pulverized-fired
units for years. The standard is sup-
ported by emission test data and other
Information contained in Volume I of
the SSEIS. Nitrogen oxides emissions
from pulverized-fired boilers will be
limited to 260 ng/J (0.6 lb/10« Btu), as
originally proposed.
. Cyclone-fired boilers could account
for 10 to 20 percent of all new lignite-
fired steam generators, based on EPA
estimates of lignite consumption for
the year 1980. EPA estimates that NO,
emissions from .new cyclone-fired boil-
ers may be reduced by as much as 20
percent as a result of the standard.
The combined effect of both standards
will be to reduce total NO. emissions
from all new boilers which burn lignite
by about 25 percent.
V-250
-------
fcULES ANft REGULATIONS
It should be noted that standards of
performance for new sources estab-
lished under-section 111 of the Clean
Air Act reflect the degree of emission
limitation achievable through applica-
tion of the best adequately demon-
strated technological system of con-
tinuous emission reduction (taking
into consideration the cost of achiev-
ing such emission reduction, any non-
air quality health and environmental
'impact find energy requirements).
State implementation plans (SIPs) ap-
proved or promulgated under section
110 of the Act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIPs must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173 of the Act requires, among
other things, that a new or modified
source constructed in an area which
exceeds the NAAQS must reduce emis-
sions to the level which reflects the
"lowest achievable emission rate" for
such category of source as defined in
section 171(3), unless the owner or op-
erator demonstrates that the source
cannot achieve such an emission rate.
In no event can the emission rate
exceed any applicable standard of per-
formance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (Part C). These provi-
sions require, atnong other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology. l*he term "best available con-
trol technology" (BACT) means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
.energy, environmental, and economic
impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission* control and
should not preclude the imposition of
a more -stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty).
costs must be accorded far less weight
in determining the "lowest achievable
emission rate" for new or modified
sources locating in areas violating sta-
tutorily-mandated health and welfare
standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition. 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. Thus,
new sources may in some cases be sub-
ject 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.
ENVIRONMENTAL AND ECONOMIC IMPACTS
The impact of the NO, emission
standards will be most significant in
North Dakota and Texas where most
new lignite-fired boilers will be locat-
ed. Although ambient NO, levels In
these areas are now low, emission reg-
ulations are important because: (1)
The standards will maintain low ambi-
ent NO, concentrations In areas where
population and industrial growth is
expected in the future; (2) the stan-
dards will reduce the potential for de-
velopment of. rural smog which can
form in regions having Initially low
ambient NO, concentrations; and (3)
the standards will reduce long distance
transport of NO, to areas having air
pollution problems. In addition, since
nationwide levels of NO, are expected
to rise in the future despite NO, con-
trol regulations, the NO, emission
standards for lignite-fired boilers will
help to alleviate this problem.
The standards will cause total NO,
emissions from all new lignite-fired
steam generators to be reduced by
about 25 percent. By comparison, NO,
emissions would have been reduced by
about 29 percent if the use of cyclones
had been restricted by the standard
originally proposed. Thus, the contin-
ued use of cyclone-fired boilers will
have only a minor adverse impact on
air quality.
The NO. emission standards will
have no impact on water pollution,
solid waste disposal, sulfur dioxide and
particulate emissions, or energy con-
sumption at new lignite-fired steam
generators. In addition, the standards
will not prohibit the use of any lignite
reserves or adversely affect any other
natural resources. Additional informa-
tion about the environmental impact
of the standards appears in Volumes 1
and 2 of the SSEIS.
The NO, emission standards will
cause capital costs for new lignite-fired
plants to increase by, at most, only 0.5
percent and operating costs will rise
even less. Therefore, capital and oper-
ating expenses will rise only nominal-
ly. Since the price consumers pay for
electric power is generally proportion-
al to the electric utility's operating
costs, consumer power price increases
will be negligible. The boiler manufac-
turers will experience no significant
market disadvantages because the
standards effectively permit the sale
of all boiler designs and provide no
sales advantages for any manufactur-
er. The small increases in capital costs
resulting from the standards will not
affect the boiler -industry's overall
sales. More information about the eco-
nomic impact of the standards can be
found in Volumes 1 and 2 of the
SSEIS.
PUBLIC COMMENTS
Seventeen comment letters were re-
ceived during the public comment
period. -Many of the. comments were
critical of the Information EPA used
to support restriction of the cyclone-
fired boiler. In particular, these argu-
ments were made: (1) None of the pul-
verized-fired boilers which EPA tested
operate reliably when burning lignite
with a sodium content above about 5
percent; (2) the front-wall-fired plant
cited by EPA has never burned lignite
with an 8 percent sodium content for
an extended period of time, as EPA
has reported. Also, the plant's capac-
ity factor has averaged about 72 per-
cent, not 86 percent as stated by EPA;
(3) although it is true that a North
Dakota electric utility has recently
agreed to purchase two tangentially-
fired boilers, these units are guaran-
teed to burn lignite containing no
more than 4.8 percent sodium. Also,
the decision to purchase these boilers
may have been influenced by the utili-
ty's concern that EPA might prohibit
the use of cyclones; (4) recent experi-
ments by the Energy Research and
Development Administration have
demonstrated that cyclone-fired boil-
ers have significantly lower ash depo-
sition rates than pulverized-fired boil-
ers. This confirms arguments that cy-
clones have much lower fouling and
slagging potentials when burning high
sodium content lignite.
EPA agrees that there has not been
enough successful operating experi-
ence with pulverized-fired boilers
FEDERAL REGISTER, VOL. 43, NO. 45—TUESDAY, MARCH 7, 1978
V-251
-------
RULES AND REGULATIONS
which burn high sodium content lig-
nite to justify eliminating cyclones
from the market. Consequently, the
Agency has decided to establish a sep-
arate NO. emission standard for cy-
clones burning Dakota lignite which
permits their use.
Another issue raised during the com-
ment period concerned the potentially
high NO. emissions which could occur
when Texas lignite with a high nitro-
~gen content is burned. It was argued
that these emissions could exceed the
standard even if the best system of
emission reduction were employed. In
support of this contention, a com-
menter submitted data which Indicate
that the fuel-nitrogen content of
Texas lignites ranges well above ex-
pected values. EPA has determined,
however, that these data were accu-
mulated around the turn of the cen-
tury and are inconsistent with present-
day values. Information from the
Bureau of Economic Geology at the
University of Texas and the Texas
Railroad Commission indicates that
Texas lignite nitrogen contents are
typically low and should not cause
NO, emissions from a well controlled
plant to exceed the standard.
These and all other comments are
discussed in detail in Volume 2, Chap-
ter 2 of the SSEIS.
The effective date of this regulation
is (date of publication), because sec-
tion HKbXlXB) of the Clean Air Act
provides that standards of perfor-
mance or revisions thereof become ef-
fective upon promulgation.
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analy-
sis under Executive Orders 11821 and 11949
and OMB Circular A-107.
Dated: March 2.1978.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed by revising Subparts A and D as fol-
lows:
Subpart A—General Previsions
1. Section 60.2 is amended by substi-
tuting the International System of
Units (SI) in paragraph (1) as follows:
860.2 Definitions.
(1) "Standard conditions" means a
temperature of 293 K (68° F) and a
pressure of 101.3 kilopascals (29.92 in
Hg).
Subpart D—Standards of Performance
for Fossil Fuel-Fired Steam Generator*
2. Section 60.40 is amended by revis-
ing paragraph (c) and by adding para-
graph (d) as follows:
§60.40 Applicability and designation of
affected facility.
(c) Except as provided in paragraph
(d) of this section, any facility under
paragraph (a) of this section that com-
menced construction or modification
after August 17, 1971, is subject to the
requirements of this subpart.
(d) The requirements 'of
§§60.44(a)(4), (a)(5), (b), and (d), and
60.45(f)(4)(vl) are applicable to lignite-
fired steam generating units that com-
menced construction or modification
after December 22,1976.
3. Section 60.41 is amended by
adding paragraph (f) as follows:
§ 60.41 Definitions.
(f) "Coal" means all solid fuels clas-
sified as anthracite, bituminous, subbi-
tuminous, or lignite by the American
Society for Testing Material. Designa-
tion D 388-66.
4. Section 60.44 is amended by
adding paragraphs (a)(4) and (a)(5), by
revising paragraph (b), and by adding
paragraphs (c) and (d) as lollows:
§ 60.44 Standard for nitrogen oxides.
(a) • • •
(4) 260 nanograms per joule heat
Input (0.60 Ib per million Btu) derived
from lignite or lignite and wood resi-
due (except as provided under para-
graph (a)(5) of this section).
(5) 340 nanograms per joule heat
Input (0.80 Ib per million Btu) derived
from lignite which is mined in North
Dakota, South Dakota, or Montana
and which is burned in a cyclone-fired
unit.
(b) Except as provided under para-
graphs (c) and (d) of this section,
when different fossil fuels are burned
simultaneously in any combination,
the applicable standard (in ng/J) is de-
termined by proration using the fol-
lowing formula:
where:
PS*>1=lB the prorated standard for nitro-
gen oxides when burning different
fuels simultaneously, in nanograms
per joule heat input derived from all
fossil fuels fired or from all fossil fuels
_ and wood residue fired;
to=is the percentage of total heat input
derived from lignite;
x=is the percentage of total heat input
derived from gaseous fossil fuel;
l/=ls the percentage of total heat input
derived from liquid fossil fuel; and
z=ls the percentage of total heat input de-
rived from solid fossil fuel (except lig-
nite).
(c) When a fossil fuel containing at
least 25 percent, by weight, of coal
refuse is burned in combination with
gaseous, liquid, or other solid fossil
fuel or wood residue, the standard for
nitrogen oxides does not apply.
(d) Cyclone-fired units which b'
fuels containing at least 25 percent of
lignite that is mined in North Dakota,
South Dakota, or Montana remain
subject to paragraph (a)(5) of this sec-
tion regardless of the types of fuel
combusted in combination with that
lignite.
(Sections 111 and 301(a) of the Clean Air
Act, as amended (42 U.S.C. 7411, and 7601).)
5. Section 60.45 is amended by
adding paragraph (f)(4)(vi) as follows:
8 60.45 Emission and fuel monitoring.
(f) • • •
(4). . .
(vi) For lignite coal as classified ac-
cording to A.S.T.M. D 388-66,
F= 2.659x10-' dscm/J (9900 dscf/mil-
lion Btu) and Fc=0.516xlO-' scm CO,/
J (1920 scf CO,/million Btu).
(Sections 111, 114, and 301(a) of the Clean
Air Act. as amended (42 U.S.C. 7411, 7414,
and 7601).)
IFR Doc. 78-5975 Filed 3-6-78; 8:45 *m]
FEDERAL REGISTER, VOL 43, NO. 45
TUESDAY, MARCH 7, 1W
V-252
-------
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TOCo
off
tFRL 836-2J
PAQ? g®~§?AK)E)ARE>§ ©P Pil3l?©B-
§'
IPtonto
AGENCY: Environmental Protection
Asency (EPA).
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which limit
emissions of participate matter from
aew, modified, and reconstructed lime
manufacturing plants. The standards
implement the Clean Air Act and are
teased on the Administrator's determi-
nation that lime manufacturing plant
emissions contribute significantly to
air pollution. The intended effect of
setting these standards is to require,
mew, modified, and reconstructed lime
manufacturing plants to use the best
demonstrated system of continuous
emission reduction.
DATE: March 7, 1978.
ADDRESSES: A support document
entitled, "Standard Support and Envi-
ronmental Impact Statement, Volume
XX: Promulgated Standards of Perfor-
mance for Lime Manufacturing
Plants" (EPA-450/2-77-007b), October
1877, has been prepared and is avail-
able. This document includes sum-
mary economic and environmental
impact statements as well as EPA's re-
sponses to the comments on the pro-
posed standards. Also available is the
supporting volume for the proposed
standards entitled, "Standard Support
and Environmental Impact Statement,
Volume I: Proposed Standards of Per-
formance for Lime Manufacturing
Plants" (EPA-450/2-77-007a), April
1077. Copies of these documents can
foe ordered by 'addressing & request to
the EPA Library (MD-35), Research
Triangle Park, N.C. 27711. The title
and number for each or both of the
documents should be specified when
ordering. These documents as well as
copies of the comment letters respond-
ing to the proposed rulemaking pub-
lished in the FEDERAL REGISTER on
May 3, 1677 (42 FR 22506) are avail-
able for public Inspection and copying
at the U.S. Environmental Protection
Agency, Public Information Reference
Unit (EPA Library), Room 2922. 401 M
Street SW.. Washington, D.C. 20460.
3?OR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park,
N.C. 27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
There are two minor changes in the
standards from those proposed on
May 3, 1977. The first of these is the
specific exclusion of lime production
units at kraft pulp mills [§60.340
-------
tULES AND REGULATIONS
from any major emitting facility,
which the permitting authority, on a
case-by-cage basis, taking Into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
Udn techniques for .control- of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which wDl exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate In
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example while
cost of achievement may be an impor-
tant factor hi determining standards
of performance applicable to.all areas
of the country (clean as well as dirty),
statutorily, costs do not play such a
role in determining the "lowest achiev-
able emission rate" for new or modi-
fied sources locating in areas violating
statutorily-mandated health and wel-
fare standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition, 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. Thus,
new sources may in some cases be sub-
ject 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.
MISCELLANEOUS: The effective
date of this regulation is March 7,
1978. Section HKbXlKB) of the Clean
Air Act provides that standards of per-
formance or revisions of them become
effective upon promulgation and apply
to affected facilities, construction or
modification of .which was commenced
after the date of proposal (May 3,
1977).
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
an Economic Impact Analysis under Execu-
tive Orders 11821 and 11949 and OMB Cir-
cular A-107.
Dated: March 1.1978.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I of Title 40 of
the Code of Regulations is amended as
follows:
1. By adding subpart WTT as follows:
Subparl HH—Standards of Perfor-
mance for Lime Manufacturing
- Plants
8ec.
60.340 Applicability and designation of af-
fected facility.
60.341 Definitions.
60.342 Standard for particulate matter.
60.343 Monitoring of emissions and oper-
ations.
60.344 Test methods and procedures.
AUTHORITY: Sec. Ill and 301(a) of the
Clean Air Act. as amended (42 U.S.C. 7411,
7601), and additional authority as noted
below.
§60.340 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities used in the manufacture
of lime: rotary lime kilns and lime hy-
drators.
(b) The provisions of this subpart
are not applicable to facilities used in
the manufacture of lime at kraft pulp
mills.
(c) Any facility under paragraph (a)
of this section that commences con-
struction or modification after May 3,
1977, is subject to the requirements of
this part.
§ 60.341 Definitions.
As used In this subpart, all terms not
defined herein shall have the same
meaning given them In the Act and in
subpart A of this part.
(a) "Lime manufacturing plant" In-
cludes any plant which produces a
lime product from limestone by calci-
nation. Hydration of the lime product
is also considered to be part of the
source.
(b) "Lime product" means the prod-
uct of the calcination process includ-
ing, but not limited to, calcitic lime,
dolomitic lime, and dead-burned dolo-
mite.
(c) "Rotary lime kiln" means a unit
with an inclined rotating drum which
is used to produce a lime product from
limestone by calcination.
(d) "Lime hydrator" means a unit
used to produce hydrated lime prod-
uct.
§ 60.342 Standard for particulate 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 provi-
sions of this subpart shalTcause to be
discharged into the atmosphere:
(1) Prom any rotary lime kiln any
gases which:
(1) Contain particulate matter In
excess of 0.15 kilogram per megagram
of limestone feed (0.30 Ib/ton).
(il) Exhibit 10 percent opacity or
greater.
(2) Prom any lime hydrator any
gases which contain particulate matter
in excess of 0.075 kilogram per mega-
gram of lime feed (0.15 Ib/ton).
§ 60.343 Monitoring of emissions and • op-
erations.
(a) The owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
a continuous monitoring system,
except as provided In paragraph (b) of
this section, to"monitor and record the
opacity of a representative portion of
the gases discharged Into the atmos-
phere from any rotary lime kiln. The
span of this system shall be set at 40
percent opacity.
(b) The owner or operator of any
rotary lime kiln using a wet scrubbing
emission control device subject to the
provisions of this subpart shall not be
required to monitor the opacity of the
gases discharged as required in para-
graph (a) of this section, but shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
devices:
(DA monitoring device for the con-
tinuous measurement of the pressure
loss of the gas stream through the
scrubber. The monitoring device must
be accurate within ±250 pascals (one
inch of water).
(2) A monitoring device for the con-
tinuous 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) The owner or operator of any
lime hydrator using a wet scrubbing
emission control device subject to the
provisions of this subpart shall install,
calibrate, maintain, and operate the
following continuous monitoring de-
vices:
(DA monitoring device for the con-
tinuous measuring of the scrubbing
liquid flow rate. The monitoring
device must be accurate within ±5 per-
cent of design scrubbing liquid flow
rate.
<2) A monitoring device for the con-
tinuous measurement of the electric
• current, in amperes, used by the scrub-
ber. The monitoring device must be ac-
curate within ±10 percent over its
normal operating range.
(d) For the purpose of conducting a
performance test under §60.8, the
owner or operator of any lime manu-
facturing plant subject to the provi-
sions of this subpart shall Install, cali-
brate, maintain, and operate a device
for measuring the mass rate of lime-
stone feed to any affected rotary lime
MKftAL KEOISTEft, VOL 43, NO. 4S—TUESDAY, MARCH 1,
V-254
-------
and the MMS rate of lime feed to
affected lime hydrator. The mea-
suring device used must be accurate to
within ±5 percent of the mass rate
over its operating range.
(e) For the purpose of reports re-
quired 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 lime kiln si'^.'ect
to paragraph (a) of this subpaic is 10
percent or greater.
(Sec. 114 of the Clean Air Act. as amended
«12 U.S.C. 7414).)
§00.344 Test methods and procedures.
(a) Reference methods in Appendix
A of this part, except as provided
under §80.8(b), shall be used to deter-
mine compliance with §80.322(a) &s
follows:
(1) Method 5 for the measurement
of particulate matter,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate,
«1) Method 3 for gas analysis,
(5) Method 4 for stack gas moisture,
and
(8) Method 9 for visible emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.85 std m'/h. dry basis (0.53
dscf/mln), except that shorter sam-
pling times, when necessitated by pro-
cess variables or other factors, may be
approved by the Administrator.
(c) Because of the high moisture
content (40 to 85 percent by volume)
of the exhaust gases from hydrators,
the Method 5 sample train may be
modified to Include a calibrated orifice
Immediately following the sample
norale when testing lime hydrators. In
this configuration, the sampling rate
necessary for maintaining isokinetic
conditions can be directly related to
exhaust gas velocity without a correc-
tion for moisture content. Extra care
Qhould be exercised when cleaning the
sample train with the orifice in this
position following the test runs.
(Sec. 114 of the Clean Air Act, es amended
(42 UJS.C. 7414).)
[PR Doc. 78-8974 Filed 3-S-78; 8:45 am]
CHAPTER 1— ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C— AIH PROGRAMS
[FRL 836-1]
PAST 60— STANDARDS OF PHRPOS-
MANCE FOR NEW
SOURCES
, mass 7,
Refinery Clous Sulfur
Recovery Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which will
limit emissions of sulfur dioxide (SO,)
and reduced sulfur compounds from
new, modified, and reconstructed pe-
troleum refinery Claus sulfur recovery
plants. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from petroleum refinery
Claus sulfur recovery plants contrib-
ute significantly to air pollution. The
intended effect of the standards is to
require new, modified, and recon-
structed petroleum refinery Claus
sulfur recovery plants to use the best
technological system of continuous
emission reduction.
EFFECTIVE DATE: March 15, 1978.
ADDRESSES: Copies of the standard
support documents are available on re-
quest from the U.S. EPA Library
(MD-35), Research Triangle Park,
N.C. 27711. The requestor should
specify "Standards Support and Envi-
ronmental Impact Statement. Volume
I: Proposed Standards of Performance
for Petroleum Refinery Sulfur Recov-
ery Plants" (EPA-450/2-76-016a) and/
or "Standards Support and Environ-
mental Impact Statement, Volume II:
Promulgated Standards of Perfor-
mance for Petroleum Refinery Sulfur
Recovery Plants" (EPA-450/2-76-
016b). Comment letters responding to
the proposed rules published in the
FEDERAL REGISTER on October 4, 1976
(41 FR 43866), are available for public
inspection and copying at the U.S. En-
vironmental Protection Agency, Public
Information Reference Unit (EPA Li-
brary), Room 2922, 401 M Street SW.,
Washington, D.C.
FOR FURTHER INFORMATION
CONTACT:
' Don R. Goodwin, Emission Stan-
dards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park,
N.C. 27711, telephone number 919-
541-5271.
SUPPLEMENTARY INFORMATION:
SUMMARY
On October 4, 1976 (41 FR 43866).
EPA proposed standards of perfor-
mance for new petroleum refinery
Claus sulfur recovery plants under sec-
tion 111 of the Clean Air Act, as
amended. The promulgated standards
are essentially the same as those pro-
posed, although an exemption for
small petroleum refineries has been in-
cluded in the promulgated standards.
The standards are based on the use of
tail gas scrubbing systems which have
been determined to be the best tech-
nological system of continuous emis-
sion reduction, taking into consider-
ation the cost of achieving such emis-
sion reduction, any nonair quality,
health, and environmental impact and
energy requirements. Compliance with
these standards will increase the over-
all sulfur recovery efficiency of a typi-
cal refinery Claus sulfur recovery
plant to about 99.9 percent, compared
to a recovery efficiency of about 94
percent for an uncontrolled refinery
Claus sulfur recovery plant, or a recov-
ery efficiency of about 99 percent for a
Claus sulfur recovery plant complying
with typical State emission control
regulations for these plants.
The promulgated standards will
apply to: (l)"any Claus sulfur recovery
plant with a sulfur production capac-
ity of more than 20 long tons per day
(LTD) which is associated with a small
petroleum refinery (i.e., a petroleum
refinery having a crude oil processing
capacity of 50,000 barrels per stream
day (BSD) or less which is owned or
controled by a refiner whose total
combined crude oil processing capacity
is 137,500 BSD or less) and (2) any size
Claus sulfur recovery plant associated
with a large petroleum refinery. Spe-
cifically, the standards limit the con-
centration of sulfur dioxide (SO,) in
the gases discharged into the atmo-
sphere to 0.025 percent by volume at
zero percent oxygen on a dry basis.
Where the emission control system In-
stalled to comply with these standards
discharges residual emissions of hy-
drogen sulfide (H>S), carbonyl sulfide
(COS), and carbon disulfide (CS,), the
standards limit the concentration of
HS and the total concentration of
H,S, COS and CS, (calculated as SO,)
in the gases discharged into the atmo-
sphere to 0.0010 percent and 0.030 per-
cent by volume at zero percent oxygen
on a dry basis, respectively.
Compliance with these standards
will reduce nationwide sulfur dioxide
emissions by some 55,000 tons per year
by 1980. This reduction will be
achieved without any significant ad-
verse impact on other aspects of envi-
ronmental quality, such as solid waste
disposal, water pollution, or noise.
This reduction in emissions will also
be accompanied by a reduction in the
V-255
-------
growth of nationl energy consumption
equivalent to about 90,000 barrels of
fuel oil per year by 1980.
The economic impact of the promul-
gated standards is reasonable. They
will result in an increase in the annual
operating costs of the petroleum refin-
ing Industry by some $16 million per
year in 1980. An individual refiner who
installs alternative II controls will
need to increase his prices from 0.1 to
1 percent to maintain his profitability.
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Act re-
flect the degree of emission limitation
achievable through application of the
best adequately demonstrated techno-
logical system of continuous emission
reduction (taking into consideration
the cost of achieving such emission re-
duction, any nonair quality health and
environmental impact and energy re-
quirements). State implementation
plans (SIPs) approved or promulgated
under section 110 of the Act, on the
other hand, must provide 'for the at-
tainment and maintenance of national
ambient air quality standards
(NAAQS) designed to protect public
health and welfare. For that purpose,
SIPs must in some cases require great-
er emission reduction than those re-
quired by standards of performance
for new sources. Section 173(2) of the
Act requires, among other things, that
& new or modified source constructed
in an area which exceeds the NAAQS
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" for such category of
source, unless the owner or operator
demonstrates that the source cannot
achieve such an emission rate. In no
event can the emission rate exceed any
applicable standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to the best available control
technology. The term "best available
control technology" (BACT) means
"an emission limitation based on the
maximum degree of reduction of each
pollutant subject to regulation under
this Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty),
costs must be accorded far less weight
in determining the "lowest achievable
emission rate" for new or modified
sources locating in areas violating sta-
tutorily-mandated health and welfare
standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition, 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. Thus,
new sources may in some cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning
for such facilities.
PUBLIC PARTICIPATION
Prior to proposal of the standards,
interested parties were advised by
public notice in the FEDERAL REGISTER
of a meeting of the National Air Pollu-
tion Control Techniques Advisory
Committee to discuss the standards
recommended for proposal. This meet-
ing was open to the public and each
person attending was given ample op-
portunity to comment on the stan-
dards recommended for proposal. The
standards were proposed on October 4,
1976, and copies of the proposed stan-
dards and the Standards Support and
Environmental Impact Statement
(SSEIS) were distributed to members
of the petroleum refining industry and
several environmental groups at this
time. The public comment period ex-
tended from October 4, 1976, to De-
cember 3, 1976.
Twenty-two 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 pro-
posed.
MAJOR COMMENTS
Comments on the proposed stan-
dards were received from several oil in-
dustry representatives, State and local
air pollution control agencies, a vendor
of emission source testing equipment,
and several Federal agencies. These
comments covered four major areas:
the costs of implementing the stan-
dards, the ability of emission control
technology to meet the standards, the
environmental impacts of the stan-
dards, and the energy impacts of the
standards.
COSTS
The major comments concerning
costs were that the costs of the emis-
sion control systems required to meet
the standards were underestimated,
that these costs were excessive; and
that small sulfur recovery plants, or
small petroleum refineries should be
exempt from the standard.
The basic cost data used to develop
the cost estimates were obtained from
pretroleum refinery sources. No specif-
ic data or information was provided in
the public comments, however, which"
would indicate that these costs are sig-
nificantly in error.
In the preamble to the proposed
standards, comments were specifically
invited concerning the impact of the
standards on the small refiner. After,
considering these comments, EPA has!
concluded that some relief from the
standards is appropriate. The major
factor involved in this decision was a
consideration of the cost effectiveness
of the standards on large and small re-
finers. The incremental cost per incre-
mental unit of sulfur emissions that
must be controlled to meet the stan-
dards is substantially greater for the
small refiner than for the large refin- •
er. Furthermore, the impact of these
costs on the small refiner is more
severe than the impact on the large re-
finer, because the small refiner cannot
readily pass on the cost of emission
control equipment. Consequently, ES
discussed in volume II of the Stan-
dards Support and Environmental
Impact Statement (SSEIS), the pro-
mulgated standards include a lower
size cutoff for small petroleum refiner-
ies and Claus sulfur recovery plants.
Claus sulfur recovery plants with a
sulfur production capacity of 20 Ions
tons per day or less associated with &
petroleum refinery with a crude oil
processing capacity of 50,000 BSD or
less, which is owned or controlled by a
refiner whose total combined crude oil
processing capacity is 137,500 BSD or
less, are exempt from the standards.
This definition of a small petroleum
refinery is consistent with that includ-
ed in section 211 of the Clean Air Act,
as amended.
V-256
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AM0 QE©ya.AYB©)MS
EMISSION CONTROL TECHNOLOGY
A major concern of many com-
menters was the limited amount of
source test data used in support of the
numerical emission limits included in
the standards and the fact that some
of these data were collected at refiner-
ies where the emission control system
was operating below design capacity.
Also, some commenters questioned the
ability of the alternative II emission
control systems to continuously oper-
ate at a 99.9 percent control efficiency
because of the adverse impact of Claus
sulfur recovery plant fluctuations and
COa-rich waste/ gas streams.
In arriving at the numerical emis-
sions limits included in the standards,
source test data collected by a local
agency at times when the emission
control systems were operating at
normal capacities, information from
vendors of emission control equip-
ment, published literature on emission
control technology, and contractor re-
ports on the performance of emission
control technology were considered, in
addition to the data collected .during
EPA's source tests. Based on the infor-
mation and data from these sources
and the lack of any new information
and data submitted by the com-
menters, no change in the emission
limits of the standards is warranted.
Furthermore, the numerical emission
limits in the standards contain an ade-
quate safety margin to allow for in-
creased emissions due to Clause sulfur
recovery plant fluctuations.
With repect to the potential adverse
impact of high CO, gas streams, this is
not likely to impair the overall emis-
sion control system efficiency since
high COj gas streams are seldom
found in the gases treated in refinery
Claus sulfur recovery plants.
ENVIRONMENTAL IMPACT
Several commenters felt that the as-
sessment of the environmental impact
of the standards was, in some cases,
biased and not always clear. One of
these commenters suggested that a
thorough environmental impact state-
ment should be prepared to clarify the
impacts of the standards.
Litigation involving standards of
performance has established that
preparation of a formal environmental
impact statement under the National
Environmental Policy Act is not neces-
sary for actions under section 111 of
the Clean Air Act. While a formal en-
vironmental impact statement is not
prepared, the beneficial as well as the
adverse Impacts of standards of per-
formance are considered. The promul-
gated standards will significantly
reduce emissions of sulfur from petro-
leum refineries without resulting in
any significant adverse environmental,
energy, or economic impacts.
Other commenters felt that stan-
ta-ds based on 89 percent control (al-
ternative I) would be essentially as en-
vironmentally beneficial as standards
based on 99.9 percent control and
would be less costly to the public. This
argument was based on the premise
that most State regulations do not re-
quire control of Claus sulfur plant
emissions at the 99 percent level as
claimed in volume I of the SSEIS.
Hence, standards based on alternative
I would significantly reduce national
sulfur emissions from refinery Claus
sulfur recovery plants.
A review of State regulations for
controlling emissions from refinery
sulfur recovery plants has shown that
the majority of the States with the
largest petroleum refining capacities
require 99 percent control of emissions
from new and existing sulfur recovery
plants. Since refinery sulfur recovery
plant growth will likely occur in these
States, the conclusion that standards
based on 99 percent control would
have little or no beneficial impact is
essentially correct.
ENERGY IMPACT
Several commenters questioned the
conclusion that compliance with stan-
dards based on alternative II could
lead to an energy savings, compared to
standards based on alternative I. A
review of the information and data
available confirms this conclusion. In
any case, the important consideration
is whether the energy impact of the
standards is reasonable. No informa-
tion was submitted which would indi-
cate that the energy impact of the
standards is unreasonable.
OTHER CONSIDERATIONS
At proposal comments were request-
ed relative to EPA's decision to regu-
late reduced sulfur compound emis-
sions, which are designated pollutants.
without implementing section lll(d)
of the Clean Air Act at this time. The
one commenter who responded to this
issue was in agreement with this deci-
sion.
As discussed in both the preamble to
the proposed standards and volumes I
and II of the SSEIS, petroleum refin-
ery Claus sulfur recovery plants are
sources of SO. emissions, not reduced
sulfur compound emissions. One of
the emission control technologies for
reducing SO, emissions, however, first
converts these emissions to reduced
sulfur compounds and then controls
these compounds. Consequently, this
technology may discharge residual
emissions of reduced sulfur com-
pounds to the atmosphere.
Currently, there are about 30 refin-
ery Claus sulfur recovery plants in the
United States which have installed re-
duction emission control systems to
. reduce SO, emissions. A review of
these plants indicates that these emis-
sion control systems are well designed
and well maintained and operated.
Emissions of reduced sulfur com-
pounds are less than 0.050 percent
(i.e., 500 ppm), which is only slightly
higher than the numerical emission
limit included in the promulgated
standard. Thus, there is little to gain
at this time by requiring States to de-
velop regulations limiting emissions
from these sources. Consequently, sec-
tion lll(d) will not be implemented
until resources permit, taking into
consideration other requirements of
the Clean Air Act, as amended, which
EPA must implement.
Several commenters were concerned
that Reference Method 15 might not
be practical for use in a refinery envi-
ronment. The basis for most of these
objections was that the commenters
thought this method was being pro-
posed as a continuous monitoring
method. However, Reference Method
15 was not proposed for use as a con-
tinuous monitoring method. Perfor-
mance specifications for continuous
monitors for reduced sulfur com-
pounds have not been developed and
therefore such monitors are not re-
quired to be installed until perfor-
mance specifications for these moni-
tors are proposed and promulgated
under Appendix B of 40 CPR Part 60.
Reference Method 15 has been re-
vised to allow greater flexibility in op-
erating details and equipment choice.
The user is now permitted to design
his own sampling and analysis system
as long as he preserves the operating
principle of gas chromatography with
flame photometric detection and
meets the design and performance cri-
teria.
MISCELLANEOUS
The effective date of this regulation
is March 15, 1978. Section HKbXlXB)
of the Clean Air Act provides that
standards of performance or revisions
of them become effective upon pro-
mulgation and apply to affected facili-
ties, construction or modification of
which was commenced after the date
of proposal (October 4,1976).
ECONOMIC IMPACT ASSESSMENT: An econom-
ic assessment has been prepared as required
under section 317 of the Act. This also satis-
fies the requirements of Executive Orders
11821 and 11949 and OMB Circular A-107.
Dated: March 1, 1978.
DOUGLAS M. COSTLE.
Administrator.
1. Section 60.100 is amended as fol-
lows:
§60.100 Applicability and designation of
effected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in petroleum refineries:
fluid catalytic cracking unit catalyst
regenerators, fuel gas combustion de-
vices, and all Claus sulfur recovery
plants except Claus plants of 20 long
V-257
-------
RULES AND REGULATIONS
tons per day (LTD) or less associated
with a small petroleum refinery. The
Claus sulfur recovery plant need not
be physically located within the
boundaries of a petroleum refinery to
be an affected facility, provided it pro-
cesses gases produced within a petro-
leum refinery.
(b) Any fluid catalytic cracking unit
catalyst regenerator of fuel gas com-
bustion device under paragraph (a) of
this section which commences con-
struction or modification after June
11, 1973, or any Claus sulfur recovery
plant under paragraph (a) of this sec-
tion which commences construction or
modification after October 4, 1976, is
subject to the requirements of this
part.
(Sees. Ill and 301(a), Clean Air Act. as
amended (42 U.S.C. 7411, 7601 (a)), and ad-
ditional authority as noted below.)
2. Section 60.101 is amended as fol-
lows:
§ 60.101 Definitions.
(i) "Claus sulfur recovery plant"
means a process unit which recovers
sulfur from hydrogen sulfide by a
vapor-phase catalytic reaction of
sulfur dioxide and hydrogen sulfide.
(j) "Oxidation control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to sulfur dioxide.
(k) "Reduction control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to hydrogen sulfide.
(1) "Reduced sulfur compounds"
mean hydrogen sulfide (H,S). carbonyl
sulfide (COS) and carbon disulfide
(CSZ).
(m) "Small petroleum refinery"
means 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
refinery with a total combined crude
oil processing capacity of 137,500 bar-
rels per stream day or less.
3. Section 60.102 is amended by re-
vising paragraph (a) introductory text
and paragraph (b) as follows:
§ 60.102 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 provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any fluid catalytic crack-
ing unit catalyst regenerator:
(b) Where the gases discharged by
the fluid catalytic cracking unit cata-
lyst regenerator pass through an in-
cinerator or waste heat boiler in which
auxiliary or supplemental liquid or
sold fossil fuel is burned, particulate
matter in excess of that permitted by
paragraph (a)(l) of this section may
be emitted to the atmosphere, except
that the incremental rate of particu-
late matter emissions shall not exceed
43.0 g/MJ (0.10 Ib/million Btu) of
heat input attributable to such liquid
or solid fossil fuel.
4. Section 60.104 is amended as fol-
lows:
§ 60.104 Standard for sulfur dioxide.
(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 provi-
sions of this subpart. shall:
(1) Burn in any fuel gas combustion
device any fuel gas which contains hy-
drogen sulfide in excess of 230 mg/
dscm (0.10 gr/dscf), except that the
gases resulting from the combustion of
fuel gas may be treated to control
sulfur dioxide emissions provided the
owner or operator demonstrates to the
satisfaction of the Administrator that
this is as effective in preventing sulfur
dioxide emissions to the atmosphere
as restricting the HU concentration in
the fuel gas to 230 mg/dscm or less.
The combustion in a flare of process
upset gas, or fuel gas which is released
to the flare as a result of relief valve
leakage, is 'exempt from this para-
graph.
(2) Discharge or cause the discharge
of any gases into the atmosphere from
any Claus sulfur recovery plant con-
taining in excess of:
(i) 0.025 percent by volume of sulfur
dioxide at zero percent oxygen on a
dry basis if emissions are controlled by
an oxidation control system, or a re-
duction control system followed by in-
cineration, or
(ii) 0.030 percent by volume of re-
duced sulfur compounds and 0.0010
percent by volume of hydrogen sulfide
calculated as sulfur dioxide at zero
percent oxygen on a dry basis if emis-
sions are controlled by a reduction
control system not followed by incin-
eration.
(b) [Reserved]
5. Section 60.105 is amended as fol-
lows:
§ 60.105 Emission monitoring.
(a)* • •
(2) An instrument for continuously
monitoring and recording the concen-
tration of carbon monoxide in gases
discharged into the atmosphere from
fluid catalytic cracking unit catalyst
regenerators. The span of this con-
tinuous monitoring system shall be
1,000 ppm.
(3)' • •
(4) An instrument for continuously
monitoring and recording concentra-
tions of hydrogen sulfide in fuel gases
burned in any fuel gas combustion
device, if compliance with
§60.104(a)(l) is achieved by removing
H,S from the fuel gas before it is
burned; fuel gas combustion devices
having a common source of fuel gas
may be monitored at one location, if
monitoring at this location accurately
represents the concentration of H,S in
the fuel gas burned. The span of this
continuous monitoring system shall be
300 ppm.
(5) An instrument for continuously
monitoring and recording concentra-
tions of SO, in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with §60.104(a)(2) is achieved through
the use of an oxidation control system
or a reduction control system followed
by incineration. The span of this con-
tinuous monitoring system shall be
sent at 500 ppm.
(6) An instrument(s) for continuous-
ly monitoring and recording the con-
centration of H,S and reduced sulfur
compounds in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with §60.104(a)(2) is achieved through
the use of a reduction control system
not followed by incineration. The
span(s) of this continuous monitoring
system(s) shall be set at 20 ppm for
monitoring and recording the concen-
tration of H,S and 600 ppm for moni-
toring and recording the concentration
of reduced sulfur compounds.
(e)* * *
(!>•••
(2) Carbon monoxide. All hourly pe-
riods during which the average carbon
monoxide concentration in the gases
discharged into the atmosphere from
any fluid catalytic cracking unit cata-
lyst regenerator subject to § 60.103 ex-
ceeds 0.050 percent by volume.
(3) Sulfur dioxide, (i) Any three-
hour period during which the average
concentration of HiS in any fuel gas
combusted In any fuel gas combustion
device subject to §60.104(a)(l) exceeds
230 mg/dscm (0.10 gr/dscf), if compli-
ance is achieved by removing H,S from
the fuel gas before it is burned; or any
three-hour period during which the
average concentration of SO, in the
gases discharged into the atmosphere
from any fuel gas combustion device
subject to §60.104(a)(l) exceeds the
level specified in §60.104(a)(l). if com-
pliance is achieved by removing SO.
from the combusted fuel gases.
(ii) Any twelve-hour period during
which the average concentration of
SO, in the gases discharged into the
atmosphere from any Claus sulfur re-
covery plant subject to §60.104(a)(2)
exceeds 250 ppm at zero percent
oxygen on a dry basis if compliance
with §60.104(b) is achieved through
the use of an oxidation control system
V-258
-------
SUILES AND KE6ULAYIOWS
r a reduction control system followed
y incineration; or any twelve-hour
_ eriod during which the average con-
centration of H2S, or reduced sulfur
compounds in the gases discharged
into the atmosphere of any Claus
sulfur plant subject to § 60.104(a)(2)
(b) exceeds 10 ppm or 300 ppm, respec-
tively, at zero percent oxygen and on a
dry basis if compliance is achieved
through the use of a reduction control
system not followed by incineration.
6. Section 60.106 is amended as fol-
lows:
§ 60.106 Test methods and procedures.
(c) For the purpose of determining
compliance with §60.104(a)(l),
Method 11 shall be used to determine
the concentration of. H,S and Method
6 shall be used to determine the con-
centration of S]
Buo = Proportion by volume of water vapor
in the gas stream for the run.
N=Number of samples.
B,, = Proportion by volume of water vapor
in the gas stream for the sample t.
t,,-Continuous sampling time for sample
i.
T= Total continuous sampling time of all
N samples.
-------
RULES AND REGULATIONS
effects on the flame photometric detector
even after 9:1 dilution. (Acceptable systems
must demonstrate that they have eliminat-
ed this interference by some procedure such
as eluding CO and CO, before any of the
sulfur compounds to be measured.) Compli-
ance with this requirement can be demon-
strated by submitting chromatograms of
calibration gases with and without CO, in
the diluent gas. The CO, level should be ap-
proximately 10 percent for the case with
CO, present. The two chromatographs
should show agreement within the precision
limits of section 4.1.
3.3 Elemental Sulfur. The condensation of
sulfur vapor in the sampling line can lead to
eventual coating and even blockage of the
sample line. This problem can be eliminated
along with the moisture problem by heating
the sample line.
4. Precision
4.1 Calibration Precision. A series of three
consecutive injections of the same calibra-
tion gas, at any dilution, shall produce re-
sults which do not vary by more than ±13
percent from the mean of the three injec-
tions.
4.2 Calibration Drift. The calibration drift
determined from the mean of three injec-
tions made at the beginning and end of any
8-hour period shall not exceed ±5 percent.
5. Apparatus
5.1.1 Probe. The probe must be made of
inert material such as stainless steel or
glass. It should be designed to incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
S.I.2 The sample line must be made of
Teflon,'no greater than 1.3 cm (Viz in) inside
diameter. All parts from the probe to the di-
lution system must be thermostatically
heated to 120' C.
S.I.3 Sample Pump. The sample pump
shall be a leakless Teflon coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120' C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are maue of inert material (e.g.
stainless steel or Teflon). It must be heated
to 120° C and be capable of approximately a
9:1 dilution of the sample. .
S.3 Gas Chromatograph. The gas chroma-
tograph must have at least the following
components:
5.3.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.
5.3.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±1' C.
5.3.3 Flow System. Gas metering system to
measure sample, fuel, combustion gas, and
carrier gas flows.
5.3.4 Flame Photometric Detector.
5.3.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10"'to 10~*
amperes full scale.
5.3.4.2 Power Supply. Capable of deliver-
ing up to 750 volts.
5.3.4.3 Recorder. Compatible with the
output voltage range of the electrometer.
'Mention of trade names or specific prod-
ucts does not constitute an endorsement by
the Environmental Protection Agency.
5.4 Gas Chromatograph Columns. The
column system must be demonstrated to be
capable of resolving three major reduced
sulfur compounds: H,S. COS, and CS,.
To demonstrate that adequate resolution
has been achieved the tester must submit a
Chromatograph of a calibration gas contain-
ing all three reduced sulfur compounds in
the concentration range of the applicable
standard. Adequate resolution will be de-
fined as base line separation of adjacent
peaks when the amplifier attenuation is set
so that the smaller peak is at least 50 per-
cent of full scale. Base line separation is de-
fined as a return to zero ±5 percent in the
Interval between peaks. Systems not meet-
Ing this criteria may be considered alternate
methods subject to the approval of the Ad-
ministrator.
5.5.1 Calibration System. The calibration
system must contain the following compo-
nents.
5.5.2 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs .from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lowest flow measurement. Calibra-
tion with a wet test meter before a test is
optional.
5.5.3 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±1.1° C.
5.5.4 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1'C.
6. Reagents
6.1 Fuel. Hydrogen (H.) prepurified grade
or better.
6.2 Combustion Gas. Ovygen (O,) or air,
research purity or better.
6.3 Carrier Gas. Prepurified grade or
better.
6.4 Diluent. Air containing less than 0.5
ppm total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons.
6.5 Calibration Gases. Permeation tubes,
one each of H,S, COS, and CS,, gravimetri-
cally calibrated and certified at some conve-
nient operating temperature. These tubes
consist of hermetically sealed FEP Teflon
tubing in which a liquified gaseous sub-
stance is enclosed. The enclosed gas perme-
ates through the tubing wall at a constant
rate. When the temperature is constant,
calibration gases covering a wide range of
known concentrations can be generated by
varying and accurately measuring the flow
rate of diluent gas passing over the tubes.
These calibration gases are used to calibrate
the GC/FPD system and the dilution
system.
7. Pretest Procedures
The following procedures are optional but
would be helpful in preventing any problem
which might occur later and invalidate the
entire test.
7.1 After the complete measurement
system has been set up at the site and
deemed to be operational, the following pro-
cedures should be completed before sam-
pling is initiated.
7.1.1 Leak Test. Appropriate leak test pro-
cedures should be employed to verify the in-
tegrity of all components, sample lines, and
connections. The following leak test proce-
dure is suggested: For components upstream
of the sample pump, attach the probe end
of the sample line to a manometer or
vacuum gauge, start the pump and pull
greater than 50 mm (2 in.) Hg vacuum, close
off the pump outlet, and then stop the
pump and ascertain that there is no leak for
1 minute. For components after the pump,
apply a slight positive pressure and check
for leaks by applying a liquid (detergent in
water, for example) at each joint. Bubbling
indicates the presence of a leak.
7.1.2 System Performance. Since the com-
plete system is calibrated following each
test, the precise calibration of each compo-
nent is not critical. However, these compo-
nents should be verified to be operating
properly. This verification can be performed
by observing the response of flowmeters or
of the GC output to changes in flow rates or
calibration gas concentrations and ascer-
taining the response to be within predicted
limits. If any component or the complete
system fails to respond in a normal and pre-
dictable manner, the source of the discrep-
ancy should be identifed and corrected
before proceeding.
8. Calibration
Prior to any sampling run, calibrate the
system using the following procedures. (If
more than one run is performed during any
24-hour period, a calibration need not be
performed prior to the second and any sub-
sequent runs. The calibration must, howev-
er, be verified as prescribed in section 10.
after the last run made within the 24-hour
period.)
8.1 General Considerations. This section
outlines steps to be followed for use of the
GC/FPD and the dilution system. The pro-
cedure does not include detailed instruc-
tions because the operation of these systems
is complex, and it requires an understanding
of the individual system being used. Each
system should Include a written operating
manual describing in detail the operating
procedures associated with each component
in the measurement system. In addition, the
operator shuld be familiar with the operat-
ing principles of the components; particular-
ly the GC/FPD. The citations in the Bib-
liography at the end of this method are rec-
ommended for review for this purpose.
8.2 Calibration Procedure. Insert the per-
meation tubes into the tube chamber. Check
the bath temperature to assure agreement
with the calibration temperature of the
tubes within ±0.1'C. Allow 24 hours for the
tubes to equilibrate. Alternatively equilibra-
tion may be verified by injecting samples of
calibration gas at 1-hour intervals. The per-
meation tubes can be assumed to have
reached equilibrium when consecutive
hourly samples agree within the precision
limits of section 4.1.
Vary the amount of air flowing over the
tubes to produce the desired concentrations
for calibrating the analytical and dilution
systems. Th6 air flow across the tubes must
at all times exceed the flow requirement of
the analytical systems. The concentration in
parts per million generated by a bube con-
taining a specific permeant can be calculat-
ed as follows:
C=KxP,/ML
Equation 15-1
where:
C=Concentration of permeant produced
in ppm.
P,=Permeation rate of the tube in jig/
mln.
V-260
-------
BUUIS AN0 KE©ULAYOONS
M = Molecular weight of the p»rmeant: g/
g-mole.
L=Flow rate. 1/mln, of air over permeant
@ 20'C, 760 mm Hg.
K=Gas constant at 20°C and 760 mm
Hg=24.041/gmole.
8.3 Calibration of analysis system. Gener-
ate a series of three or more known concen-
trations spanning the linear range of the
PPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system, inject these
standards In to the GC/FPD analyzers and
monitor the responses. Three injects for
each concentration must yield the precision
described in section 4.1. Failure to attain
this precision is an indication of a problem
in the calibration or analytical system. Any
such problem must be identified and cor-
rected before proceeding.
8.4 Calibration Curves. Plot the GC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gener-
ate a know concentration of hydrogen sul-
fled using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution is approximated. Inject the dilut-
ed calibration gas into the GC/FPD system
and monitor its response. Three injections
for each dilution must yield the precision
described in section 4.1. Failure to attain
this precision in this step is an indication of
a problem in the dilution system. Any such
problem must be identified and corrected
before proceeding. Using the calibration
data for HcS (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the GC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
be necessary. However, the precision re-
quirements of section 4.1 are still applicable.
8. Sampling and Analysis Procedure
6.1 Sampling. Insert the sampling probe
into the test port making certain that no di-
lution air enters the stack through the port.
Sesin sampling and dilute the sample ap-
proximately 9:1 using the dilution system.
Note that the precise dilution factor is that
which is determined in paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
0.2 Analysis. Aliquots of diluted sample
ore injected into the GC/FPD analyzer for
analysis.
0.2.1 Sample Run. A sample run Is com-
posed of 16 Individual analyses (Injects) per-
formed over a period of not less than 3
hours or more than 6 hours.
0.2.2 Observation for Clogging of Probe. If
reductions in sample concentrations are ob-
csrved during a sample run that cannot be
explained by process conditions, the sam-
pling must be interrupted to determine if
the sample probe is clogged with particulate
matter. If the probe is found to be clogged.
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing it with
a clean one. After each run. the sample
probe must be Inspected and. If necessary,
dismantled and cleaned.
10. Post-Test Procedures
10.1 Sample Line Loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard. ±20 percent, must
be introduced into the sampling system at
the opening of the probe in sufficient quan-
tities to ensure that there is an excess of
sample which must be vented to the atmo-
sphere. The sample must be transported
through the entire sampling system to the
measurement system in the normal manner.
The resulting measured concentration
should be compared to the known value to
determine the sampling system loss. A sam-
pling system loss of more than 20 percent is
unacceptable. Sampling losses of 0-20 per-
cent must be corrected by dividing the re-
sulting sample concentration by the frac-
tion of recovery. The known gas sample may
be generated using permeation tubes. Alter-
natively, cylinders of hydrogen sulfide
mixed in air may be used provided they are
traceable to permeation tubes. The optional
pretest procedures provide a good guideline
for determining if there are leaks in the
sampling system.
10.2 Recalibration. After each run, or
after a series of runs made within a 24-hour
period, perform a partial recalibration using
the procedures in section 8. Only H.S (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).
10.3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration curves
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth in paragraph 4.2. If the drift exceeds
this limit, the intervening run or runs
should be considered not valid. The tester,
however, may instead have the option of
choosing the calibration data set which
would give the highest sample values.
11. Calculations
11.1 Determine the concentrations of each
reduced sulfur compound detected directly
from the calibration curves. Alternatively,
the concentrations may be calculated using
the equation for the least squares line.
11.2 Calculation of SO, Equivalent. SO,
equivalent will be determined for each anal-
ysis made by summing the concentrations of
each reduced sulfur compound resolved
during the given analysis.
SO, equivalent = HH,S, COS, 2 CS,)d
Equation 15-2
where:
SO, equivalent = The sum of the concen-
tration of each of the measured com-
pounds (COS, H.S, CS,) expressed as
sulfur dioxide in ppm.
HcS=Hydrogen sulfide, ppm.
COS = Carbonyl sulfide, ppm.
CS,=Carbon disulfide, ppm.
d=Dilution factor, dimensionless.
11.3 Average SO, equivalent will be deter-
mined as follows:
Average SO, equivalent =
j S02 equtv.
_
H (1 - Bwo)
Equation 15-3
where:
Average SO, equivalent, = Average SO,
equivalent in ppm, dry basis.
Average SO, equivalent,=SO, in ppm as
• determined by Equation 15-2.
N = Number of analyses performed.
B wo=Fraction of volume of water vapor
in the gas stream as determined by
Method 4—Determination of Moisture
in Stack Gases (36 FR 24887).
12. Example System
Described below is a system utilized by
EPA in gathering NSPS data. This system
does not now reflect all the latest develop-
ments in equipment and column technology,
but it does represent one system that has
been demonstrated to work.
12.1 Apparatus.
12.1.1 Sample System.
12.1.1.1 Probe. Stainless steel tubing. 6.35
mm (V, in.) outside diameter, packed with
glass wool. *
12.1.1.2 Sample Line. »ie inch Inside diam-
eter Teflon tubing heated to 120' C. This
temperature is controlled by a thermostatic
heater.
12.1.1.3 Sample Pump. Leakless Teflon
coated diaphragm type or equivalent. The
pump head is heated to 120° C by enclosing
it in the sample dilution box (12.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system is
given in Figure 15-2. The dilution system is
constructed such that all sample contacts
are made of Inert materials. The dilution
system which is heated to 120* C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below:
12.1.2.1 Dilution Pump. Model A-150 Koh-
myhr Teflon positive displacement type,
nonadjustable 150 cc/mln. ±2.0 percent, or
equivalent, per dilution stage. A 9:1 dilution
of sample is accomplished by combining 150
cc of sample with 1350 cc of clean dry air as
shown in Figure 15-2.
12.1.2.2 Valves. Three-way Teflon solenoid
or manual type.
12.1.2.3 Tubing. Teflon tubing and fittings
are used throughout from the sample probe
to the GC/FPD to present an inert surface
for sample gas.
12.1.2.4 Box. Insulated box, heated and
maintained at 120* C. of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotameters or equiv-
alent to measure flow from 0 to 1500 ml/
mln. ± 1 percent per dilution stage.
12.1.3.0 Gas Chromatograph.
12.1.3.1 Column—1.83 m (6 ft.) length of
Teflon tubing, 2.16 mm (0.085 in.) inside di-
ameter, packed with deactivated silica gel,
or equivalent.
12.1.3.2 Sample Valve. Teflon six port sas
sampling valve, equipped with a 1 ml sample
loop, actuated by compressed air (Figure 15-
1).
12.1.3.3 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100* C, constant within
±TC.
V-261
-------
RULES AND REGULATIONS
12.1.3.4 Temperature Monitor. Thermo-
couple pyrometer to measure column oven.
detector, and exhaust temperature ±1' C.
12.1.3.5 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, oxygen flow and nitrogen carrier gas
flow.
12.1.3.6 Detector. Flame photometric de-
tector.
12.1.3.7 Electrometer. Capable of full scale
amplification of linear ranges of 10"* to 10''
amperes full scale.
12.1.3.8 Power Supply. Capable of deliver-
ing up to 750 volts.
12.1.3.9 Recorder. Compatible with the
output voltage range of the electrometer.
12.1.4 Calibration. Permeation tube
system (Figure 15-3).
12.1.4.1 Tube Chamber. Glass chamber of
sufficient dimensions to house permeation
tubes.
12.1.4.2 Mass Flowmeters. Two mass flow-
meters in the range 0-3 1/min. and 0-10 I/
mln. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate in the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this flow rate as measured
by one flowmeter followed by injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not, then there is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter at
least once each year.
12.1.4.3 Constant Temperature Bath. Ca-
pable of maintaining permeation -tubes at
certification temperature of 30* C within
±0.1'C.
12.2 Reagents.
12.2.1 Fuel. Hydrogen (H,) prepurified
grade or better.
12.2.2 Combustion Gas. Oxygen (O,) re-
search purity or better.
12.2.3 Carrier Gas. Nitrogen (N.) prepuri-
fied grade or better.
12.2.4 Diluent. Air containing less than 0.5
ppm total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons, and filtered using MSA filters
46727 and 79030, or equivalent. Removal of
sulfur compounds can be verified by inject-
ing dilution air only, described in section
8.3.
12.2.5 Compressed Air. 60 psig for GC
valve actuation.
12.2.6 Calibration Gases. Permeation
tubes gravimetrically calibrated and certi-
fied at 30.0* C.
12.3 Operating Parameters. The operating
parameters for the GC/FPD system are as
follows: nitrogen carrier gas flow rate of 100
cc/min, exhaust temperature of 110* C, de-
tector temperature 105* C, oven tempera-
ture of 40' C, hydrogen flow rate of 80 cc/
minute, oxygen flow rate of 20 cc/minute,
and sample flow rate of 80 cc/minute.
12.4 Analysis. The sample valve is actu-
ated for 1 minute in which time an aliquot
of diluted sample is injected onto the sepa-
ration column. The valve is then deactivated
for the remainder of analysis cycle in which
time the sample loop is refilled and the sep-
aration column continues to be foreflushed.
The elution time for each compound will be
determined during calibration.
13. Bibliography
13.1 O'Keeffe. A. E. and G. C. Ortman.
"Primary Standards for Trace Gas Analy-
sis." Anal. Chem. 38,760 (1966).
13.2 Stevens, R. K., A. E. O'Keeffe, and
G. C. Ortman. "Absolute Calibration of a
Flame Photometric Detector to Volatile
Sulfur Compounds at Sub-Part-Per-Mil'ion
Levels." Environmental Science and Tech-
nology 3:7 (July, 1969).
13.3 Mulick, J. D., R. K. Stevens, and R.
Baumgardner. "An Analytical System De-
signed to Measure Multiple Malodorous
Compounds Related to Kraft Mill Activi-
ties." Presented at the 12tn Conference on
Methods in Air Pollution and Industrial Hy-
giene Studies, University of Southern Cali-
fornia, Los Angeles. Calif. April 6-8, 1971.
13.4 Devonald, R. H., R. S. Serenius. and
A. D. Mclntyre. "Evaluation of the Flame
Photometric Detector for Analysis of Sulfur
Compounds." Pulp and Paper Magazine of
Canada. 73,3 (March, 1972).
13.5 Grimley, K. W., W. 3. Smith, and
R. M. Martin. "The Use of a Dynamic Dilu-
tion System in the Conditioning of Stack
Gases for Automated Analysis by a Mobile
Sampiing Van" Presented at the 63rd
Annual APCA Meeting in St. Louis, Mo.
June 14-19, 1970.
13.6 General Reference. Standard Meth-
ods of Chemical Analysis Volume III A and
B Instrumental Methods. Sixth Edition.
Van Nostrand Reinhold Co.
[FR Doc. 78-6633 Filed 3-14-78; 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. 51
WEDNESDAY, MARCH 15, 1978
87
Titl*40-
-Frotoction of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
CFRL 870-4]
PART 60—STANDARDS OF PERFOR-
MANCE FOR NEW STATIONARY
SOURCES
Amendment* to Reference Method*
1-8; Correction
AGENCY: Environmental Protection
Agency.
ACTION: Correction.
SUMMARY: This document corrects
typographical errors to certain Refer-
ence Methods and makes amendments
to others for purposes of clarification.
These Reference Methods were pub-
lished as final rules in the FEDERAL
REGISTER for Thursday, 42 PR 41754,
August 18. 1077, in FR Doc. 77-13608.
EFFECTIVE DATE March 23,1978.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Emission Stan-
dards and Engineering Division
(MD-13). Environmental Protection
Agency, Research Triangle Park,
N.C. 27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
After publication of revisions to Refer-1
ence Methods 1-8 on August 18, 1977,'
we found many typographical errors.
We also received comments which
showed that the procedures to Refer-
ence Methods 1, 4, 6, and 7 needed ad-
ditional clarification or revision. Addi-
tional explanation of the procedure*
to be used are provided by thia correc-
V-262
-------
RULES AND REGULATIONS
Uon notice. In addition to the errors in
the methods themselves, two typo-
graphical errors were discovered In the
preamble. On page 41754, under
"Method 7." the phrase "variable wave
length" is corrected to read "single
and double-beam." On page 41755,
under "Method 8." the word "content"
(in point No. 4) is corrected to read
"components."
ROTB.—The Environmental Protection
Agency tuu determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analy-
sis.
Dated: March 13, 1978.
DAVID A. HAWKINS,
Assistant Administrator
for Air and Waste Management.
Part 60 of Chapter 1, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
APPENDIX A—REFERENCE METHODS
In Method 1 of Appendix A, Sections
2.3.1, 2.3.2, and 2.4 and Table 1-1 are
amended as follows:
1. In Section 2.3.1, the word "adcord-
ing" in the second line is corrected to
read "according."
2. In Section 2.3.2, Insert after the
first paragraph the following:
If the tester desires to use more than the
minimum number of traverse points,
expand the "minimum number of traverse
polnti" matrix (see Table 1-1) by adding the
extra traverse points along one or the other
or both legs of the matrix; the final matrix
need not be balanced. For example, if a 4x3
"minimum number of points" matrix were
expanded to M points, the final matrix
could be 9x4 or 12x3. and would not neces-
sarily have to be 6x6. After constructing the
final matrix, divide the stack cross-section
into as many equal rectangular, elemental
areas as traverse points, and locate a tra-
verse point at the centroid of each equal
area.
3. In Section 2.4, the word "travrse"
in the fifteenth line of the second
paragraph is corrected to read "tra-
verse."
4. In Table 1-1, move the words
"Number of traverse points" to the
left, so that they are centered above
the numbers listed in the left-hand
column. '
In Method 2 of Appendix A, Sections
2.1. 2.2. 2.4. 8.2. 4.1, 4.1.2. 4.1.4.1.
4.1.5.2. and 6 are amended as follows;
1. In Section 2.1, "±" is inserted in
front of the "5 percent" in the four-
teenth line of the third paragraph.
2. In Section 2.2, "measuremen t" In
the next-to-the last line of the first
paragraph is corrected to read "mea-
surement."
3. In Section 2.4, "Type X" in the
fifth line is corrected to read "Type
4. In Section 1.2. "ma" In the first
line is corrected to read "ma-."
5. In Section 4.1, "R," in the seventh
line of the second paragraph is re-
placed with TV"
6. In Section 4.1.2, "B." is inserted
between the words "other," and "Cali-
bration."
7. In Section 4.1.4.1, "Cp(.>=Type S
pDot tube coefficient" is corrected to
read "C^)=Type S pilot tube coeffi-
cient."
8. In Section 4.1.5.2, the words..
"pitot-nozzel" in the third line are cor-
rected to read "pitot-nozzle."
9. In Section 6, Citations 9, 13, and
18 are amended as follows:
a. In No. 9, the word "Tiangle" is
corrected to read "Triangle."
b. In No. 13, the "s" in "Techniques"
is deleted.
c. In No. 18, the word "survey" is
corrected to read "Survey."
In Method 3 of Appendix A. Sections
1.2, 3.2.4. 4.2.6.2. 6.2, and 7 are amend-
ed as follows:
1. In Section 1.2, the title ",TJ. S. En-
vironmental Protection Agency." is in-
serted at the end of the second para-
graph.
2. In Section 3.2.4, "CO" in the tenth
line is corrected to read "CO,."
3. In Section 4.2.6.2(b). the phrase
"or equal to" is inserted between
•than" and "15.0."
4. In Section 6.2, Equation 3-1 is cor-
rected to read as follows:
I 10, - o.s: c»
" 6.2M *~- I'.O - 6.
5. In Section 7, Bibliography, No. 2,
the word "with" is inserted between
the words "Sampling" and "Plastic."
In Method 4 of Appendix A, Sections
2.1.2, 2.2.1. 2.2.3. 2.3.1. 3.1.8, 3.2.1. 3.3.1.
3.3.3. 3.3.4, and Figure '4-2 are amend-
ed as follows:
1. In Section 2.1.2, the word "neasur-
ement" in the third line of the third
paragraph is corrected to read "mea-
surement."
2. In Section 2.2.1. the word
"travers" in the sixth line is corrected
to read "traverse."
3. In Section 2.2.3. the work "eak" in
the last sentence is corrected to read
"leak."
4. In Figure 4-2, the word "ocation"
in the second line on top of the figure.
is corrected to read "Location."
5. In Section 2.3.1. "M." is changed
to read "M." and "P." is changed to
read "p,."
6. In Section 3.1.8, "31 pm" is cor-
rected to read "3 1pm".
7. In Section 3.2.1. delete all of first
paragraph except the first sentence
and insert the following:
Leak check the sampling train as follows:
Temporarily insert a vacuum gauge at or
near the probe Inlet; then, plug the probe
inlet and pull a vacuum of at least 250 mm
Hg (10 In. Hg). Note, the time rate of
change of the dry gas meter dial: alternati-
vely, a rotameter (0-40 cc/mln) may be tem-
porarily attached to the dry gas meter
outlet to determine the leakage rate. A leak
rate not in excess of 2 percent of the aver-
age sampling rate Is acceptable.
NOTE.—Carefully release the probe inlet
plug before turning off the pump.
8. In Section 3.3.1, add the following
definition to the list:
Y=Dry gas meter calibration factor.
Also, "Ow" is corrected to read "?*".
9. In Section 3.3.3, Equation 4-6 is
corrected to read as follows:
Vstd)
10. In Section 3.3.4, Equation 4-7 is
corrected to read as follows:
c(rtd)
•(»«)
• IO.OZ5)
In Method 5 of Appendix A. Sections
2.1.1, 2.2.4, 4.1.2. 4.1.4J. 4.2, 6.1, 6.3,
6.11.1, and 6.11.2 are amended as fol-
lows:
1. In Section 2.1.1, the word "proble"
in the fourth line is corrected to read
"probe."
2. In Section 2.2.4, "polO-" Is correct-
ed to read "poly-".
3. In Section 4.1.2, the sentence
"The sampling time at each point
shall. be the same." is inserted at the
end of the fifth paragraph.
4. In Section 4.1.4.2, the word "It" m
the seventh line is corrected to read
"it."
5. In Section 4.2, the word "nylon"
m the seventh, ninth, and thirteenth
paragraphs is corrected to read
"Nylon."
6. In Section 6.1 Nomenclature,
"C.= Acetone blank residue concentra-
tions, mg/g" is corrected to read
~C.= Acetone blank residue concentra-
tion, mg/g" and "V." is changed to
read "v,."
7. In Section 6.3. page 41782,
"m,= 0.3858 °K/mm Hg for metric
units" is corrected to read "Ki=0 .3658
°K/mm Hg for metric units."
a. In Section 6.11.1, Equation 4-7 is
corrected to read as follows:
*lc * "• Y/V '%«• '
85~L; ~ P JL
™ 1 » Tl
9. In Section 6.11.2, the second form
of Equation 5-6 is corrected to read as
follows:
In Method 6 of Appendix A, Sections
2.1. 2.1.6, 2.1.7, 2.1.8. 2.1.11. 2.1.12,
2.3.2, 3.3.4, 4.1.2, 4.1.3. and 5.1.1 are
amended as follows:
V-263
-------
RULES AND REGULATIONS
1. In Section 2.1, the word "pertox-
Ide" In the fourth line of the second
paragraph te corrected to read "perox-
ide."
2. In Section 2.1.6, the word "siliac"
In the third line Is corrected to read
"silica."
3. In Section 2.1.7, the word "value".
which appears twice is corrected to
read "valve."
4. In Section 2.1.8, the word "diaph-
ragm" is corrected to read "dia-
phragm" and the word "surge" is in-
serted between the words "gma.il" and
"tank."
8. In Section 2.1.11, the word "amer-
old" is corrected to read "aneroid."
6. In Section 2.1.12, the phrase "and
Rotameter." is inserted after the
phrase "Vacuum Gauge" and the
phrase "and 0-40 cc/min rotameter" is
inserted between the words "gauge"
and ", to."
7. In Section 2.3.2, the phrase "and
100-ml size" is corrected to read "and
1000-ml size."
6. In Section 3.3.4, the word "sopro-
panol" in the fourth line is corrected
to read "isopropanol."
». In Section 4.1.2, delete the last
sentence of the last paragraph. Also
delete the second paragraph and re-
place it with the following paragraphs:
Temporarily attach a suitable (.e.g., D-40
ec/mln) rotameter to the outlet of the dry
gas meter and place a vacuum gauge at or
near the probe inlet. Plug the probe Inlet,
pull a vacuum of at least 250 mm He (10 in.
Hg). and note the flow rate as Indicated by
the rotameter. A leakage rate not In excess
ot 2 percent of toe average campling rate is
acceptable.
NOTE: Carefully release the probe Inlet
plug before turning off the pump.
It ic suggested (not mandatory) that the
pump be leak-checked separately, either
prior to or after the sampling run. If done
prior to the sampling run, the pump leak-
check shall precede the leak check of the
•ampllng train described Immediately above;
if done after the sampling run, the pump
leak-check shall follow the train leak-check.
To leak check the pump, proceed as follows:
Disconnect the drying tube from the probe-
Impinger assembly. Place a vacuum gauge at
the inlet to either the drying tube or the
pump, pull a vacuum at 250 mip (10 In.) Hg.
plug or pinch off the outlet of the flow
meter and then turn off the pump. The
vacuum should remain stable for at least 30
seconds.
10. In Section 4.1.3, the sentence "If
a leak is found, void the test run" on
the sixteenth line is corrected to read
"If a'leak Is found, void the test run. or use
procedures acceptable to the Administrator
to adjust the sample volume for the leak-
age."
11. In Section 5.1.1, the word "or" on
the sixth line is corrected to read "of."
In Method 7 of Appendix A, Sections
2.3.2. 2.3.7, 4.2, 4.3, 5.2.1, 5.2.2, 6 and 7
are amended as follows:
1. In Section 2.3.2, a semicolon re-
places the comma between the words
"step" and "the."
2. In Section 2.3.7. the phrase "(one
for each sample)" in the first line -is
corrected to read " working
standard solution (1 ml = 100 jig NO,) to a
series of five 50-ml volumetric flasks. To
each flask, add 25 ml of absorbing solution,
10 ml delonlzed, distilled water, and sodium
hydroxide (IN) dropwise until the pH Is be-
tween B and 12 (about 25 to 35 drop* each).
Dilute to the mark with deionized, distilled
water. Mix thoroughly and pipette a 25-ml
aliquot of each solution into a separate por-
celain evaporating dish.
7. In Section 6.1, the word "Hass" in
the tenth line is corrected to read
"Mass."
8. In Section 7, the word "Vna" in
(1) is corrected to read "Van." The
word "drtermination" in (6) is correct-
ed to read "Determination."
In Method 8 of Appendix A, Sections
1.2, 2.32, 4.1.4, 4.2.1, 4.3.2, 6.1, and 6.7.1
are amended as follows:
1. In Section 1.2, the phrase "U.S.
EPA," is inserted in the fifth line of
the second paragraph between the
words "Administrator," and "are."
Also, delete the third paragraph and
Insert the following:
Filterable paniculate matter may be de-
termined along with SO, and SO, (subject to
the approval of the Administrator) by In-
serting a heated glass fiber filter between
the probe and isopropanol tmpinger (see
Section 2.1 of Method 6). If this option U
chosen, participate analysis Is gravimetric
only: H.SO. acid mist is not determined sep-
arately.
V-264
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RULES AND REGULATIONS
2. In Section 2.3.2, the word "Bur-
rette" is corrected to read "Burette."
3. In Section 4.1.4, the stars "• • •"
are corrected to read as periods ". . .".
4. In Section 4.2.1, the word "net" on
the eighth line of the second para-
graph is corrected to read "the."
5. In Section 4.3.2, the number "40"
is inserted in the fourth line between
the words "Add" and "ml."
6. In Section *6.1, Nomenclature, the
following are corrected to read ai
shown with subscripts "Cv?n*, do*.
V.,,,,."
7. In Section 6.7.1, Equation 8-4 is
corrected to read as follows:
(Sees. 111. 114. 301
-------
QULES
multaneously started on a blow, pro-
duction data should be examined for
such peculiarities before drawing any
conclusions from the opacity data.
Other Issues raised Include the
effect of oxygen "reblows" on the
standard and a request for a more le-
nient monitoring requirement. One in-
dustry commenter claimed that there
would be a "significant" number .of
production cycles with more than one
opacity reading greater than 10 per-
cent due to the blowing of additional
oxygen (after the initial oxygen blow)
into a furnace to obtain the proper
composition. The opacity standard,
however, is based on 73 hours of
SOPF operation during which numer-
ous reblows occurred. It was found
that although the opacities could be
very large at these times, they were of
short enough duration that the six-
minute average was still 10 percent or
less.
EPA agrees with the comment that
the requirement for reporting of in-
stantaneous scrubber differential and
water supply pressures that are'less
than 10 percent of the average main-
tained during the most recent perfor-
mance test needs further clarification.
The requirement has been revised so
that any deviation of more than 10
percent over a three hour averaging
period must be reported. The three
hour averaging period was chosen
since It is the minimum duration of a
performance test. Thus instantaneous
monitoring device measurements
caused by routing process fluctuations
will not be reported. The reports
needed are the periods of time when
the average scrubber pressure drop is
below the level used to demonstrate
compliance at the time of the perfor-
mance test. In addition, the require-
ment for a water pressure monitor has
been retained (despite the comment
that it will not indicate a plugged
water line) since it will perform the
function of assuring that the water
pumps have not shut down. A flow
monitoring device was not specified
because they are susceptible to plug-
ging.
To provide for the use of certain
partial combustion systems on BOPPs,
new requirements have been added to
the monitoring section and two clarifi-
cations added to the test methods and
procedures section. A partial combus-
tion system uses a closed hood to limit
Ijas combustion and exhaust gas vol-
umes. To recover combustible exhaust
erases, the system may be designed to
duct its emissions away from the stack
to a gas holding tank during part of
the steel production cycle. Steel plants
In this country may begin to make
more use of this approach due to its
significant energy benefits. This type
of control/recovery system presents
two problems for enforcement person-
nel. First is the problem of knowing
when the diversion of exhaust gases
from the stack occurs. The new re-
quirements of paragraphs (a), (b)(3),
and (b)(4) of §60.143 address this ques-
tion. Second is the problem of how to
sample or observe stack emissions.
New provisions under §60.144 clarify
this question for determining the
opacity of emissions (paragraph (a)(5))
and for determining the concentration
of emissions (paragraph (c)).
In addition to addressing the prob-
lem posed by exhaust gas diversion,
the new requirements of paragraphs
(a), (b)(3), and (b>(4) of §60.143 ore
also designed to minimty.? errors in re-
cording the time and duration of the
steel production cycle for all types of
BOPPs. Accurate records are essential
for determining compliance with the
opacity standard. Likewise the syn-
chronization of daily logs with the
chart recorders of monitoring devices
is necessary for determining that ac-
ceptable operation and maintenance
procedures are being used as required
by paragraph (d) of §60.11.
An alternative to the manual
method of synchronization under
paragraph (b)(3) of §60.143 which may
minimize costs of this requirement
would be to have the chart recorder
automatically mark the beginning and
end of the steel production cycle and
any period of gas diversion from the
stack. Such marking could be electri-
cally relayed from the production
equipment and exhaust duct damper
operation in order to be fully automat-
ic. Source owners or operators who
wish to employ this method or equiv-
alent methods in lieu of the synchro-
nization procedure prescribed by the
regulations may submit their plans to
the Administrator for approval under
paragraph 60.13(1).
The concentration standard promul-
gated in March, 1874, applies to both
top and bottom-blown BOPPs. In de-
veloping the proposed opacity stan-
dard, data from both types of BOPFs
were considered. Scrubber-controlled
top and bottom-blown BOPPs were
demonstrated capable of meeting the
opacity limits proposed and here pro-
mulgated. Thus the promulgated opac-
ity standard applies to bottom as well
as top-blown BOPPs.
Although there was no announced
intentions to utilize electrostatic preci-
pitators (ESPs) as a control device
(rather than venturi scrubbers),
during the development of the pro-
posed standard, one industry com-
menter asserted that ESPs may
become more attractive in the future.
especially in the semi-arid regions of
the West where the- water and energy
demands of scrubbers are not easily
met. If a BOPF furnace is constructed
with an ESP control device, the estab-
lishment of a site-specific opacity stan-
dard may be necessary. Upon request
by the owner or operator of the BOPF
furnace, a determination will be made
by EPA pursuant to §60.11(e) if per-
formance tests demonstrate compli-
ance with the mass concentration
standard.
MISCELLANEOUS
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Act re-
flect emission limits achievable with
the best adequately demonstrated
technological system of -continuous-
emission reduction (taking into consid-
eration the cost of achieving such
emission reduction, and any aonair
quality health and environmental
impact and energy requirements).
State implementation plans (SIPs) ap-
proved or promulgated under section
110 of the Act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIPs must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173(2) of the Clean Air Act, re-
quires, among other things, that a laew
or modified source constructed in an
area which exceeds the NAAQS must
reduce emissions to the level which re-
flects the "lowest achievable emission
rate" for such category of source,
unless the owner or operator demon-
strates that the source cannot achieve i
such an emission rate. In no event can'
the emission rate exceed any applica-
ble standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
gtructed In a geographic area which
(falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (Part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology. The term "best available con-
trol technology" (BACT) means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facilities through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in ^missions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
V-266
-------
BOLES AMD BS6ULAYIONS
o Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
D more stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty),
costs must be accorded for less weight
In determining the "lowest achievable
emission rate for the new or modified
sources locating in areas violating sta-
tutorily-mandated health and welfare
standards. Although there may be
emission control technology available
that can reduce emissions below the
level required to comply with stan-
dards of performance, this technology
might be selected as the basis of stan-
dards of performance due to costs as-
sociated with its use. This in no way
should preclude Its use in situations
where cost is a lesser consideration,
auch as determination of the "lowest
achievable emission rate." Further-
more, since partial combustion sys-
tems and bottom blown BOPFs have
been shown to be inherently less pol-
luting, more stringent emission limit.*;
may be placed on such sources for the
purposes of defining "best available
control technology" (under Prevention
of Significant Deterioration regula-
tion) and "lowest achievable emission
rate" in non-attainment areas.
In addition, 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 secton 110. Thus,
mew sources may in soSe cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning
SOT such facilities.
The effective date of this regulation
is (date of publication), because sec-
tion lll(bXlXB) of the Clean Air Act
provides that standards of perfor-
mance or revisions thereof become ef-
fective upon promulgation.
The opacity standard, like the con-
centration standard, applies to BOPFs
which commenced construction or
modification after June 11, 1973. That
ts the date on which both standards
were originally proposed. The opacity
standard will add no new control
burden to the sources affected, but
will provide an effective means of
monitoring the compliance of these fa-
cilities. The relief provided under
QSO.lKe) insures that the opacity
standard requires no greater reduction
In emissions than the concentration
standard.
NOTE.—The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analy-
sis under Executive Orders 11821 and 11949
and OMB Circular A-107.
Dated: April 4, 1978.
DOUGLAS M. COSTLE.
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
Subpert W—§9endepdo <=
cneneo for Or@n and Stool
1. Section 30.141 is amended by
adding paragraph (c) as follows:
g 60.141 Definitions.
(c) "Startup means the setting into
operation for the first steel production
cycle of a relined BOPF or a BOPF
which has been out of production for a
minimum continuous time period of
eight hours.
2. Section 60.142 is amended by
adding paragraph (a)(2) as follows:
§ 60.142 Standard for paniculate matter.
-------
89
THIe 40—Protection of Environment
[FRL 882-6]
CHAPTER I—ENVIRONMENTAL
PROTEaiON AGENCY
Sufachaptor C—Air Program*
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Delegation of Authority to State/
Local Air Pollution Control Agen-
cies in Arizona, California, and
Nevada
AGENCY: Environmental Protection
Agency.
ACTION: Final Rulemaking.
SUMMARY: The Environmental Pro-
tection Agency (EPA) is amending 40
CFR 60.4 Address by adding addresses
of agencies to reflect new delegations
of authority from EPA to certain
state/local air pollution control agen-
cies in Arizona, California, and
Nevada. EPA has delegated authority
to these agencies, as described in a
notice appearing elsewhere in today's
FEDERAL REGISTER, in order to imple-
ment and enforce the standards of
performance for new stationary
sources.
EFFECTIVE DATE: May 16, 1978.
FOR FURTHER INFORMATION
CONTACT:
Gerald Katz (E-4-3), Environmental
Protection Agency, 215 Fremont
Street, San Francisco, Calif. 94105,
415-556-8005.
SUPPLEMENTARY INFORMATION:
Pursuant to delegation of authority
for the standards of performance for
new stationary sources (NSPS) to
State/Local air pollution control agen-
cies in Arizona, California, and Nevada
from March 30, 1977 to January 30,
1978. EPA is today amending 40 CFR
60.4 Address, to reflect these actions. A
Notice announcing this delegation is
published elsewhere in today's FEDER-
AL REGISTER. The amended § 60.4 is set
forth below. It adds the address of the
air pollution control agencies, to
which must be addressed all reports,
requests, applications, submittals, and
communications pursuant to this part
by sources subject to the NSPS locat-
ed within these agencies' jurisdictions.
The Administrator finds good cause
for foregoing prior public notice and
for making this rulemaking effective
Immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional substantive
burdens are imposed on the parties af-
fected. The delegation actions which
are reflected in this administrative
amendment were effective on the
RULES AND REGULATIONS
dates of delegation and it serves no
purpose to delay the technical change
on these additions of the air pollution
control agencies' addresses to the
Code of Federal Regulations.
(Sec. Ill, Clean Air Act. as amended (42
U.S.C.7411).>
Dated: April 5,1978.
SHEILA M. PRINDIVILLE, .
Acting Regional Administrator,
Environmental Protection
Agency, Region IX.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraphs D, F, and
DD to read as follows:
§60.4 Address.
• • • • •
(b)"*
(D) Arizona:
Marlcopa County Department of Health
Services, Bureau of Air Pollution Control,
1825 East Roosevelt Street, Phoenix, AZ
85006.
Pima County Health Department, Air
Quality Control District. 151 West Congress,
Tucson, AZ 85701.
• * • • • •
(P) California:
Bay Area Air Pollution Control District,
939 Ellis Street, San Francisco. CA 94109.
Del Norte County Air Pollution Control
District. Courthouse, Crescent .City. CA
95531.
Fresno County Air Pollution Control Dis-
trict, 515 S. Cedar Avenue. Fresno. CA
93702.
Humboldt County Air Pollution Control
District. 5600 S. Broadway. Eureka, CA
95501.
Kern County Air Pollution Control Dis-
trict, 1700 Flower Street (P.O. Box 997), Ba-
kersfield, CA 93302.
Madera County Air Pollution Control Dis-
trict. 135 W. Yosemite Avenue. Madera, CA
93637.
Mendoctno County Air Pollution Control
District, County Courthouse, Ukiah, CA
94582.
Monterey Bay Unified Air Pollution Con-
trol District. 420 Church Street (P.O. Box
487). Salinas. CA 93901.
Northern Sonoma County Air Pollution
Control District. 3313 Chanate Road, Santa
Rosa. CA 95404.
Sacramento County Air Pollution Control
District, 3701 Branch Center Road, Sacra-
mento, CA 95827.
San Diego County Air Pollution Control
District, 9150 Chesapeake Drive, San Diego.
CA 92123.
San Joaquln County Air Pollution Control
District. 1601 E. Hazelton Street (P.O. Box
2009), Stockton. CA 95201.
Santa Barbara County Air Pollution Con-
trol District, 4440 Calle Real, Santa Bar-
bara, CA 93110.
Shasta County Air Pollution Control Dis-
trict, 1855 Placer Street, Redding. CA 96001.
South Coast Air Quality Management Dis-
trict, 9420 Telstar Avenue. El Monte, CA
91731.
Stanislaus County Air Pollution Control
District, 820 Scenic Drive, Modesto,'-CA
95350.
Trinity County Air Pollution Control Dis-
trict. Box AJ, Weaverville. CA 96093.
Ventura County Air Pollution Control
District, 625 E. Santa Clara Street. Ventura,
CA 93001.
. • » • •
(DD) Nevada:
Nevada Department of Conservation and
Natural Resources, Division of Environmen-
tal Protection, 201 South Fall Street,
Cmrson City. NV 89710.
Clark County County District Health De-
partment. Air Pollution Control Division,
625 Shadow Lane, Las Vegas, NV 89106.
Washoe County District Health Depart-
ment, Division of Environmental Protection,
10 Klrman Avenue. Reno, NV 89502.
• • • . • . •
tPR Doc. 78-13011 Filed 5-15-78: 8:45 am]
KDEKAl ItOISTft, VOL 43, NO. H
TUESDAY, MAY 16, 197»
V-268
-------
TOo 4®—Pf-@fleefli©ia ®AaB>S ©I?
MEW IYATOMAEY
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: The standards limit emis-
sions of particulate matter from new,
modified, and reconstructed grain ele-
vators. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from grain elevators contrib-
ute significantly to air pollution. The
Intended effect of these standards is to
require new, modified, and recon-
structed grain elevators to use the best
demonstrated system of continuous
emission reduction, considering costs,
nonair quality health, environmental
and energy impacts.
EFFECTIVE DATE: August 3, 1978.
ADDRESSES: Copies of the standards
support documents are available on re-
quest from the U.S. EPA Library
(MD-35), Research Triangle Park,
N.C. 27711, telephone 919-541-2777 or
(FTS) 629-2777. The requester should
specify "Standards Support and Envi-
ronmental Impact Statement, Volume
1: Proposed Standards of Performance
for Grain Elevator Industry," (EPA-
450-77-OOla) and/or "Standards Sup-
port and Environmental Impact State-
ment, Volume 2: Promulgated Stand-
ards of Performance for Grain Eleva-
tor Industry," (EPA-450/2-77-001b).
Copies of all comment letters received
from interested persons participating
In this rulemaking are available for in-
spection and copying during normal
business hours at EPA's Public Infor-
mation Reference Unit, Room 2922,
EPA Library, 401 M Street SW., Wash-
ington, D.C.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director Emission
Standards and Engineering Division
(MD-13). Environmental Protection
Agency, Research Triangle Park,
N.C. 27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On January 13, 1977, standards of per-
formance were proposed for the grain
elevator industry (42 FR 2842) under
the authority of section 111 of the
Clean Air Act. Public comments were
requested on the proposal in the FED-
ERAL REGISTER publication. Approxi-
mately 2,000 comments were received
from grain elevator operators, vendors
of equipment. Congressmen, State and
local air pollution control agencies,
other Federal agencies, and individual
U.S. citizens. Most of these comments
reflected a general misunderstanding
of the proposed standards and were
very general in nature. A number of
comments, however, contained a sig-
nificant amount of useful data and in-
formation. Due to the time required to
review these comments, the standards
were suspended on June 24, 1977. This
action was necessary to avoid creating
legal uncertainties for those grain ele-
vator operators wb.o might have un-
dertaken various expansion or alter-
ation projects before promulgation of
final standards.
On August 7, 1977, Congress amend-
ed the Clean Air Act. These amend-
ments contained a provision specifical-
ly exempting country grain elevators
with less than 2.5 million bushels of
grain storage capacity from standards
of performance developed under sec-
tion 111 of the Act.
Following review of the public com-
ments, a draft of the final standards
was developed consistent with the
adopted amendments to the Clean Air
Act. A report responding to the major
issues raised in the public comments
and containing the draft final stand-
ards was mailed on August 15, 1977, to
each individual, agriculture associ-
ation, equipment vendor. State and
local government, and member of Con-
gress who submitted comments. Com-
ments were requested on the draft
final standards by October 15, 1977.
One hundred comments were received,
and the final standards reflect a thor-
ough evaluation of these comments.
The proposed standards are reinstat-
ed elsewhere in this issue of the FED-
ERAL REGISTER.
THE STANDARDS
The promulgated standards apply
only to new, modified, or reconstruct-
ed grain elevators with a permanent
grain storage capacity of more than
88.100 m • (ca. 2.5 million U.S. bushels)
and new, modified, or reconstructed
grain storage elevators at wheat flour
mills, wet corn mills, dry corn mills
(human consumption), rice mills, or
soybean oil extraction plants with &
permanent grain storage capacity of
more than 35.200 m' (ca. 1 million
U.S. bushels).
The standards limit participate
matter emissions from nine types of
affected facilities at grain elevators by
limiting the visibility of emissions re-
leased to the atmosphere. The affect-
ed facilities are each truck loading sta-
tion, truck unloading station, rail car
loading station, railcar unloading sta-
tion, barge or ship loading station,
barge or ship unloading station, grain
dryer, all grain handling operations
and each emission control device.
The standards can be summarized as
follows:
(a) Truck loading station—visible
emissions may not exceed 10 percent
opacity.
(b) Truck unloading station, railcar
loading station, and railcar unloading
station—visible emissions may not
exceed 5 percent opacity.
(c) Ship or barge loading station-
visible emissions may not exceed 20
percent opacity.
(d) Ship or barge unloading station-
specified equipment or its equivalent
must be used.
(e) Grain dryer—visible emissions
may not exceed 0 percent opacity.
(f) All pain handling operations-
visible emissions may not exceed 0 per-
cent opacity.
(g) Emission control devices—visible
emissions may not exceed 0 percent
opacity; and the concentration of par-
ticulate matter In the exhaust gas dis-
charged to the atmosphere may not
exceed 0.023 g/dscm (ca. 0.01 pr/dscf).
These standards are different from
those proposed in the following areas.
The visible emission limits for truck
unloading stations and railcar loading
and unloading stations have been in-
creased from 0 .percent opacity to 5
percent opacity. The visible emission
limit for barge and ship loading has
been increased from 10 percent opac-
ity during normal loading and 15 per-
cent opacity during "topping off" load-
ing, to 20 percent opacity during all
loading operations. The applicability
of the visible emission standards for
column grain dryers has been nar-
rowed from dryers with perforated
plate hole sizes of greater than 0.084
Inch diameter to dryers with perforat-
ed plate hole sizes of greater than
0.094 inch diameter.
The August 1977 amendments to the
Clean Air Act authorize the promulga-
tion of design, equipment, work prac-
tice, or operational standards if devel-
opment of a numerical emission limit
is not feasible. Numerical emission
limits may not be feasible where emis-
sions are not confined or where emis-
sions cannot be measured due to tech-
nological or economic limitations. Ob-
servation of visible emissions at barge
unloading stations led to the conclu-
sion that a numerical emission limit is
not feasible for this facility. The visi-
ble emissions data showed an extreme-
ly wide range with some 6 minute
averages above 65 percent opacity. Be-
cause of this wide range of visible
emissions, an opacity numerical emis-
sion limit cannot be established that
would ensure the use of the best
V-269
-------
RULES AND REGULATIONS
system of continuous emission reduc-
tion. An equipment standard, there-
fore, rather than an emission standard
is being promulgated for barge and
ship unloading stations.
Another change from the proposed
standards is that section 60.14 (modifi-
cation) of the general provisions has
been clarified to ensure that only capi-
tal expenditures which are spent di-
rectly on an affected facility are used
to determine whether the annual asset
guideline repair allowance percentage
is exceeded. The annual asset guide-
line repair allowance percentage has
been defined to be 6.5 percent.
The remaining change from the pro-
posed standards is that four types of
alterations at grain elevators have
been exempted from consideration as
modifications. The exempted alter-
ations are:
(1) The addition of gravity load-out
spouts to existing grain storage or
grain transfer bins.
(2) The installation of automatic
grain weighing scales.
(3) Replacement of motor and drive
units driving existing grain handling
equipment.
(4) The installation of permanent
storage capacity with no increase in
hourly grain handling capacity.
ENVIRONMENTAL AND ECONOMIC IMPACTS
The promulgated standards will
reduce uncontrolled particulate.
matter emission from new grain eleva-
tors by more than 99 percent and will
reduce particulate matter emissions by
70 to 90 percent compared to emission
limits contained in State or local air
pollution regulations. This reduction
in emissions will result In a significant
reduction of ambient air concentration
levels of particulate matter in the vi-
cinity of grain elevators. The maxi-
mum 24-hour average ambient air par-
ticulate matter concentration at a dis-
tance of 0.3 kilometer (km) from a
typical grain elevator, for example,
will be reduced by 50 to 80 percent
below the ambient air concentration
that would result from control of
emissions to the level of the typical
State or local air pollution regulations.
Several of the changes to the pro-
posed standards reduce the estimated
primary impact of the proposed stand-
ards in terms of reducing emissions of
particulate matter from grain eleva-
tors. The promulgated standards, for
example, apply only to large grain ele-
vators. These changes will permit
more emissions of particulate matter
to the atmosphere. It was estimated
that the proposed standards would
have reduced national particulate
matter emissions by approximately
21,000 metric tons over the next 5
years; it is now estimated that the pro-
mulgated standards will reduce partic-
ulate matter emissions by 11,000
metric tons over the next 5 years.
The secondary environmental Im-
pacts associated with the promulgated
standards will be a small increase in
solid waste handling and disposal and
a small Increase in noise pollution. A
relatively minor amount of particulate
matter, sulfur dioxide and nitrogen
oxide emissions will be discharged into
the atmosphere from steam/electric
power plants supplying the additional
electrical energy required to operate
the emission control devices needed to
comply with the promulgated stand-
ards. The energy impact associated
with the promulgated standards will
be small and will lead to an Increase In
national energy consumption in 1981
by the equivalent of only 1,600 m' (ca.
10,000 barrels) per year of No. 6 fuel
oil.
Based on information contained in
the comments submitted during the
public comment periods, approximate-
ly 200 grain terminal elevators and
grain storage elevators at grain pro-
cessing plants will be covered by the
promulgated standards over the next 5
years. The total incremental costs re-
quired to control emissions at these
grain elevators to comply with the
promulgated standards, above the
costs necessary to control emissions at
these elevators to comply with State
or local air pollution control regula-
tions, is $15 million in capital costs
over this 5-year period and (3 million
in annualized costs in the fifth year.
Based on this estimate of the national
economic Impact, the promulgated
standards will have no significant
effect on the supply and demand for
grain products, or on the growth of
the domestic grain Industry.
PUBLIC PARTICIPATION
Prior to proposal of the standards,
Interested parties were advised by
public notice In the FEDERAL REGISTER
of a meeting of the National Air Pollu-
tion Control Techniques Advisory
Committee. In addition, copies of the
proposed standards and the Standards
Support and Environmental Impact
Statement (SSEIS) supporting these
standards were distributed to members
of the grain elevator industry and sev-
eral environmental groups at the time
of proposal. The public comment
period extended from January 13, to
May 14, 1977. During this period 1,817
comments were received from grain
elevator operators, vendors of equip-
ment. Congressmen, State and local
air pollution control agencies, other
Federal agencies, and individual U.S.
citizens.
Due to the time required to review
these comments, the proposed stand-
ards were suspended on June 24, 1977.
This action was necessary to avoid cre-
ating legal uncertainties for those
grain elevator operators who might
have undertaken various expansion or
alteration projects before promulga-
tion of final standards.
Following review of the public com-
ments, a draft of the final standards
was developed consistent with the
August, 1977, amendments to the
Clean Air Act. A report responding to
the major issues raised in the public
comments and containing the draft
final standards was mailed on August
15, 1977, to each Individual, agricul-
ture association, equipment vendor,
State and local government, and
member of Congress who submitted
comments. Comments were requested
on the draft final standards by Octo-
ber 15, 1977.
One hundred and one comments
were received and the final standards
reflect a thorough evaluation of these
comments. Several comments resulted
in changes to the proposed standards.
A detailed discussion of the comments
and changes made to the proposed
standards is contained in volume 2 of
the SSEIS, which was distributed
along with a copy of the final stand-
ards to all Interested parties prior to
today's promulgation of final stand- •
ards.
SIGNIFICANT COMMENTS
Most of the comment letters re-
ceived by EPA contained multiple
comments. The most significant com-
ments and changes made to the pro-
posed standards are discussed below:
NEED FOR STANDARDS
Numerous commenters questioned
whether grain elevators should be reg-
ulated since the industry is a small
contributor to nationwide emissions of
particulate matter and grain dust is
not hazardous or toxic.
The standards were proposed under
section 111 of the Clean Air Act. This
section of the act requires that stand-
ards of performance be established for
new stationary sources which contrib-
ute to air pollution. Existing sources
are not affected unless they are recon-
structed, or modified in such a way as
to increase emissions. The overriding
purpose of standards of performance
is to prevent new air pollution prob-
lems from developing by requiring
maximum feasible control of emissions
from new, modified, or reconstructed
sources at the time of their construc-
tion. This is helpful in attaining and
maintaining the National Ambient Air
Quality Standard INAAQS) for sus-
pended particulate matter.
The Report of the Committee on
Public Works of the United States
Senate in September 1970 (Senate
Report No. 91-1196), listed grain eleva-
tors as a source for which standards of
performance should be developed. In
addition, a study of 200 industrial cat-
V-270
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RULES AND REGULATIONS
egorles of sources, which were evaluat-
ed to develop a long-range plan for set-
ting standards of performance for par-
ticulate matter, ranked grain elevators
relatively high. The categories were
ranked in order of priority based on
potential decrease in emissions. Var-
ious grain handling operations ranked
as follows: Grain processing—4; grain
transfer—6; grain cleaning and screen-
Ing—8; and grain drying—33. There-
fore, grain elevators are a significant
source of participate matter emissions
and standards of performance have
been developed for this source catego-
ry.
Many commenters felt, however,
that it was unreasonable to require
small country elevators to comply with
the proposed standards because of
their remote location and small
amount of emissions. This sentiment
was reflected in the 1977 amendments
to the Clean Air Act which exempted
country elevators with a grain storage
capacity of less than 88,100 m ' (ca. 2.5
million U.S. bushels) from standards
of performance. Consequently, the
scope of the proposed standards has
been narrowed and the promulgated
standards apply only to new, modified,
or reconstructed faculties within grain
elevators with a permanent storage ca-
pacity in excess of 88,100 m '.
A number of commenters also felt
small flour mills should not be covered
by standards of performance because
they are also small sources of particu-
late matter emissions and handle less
grain than some country elevators
which were exempted from standards
of performance by the 1977 amend-
ments to the Clean Air Act. These pro-
cessors are considered to be relatively
small sources of particulate matter
emissions that are best regulated by
State and local regulations. Conse-
quently, grain storage elevators at
wheat flour mills, wet corn mills, dry
corn mills (human consumption), rice
mills, and soybean oil extraction
plants with a storage capacity of less
than 35.200 m» (ca. 1 million U.S.
bushels) of grain are exempt from the
promulgated standards.
With regard to the hazardous nature
or toxicity of grain dust, the promul-
gated standards should not be inter-
preted to imply that grain dust is con-
sidered hazardous or toxic, but merely
that the grain elevator industry is con-
sidered a significant source of particu-
late matter emissions. Studies Indicate
that, as a general class, particulate
matter causes adverse health and wel-
fare effects. In addition, some studies
indicate that dust from grain elevators
causes adverse health effects to eleva-
tor workers and that grain dust emis-
sions are a factor contributing to an
increased incidence of asthma attacks
in the general population living In the
vicinity of grain elevators.
EMISSION CONTROL TECHNOLOGY
A number of commenters were con-
cerned with the reasonableness of the
emission control technology which was
used as the basis for the proposed
standards limiting emissions from rail-
car unloading stations and grain
dryers.
A number of commenters believed it
was unreasonable to base the stand-
ards on a four-sided shed to capture
emissions from railcar unloading sta-
tions at grain elevators which use unit
trains. The data supporting the pro-
posed standards were based on obser-
vations of visible emissions at a grain
elevator which used this type of shed
to control emissions from the unload-
ing of railcars. This grain elevator,
however, did not use unit trains. Based
on information included in a number
of comments, the lower rail rate for
grain shipped by unit trains places a
limit on the amount of time a grain
elevator can hold the unit train. The
additional time required to uncouple
and recouple each car Individually
could cause a grain elevator subject to
the proposed standards to exceed this
time limit and thus lose the cost bene-
fit gained by the use of unit trains. In
light of this fact, the proposed visible
emission limit for railcar unloading is
considered unreasonable. The promul-
gated standards, therefore, are based
upon the use of a two-sided shed for
railcar unloading stations. This
change in the control technology re-
sulted in a change to the visible emis-
sion limit for railcar unloading sta-
tions and is discussed later.
A number of comments were re-
ceived concerning the proposed stand-
ard for column dryers. The proposed
standards would have permitted the
maximum hole size in the perforated
plates used in column dryers to be no
larger than 2.1 mm (0.084 inch) in di-
ameter for the dryer to automatically
be in compliance with the standard. A
few comments contained visible emis-
sion data taken by certified opacity ob-
servers which Indicated that column
dryers with perforated plates contain-
ing holes of 2.4 mm (0.094 inch) diame-
ter could meet a 0-percent opacity
emission limit. Other comments Indi-
cated that sorghum cannot be dried in
column dryers with a hole size smaller
than 2.4 mm (0.094 inch) diameter
without plugging problems. In light of
these data and information, the speci-
fication of 2.1 mm diameter holes is
considered unreasonable and the pro-
mulgated standards apply only to
column dryers containing perforated
plates with hole sizes greater than 2.4
mm in diameter.
STRINGENCY OF THE STANDARDS
Many commenters . questioned
whether the standards for various af-
fected facilities could be achieved even
if the best system of emission reduc-
tion were Installed, maintained, and
properly operated. These commenters
pointed out that a number of variables
can affect the opacity of visible emis-
sions during unloading, handling, and
loading of grain and they questioned
whether enough opacity observation
had been taken to assure that the
standards could be attained under all
operating conditions. The variables
mentioned most frequently were wind
speed and type, dustiness, and mois-
ture content of grain.
It is true that wind speed could have
some effect on the opacity of visible
emissions. A well-designed capture
system should be able to compensate
for this effect to a certain extent, al-
though some dust may escape if wind
speed is too high. Compliance with
standards of performance, however, is
determined only under conditions rep-
resentative of normal operation, and
judgment by State and Federal en-
forcement personnel will take wind
conditions into account in enforcing
the standards.
It is also true that the type, dusti-
ness, and moisture content of grain
affect the amount of particulate
matter emissions generated during un-
loading, handling, and loading of
grain. A well-designed capture system,
however, should be designed to cap-
ture dust under adverse conditions and
should, therefore, be able to compen-
sate for these variables.
In developing the data base for the
proposed standards, over 60 plant
visits were made to grain terminal and
storage elevators. Various grain un-
loading, handling, and loading oper-
ations were inspected under a wide va-
riety of conditions. Consequently, the
standards were not based on conjec-
ture or surmise, but on observations of
visible emissions by certified opacity
observers at well-controlled existing
grain elevators operating under rou-
tine conditions. Not all grain elevators
were visited, however, and not all op-
erations within grain elevators were
Inspected under all conditions. Thus,
while the proposed standards were
based upon a sufficiently broad data
base to allow extrapolation of the
data, particular attention was paid to
those comments submitted during the
public comment period which included
visible emission data taken by certified
observers from operations at grain ele-
vators which were using the same
.emission control systems the proposed
standards were based upon. Evaluation
of these data indicates that the visible
emission limit for truck unloading sta-
tions and railcar loading stations
should be 5 percent opacity instead of
0 percent opacity which was proposed.
The promulgated standards, therefore,
limit visible emissions from these fa-
cilities to 5 percent opacity.
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IULES AND tEGULATlONS
As discussed earlier, the emission
control technology selected as the
basis for the visible emissions standard
for rail car unloading has been
changed from a four-sided shed to a
two-sided shed. Visible emission data
Included with the public comments in-
dicate that emissions from a two-sided
shed will not exceed 5 percent opacity.
Consequently, the promulgated stand-
ards limit visible emissions from rail-
car unloading stations to 5 percent
opacity.
A number of commenters also indi-
cated that the opacity limit Included
in the proposed standards for barge
loading was too stringent. One com-
menter indicated that the elevator op-
erator had no control over when the
"topping off" operation commenced
because the ship captain and the ste-
vedores decide when to start "topping
off." Several State agencies comment-
ed that the standards should be at
least 20 percent opacity. Based on
these comments, the standards for
barge and ship loading operations
have been increased to 20 percent
opacity during all loading operations.
The comments indicate that this
standard will still require use of the
emission control technology upon
which the proposed standards were
based.
Data included with the public com-
ments confirm that a visible emission
limit of 0 percent opacity is appropri-
ate for grain -handling equipment,
grain dryers, and emission control
equipment. Consequently, the visible
emission limits for these facilities have
not been changed.
OPACITY
Many commenters misunderstood
the concept of opacity and how it is
used to measure visible emissions.
Other commenters stated that opacity
measurements were not accurate
below 10 to 15 percent opacity and a
standard below these levels was unen-
forceable.
Opacity is a measure of the degree
to which particulate matter or other
visible emissions reduce the transmis-
sion of light and obscure the view of
an object in the background. Opacity
is expressed on a scale of 0 to 100 per-
cent with a totally opaque plume as-
signed a value of 100 percent opacity.
The concept of opacity has been used
in the field of air pollution control
since the turn of the century. The con-
cept has been upheld in courts
throughout the country as a reason-
able and effective means of measuring
visible emissions.
Opacity for purposes of determining
compliance with the standard is not
determined with Instruments but is de-
termined by a qualified observer fol-
lowing a specific procedure. Studies
have demonstrated that certified ob-
servers can accurately determine the
opacity of visible emissions. To become
certified, an Individual must be trained
and must pass an examination demon-
strating his ability to accurately assign
opacity levels to visible emissions. To
remain certified, this training must be
repeated every 6 months.
In accordance with method 9, the
procedure followed in making opacity
determinations requires that an ob-
server be located in a position where
he has a clear view of the emission
source with the sun at his back. In-
stantaneous opacity observations are
recorded every 15 seconds for 6 min-
utes (24 observations). These observa-
tions are recorded in 5 percent Incre-
ments (i.e., 0, 5. 10, etc.). The arithme-
tic average of the 24 observations,
rounded off to the nearest whole
number (i.e., 0.4 would be rounded off
to 0), is the value of the opacity used
for determining compliance with visi-
ble emission standards. Consequently,
a 0 percent opacity standard does not
necessarily mean there are no visible
emissions. It means either that visible
emissions during a 6-minute period are
not sufficient to cause a certified ob-
server to record them as 5 percent
opacity, or that the average of the
twenty-four 15-second observations is
calculated to be less than 0.5 percent.
Consequently, although emissions re-
leased into the atmosphere from an
emission source may be visible to a
certified observer, the source may still
be found in compliance with a 0 per-
cent opacity standard.
Similarly, a 5-percent opacity stand-
ard permits visible emissions to exceed
5 percent opacity occasionally. If, for
example, a certified observer recorded
the following twenty-four 15-second
observations over a 6-minute period: 7
observations at 0 percent opacity; 11
observations at 5 percent opacity; 3 ob-
servations at 10 percent opacity; and 3
observations at 15 percent opacity, the
average opacity would be calculated as
5.4 percent. This value would be
rounded off to 5 percent opacity and
the source would be in compliance
with a 5 percent opacity standard.
Some of the commenters felt the
proposed standards were based only on
one 6-minute reading of the opacity of
visible emissions at various grain ele-
vator facilities. None of the standards
were based on a single 6-minute read-
ing of opacity. Each of the standards
were based on the highest opacity
readings recorded over a period of
time, such as 2 or 4 hours, at a number
of grain elevators.
A number of commenters also felt
the visible emission standards were too
stringent in light of the maximum ab-
solute error of 7.5 percent opacity as-
sociated with a single opacity observa-
tion. The methodology used to develop
and enforce visible emission standards,
however, takes into account this ob-
server error. As discussed above, visi-
ble emission standards are based on
observations recorded by certified ob-
servers at well-controlled existing fa-
cilities operating under normal condi-
tions. When feasible, such observa-
tions are made under conditions which
yield the highest opacity readings
such as the use of a highly contrasting
background. These readings then
serve as the basis for establishing the
standards. By relying on the highest
observations, the standards inherently
reflect the highest positive error Intro-
duced by the observers.
Observer error is also taken into ac-
count In enforcement of visible emis-
sion standards. A number of observa-
tions are normally made before an en-
forcement action is initiated. Statisti-
cally, as the number of observations
increases, the error associated with
these observations taken as a group
decreases. Thus, while the absolute
positive error associated with a single
opacity observation may be 7.5 per-
cent, the error associated with a
•number of opacity observations, taken
to form the basis for an enforcement
action, may be considerably less than
7.5 percent.
ECONOMIC IMPACT
Several commenters felt the estimat-
ed economic impact of the proposed
standards was too low. Some com-
menters questioned the ventilation
flow rate volumes used in developing
these estimates. The air evacuation
flow rates and equipment costs used in
estimating the costs associated with
the standards, however, were based on
information obtained from grain ele-
vator operators during visits to facili-
ties which were being operated with
visible emissions meeting the proposed
standards. These air evacuation flow
rates and equipment costs were also
checked against equipment vendor es-
timates and found to be in reasonable
agreement. These ventilation flow
rates, therefore, are compatible with
the opacity standards. Thus, the unit
cost estimates developed for the pro-
posed standards are considered reason-
ably accurate.
Many commenters felt that the total
cost required to reduce emissions to
the levels necessary to comply with
the visible emission standards should
be assigned to the standards. The rele-
vant costs, however, are those Incre-
mental costs required to comply with
these standards above the costs re-
quired to comply with existing State
or local air pollution regulations.
While it is true that some States have
no regulations, other States have regu-
lations as stringent as the promulgat-
ed standards. Consequently, an esti-
mate of the costs required to comply
with the typical or average State regu-
V-272
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•ULES AND REGULATIONS
lation. which lies between these ex-
tremes, is subtracted from the total
cost of complying with the standards
to identify the cost Impact directly as-
sociated with these standards.
Most State and local regulations, for
example, require asprlation of truck
dump pit grates and Installation of cy-
clones to remove partlculate matter
from the aspirated air before release
to the atmosphere. The promulgated
standards would require the addition
of a bifold door and the use of a fabric
filter baghouse Instead of a cyclone.
The cost associated with the promul-
gated standards, therefore. Is only the
cost of the bifold doors and the differ-
ence in cost between a fabric filter
baghouse and a cyclone.
In conclusion, the unit cost esti-
mates developed for the proposed
standards are essentially correct and
generally reflect the costs associated
with the promulgated standards. As a
result, the economic Impact of the pro-
mulgated standards on an Individual
grain elevator is considered to be
about the same as that of the pro-
posed standards. The maximum addi-
tional cost that would be imposed on
most grain elevators subject to compli-
ance with the promulgated standards
will probably be less than a cent per
bushel. The impact of these additional
costs imposed on an individual grain
elevator will be small.
Based on information contained in
comments submitted by the National
Grain and Feed Association, approxi-
mately 200 grain terminal elevators
and grain storage elevators at grain
processing plants will be covered by
the standards over the next 5 years.
Consequently, over this 5-year period
the total incremental costs to control
emissions at these grain elevators to
comply with the promulgated stand-
ards, above the costs to control emis-
sions at these elevators to comply with
State or local air pollution control re-
quirements, is $15 million in capital
costs and $3 million in annualized
costs in the 5th year. Based on this es-
timate of the national economic
impact, the promulgated standards
will have no significant effect on the
supply and demand of grain or grain
products, or on the growth of the do-
mestic grain Industry.
ENERGY IMPACT
A number of commenters believed
that the energy impact associated with
the proposed standards had been un-
derestimated and that the true impact
would be much greater. As pointed out
above, the major reason for this dis-
agreement is probably due to the fact
that these commenters assigned the
full impact of air pollution control to
the proposed standards, whereas the
impact associated with compliance
with existing State and local air pollu-
tion control requirements should be
subtracted. In the example discussed
above concerning costs, the additonal
energy requirements associated with
the promulgated standards is simply
the difference in energy required to
operate a fabric filter baghouse com-
pared to a cyclone.
For emission control equipment such
as cyclones and fabric filter bag
houses, energy consumption is directly
proportional to the pressure drop
across the equipment. It was assumed
that the pressure drop across a cy-
clone required to comply with existing
State and local requirements would be
about 80 percent of that across a
fabric filter baghouse required to
comply with tlje promulgated stand-
ards. This is equivalent to an increase
in energy consumption required to op-
erate air pollution control equipment
of about 25 percent. This represents
an increase of less than 5 percent In
the totl energy consumption of a grain
elevator.
Assuming 200 grain elevators
become subject to the promulgated
standards over the next 5 years, this
energy Impact will increase national
energy consumption by less than 1,600
m» (ca. 10,000 U.S. barrels) per year in
1982. This amounts to less than 2 per-
cent of the capacity of a large marine
oil tanker and is an insignificant in-
crease in energy consumption.
MODIFICATION
Many commenters were under the
mistaken Impression that all existing
grain elevators would have to comply
with the proposed standards and that
retrofit of air pollution control equip-
ment on existing facilities within grain
elevators would be required. This is
not the case. The proposed standards
would have applied only to new. modi-
fied, or reconstructed facilities within
grain elevators. Similarly, the promul-
gated standards apply only to new.
modified, or reconstructed facilities
and not existing facilities.
Modified facilities are only subject
to the standards If the modification
results in increased emissions to the
atmosphere from that facility. Fur-
thermore, any alteration which is con-
sidered routine maintenance or repair
is not considered a modification.
Where an alteration Is considered a
modification, only those 'facilities
which are modified have to comply
with the standards, not the entire
grain elevator. Consequently, the
standards apply only to major alter-
ations of individual facilities at exist-
ing grain elevators which result in in-
creased emissions to the atmosphere.
not to alterations which are consid-
ered routine maintenance and repair.
Major alterations that do not result in
increased emissions, such as alter-
ations where existing air pollution
control equipment is upgraded to
maintain emissions at their previous
level, are not considered modifications.
The following examples illustrate
how the promulgated standards apply
to a grain elevator under various cir-
cumstances. The proposed standards
would have applied in the same way.
(1) If a completely new grain eleva-
tor were built, all affected facilities
would be subject to the standards.
(2) If a truck unloading station at an
existing grain elevator were modified
by making a capital expenditure to in-
crease unloading capacity and this re-
sulted In increased emissions to the at-
mosphere In terms of pounds per
hour, then only that affected facility
(1. e., the modified truck unloading sta-
tion) would be subject to the stand-
ards. The remaining facilities within
the grain elevator would not be sub-
ject to the standards.
(3) if a grain elevator' contained
three grain dryers and one grain dryer
were replaced with a new grain dryer,
only the new grain dryer would be
subject to the standards.
The initial assessment of the poten-
tial for modification of existing facili-
ties concluded that few modifications
would occur. The few modifications
that were considered likely to take
place would involve primarily the up-
grading of existing country grain ele-
vators into high throughput grain ele-
vator terminals. A large number of
commenters, however, indicated that
they believed many modifications
would occur and that many existing
grain elevators would be required to
comply with the standards. .
To resolve this confusion and clarify
the meaning of modification, a meet-
ing was held with representatives of
the grain elevator industry to identify
various alterations to existing facilities
that might be considered modifica-
tions. A list of alterations was devel-
oped which frequently occur within
grain elevators, primarily to reduce
labor costs or to Increase grain han-
dling capacity, although not necessar-
ily annual grain throughput. The
Impact of considering four of these al-
terations as modifications, subject to
compliance with the standards, was
viewed as unreasonable. Consequently,
they are exempted from consideration
as modifications in the promulgated
standards.
In particular, the four alterations
within grain elevators which are spe-
cifically exempt from the promulgate^
standards are (1) The addition of grav-
ity load-out spouts to existing grain
storage or grain transfer bins; (2) the
addition of electronic automatic grain
weighing scales which increases
hourly grain handling capacity; (3) the
replacement of motors and drive trains
driving existing grain handling equip-
ment with larger motors and drive
V-273
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RULES AND REGULATIONS
trains which increases hourly grain
handling capacity; and (4) the addition
of grain storage capacity with no in-
crease in hourly grain handling capac-
ity.
If the first alteration were consid-
ered a modification, this could require
installation of a load-out shed thereby
requiring substantial reinforcement of
the grain storage or grain transfer bin
to support the weight of emission con-
trol equipment. In light of the rela-
tively small expenditure usually re-
quired to install additional gravity
load-out spouts .to existing grain stor-
age or transfer bins, and the relatively
large expenditure that would be re-
quired to install a load-out shed or to
reinforce the storage or transfer bin,
consideration of this sort of alteration
within an existing grain elevator as a
modification was viewed as unreason-
able.
Under the general modification reg-
ulation which applies to all standards
of performance, alteration two, the ad-
dition of electronic automatic grain
weighing scales, would be considered a
change in the method of operation of
the affected facility if it were to in-
crease the hourly grain throughput. If
this alteration were to increase emis-
sions to the atmosphere and require a
capital expenditure, the grain receiv-
ing or loading station whose method
of operation had changed (i.e., in-
creased grain throughput), would be
considered a modified facility subject
to the standards. Consideration of this
type of alteration, which would result
in only minor changes to a facility, is
viewed as unreasonable in light of the
relatively high expenditure this could
require for existing grain elevators to
comply with the standards.
Alterations three and four, replace-
ment of existing motors and drives
with larger motors and drives and ad-
dition of grain storage capacity with
no increase in the hourly grain han-
dling capacity, would probably not be
considered modifications under the
general modification regulation. Since
it is quite evident that there was con-
siderable confusion concerning modifi-
cations, however, alterations three and
four, along with alterations one and
two discussed above, are specifically
exempt from consideration as modifi-
cations in the promulgated standards.
The modification provisions in 40
CFR 60.14(e) exempt certain physical
or operational changes from being
considered as modifications, even
though an increase in emission rate
•occurs. Under 40 CFR 60.14(e)(2). if an
increase in production rate of an exist-
ing facility can be accomplished with-
out a capital expenditure on the sta-
tionary source containing that facility,
the change is not considered a modifi-
cation.
A capital expenditure is defined as
any amount of money exceeding the
product of the Internal Revenue Serv-
ice (IRS) "annual asset guideline
repair allowance percentage" times
the basis of the facility, as defined by
section 1012 of the Internal Revenue
Code. In the case of grain elevators,
the IRS has not listed an annual asset
guideline repair allowance percentage.
Following discussions with the IRS,
the Department of Agriculture, and
the grain elevator industry, the
Agency determined that 6.5 percent is
the appropriate percentage for the
grain elevator Industry. If the capital
expenditures required to increase the
production rate of an existing facility
do not exceed the amount calculated
under the IRS formula, the change in
the facility is not considered a modifi-
cation. If the expenditures exceed the
calculated amount, the change in op-
eration is considered a modification
and the facility must comply with
NSPS.
Often a physical or operational
change to an existing facility to in-
crease production rate will result in an
increase in the production rate of an-
other existing facility, even though it
did not undergo a physical or oper-
ational change. For example, if new
electronic weighing scales were added
to a truck unloading station to in-
crease grain receipts, the production
rate and emission rate would increase
at the unloading station. This could
result in an increase in production rate
and emission rate at other existing fa-
cilities (e.g., grain handling oper-
ations) even though physical or oper-
ational changes did not occur. Under
the present wording of the regulation,
expenditures made throughout a grain
elevator to adjust for Increased pro-
duction rate would have to be consid-
ered in determining if a capital ex-
penditure had been made on each fa-
cility whose operation is altered by the
production increase. If the capital ex-
penditure made on the truck unload-
ing station were considered to be made
on each existing facility which in-
creased its production rate, it is possi-
ble that the alterations on each such
facility would qualify as modifications.
Each facility would, therefore, have to
meet the applicable NSPS.
. Such a result is inconsistent with
the intent of the regulation. The
Agency intended that only capital ex-
penditures made for the changed fa-
cility are to be considered in determin-
ing if the change is a modification. Re-
lated expenditures on other existing
facilities-are not to be considered in
the calculation. To clarify the regula-
tion, the phrase "the stationary source
containing" is being deleted. Because
this is a clarification of intent and not
a change In policy, the amendment is
being promulgated as a final regula-
tion without prior proposal.
PERFORMANCE TEST
Several commenters were concerned
about the costs of conducting perform-
ance tests on fabric filter baghouses.
These commenters stated that the
costs Involved might be a very substan-
tial portion of the costs of the fabric
filter baghouse itself, and several
baghouses may be installed at a mod-
erately sized grain elevator. The com-
menters suggested that a fabric filter
baghouse should be assumed to be in
compliance without a performance
test if it were properly sized. In addi-
tion, the opacity standards could be
used to demonstrate compliance.
It would not be wise to waive per-
formance tests in all cases. Section
60.8(b) already provides that a per-
formance test may be waived if "the
owner or operator of a source has
demonstrated by other means to the
Administrator's satisfaction that the
affected facility is in compliance with
the standard." Since performance
tests are heavily weighed in court pro-
ceedings, performance test require-
ments must be retained to insure ef-
fective enforcement.
SAFETY CONSIDERATIONS
In December 1977, and January
1978, several grain elevators exploded.
Allegations were made by various indi-
viduals within the grain elevator In-
dustry contending that Federal air
pollution control regulations were con-
tributing to an Increase in the risk of
dust explosions at grain elevators by
requiring that building doors and win-
dows be closed and by concentrating
grain dust in emission control systems.
Investigation of these allegations indi-
cates they are false.
There were no Federal regulations
specifically limiting dust emissions
from grain elevators which were in
effect at the time of these grain eleva-
tor explosions. A number of State and
local air pollution control agencies,
however, have adopted regulations
which limit particulate matter emis-
sions from grain elevators. Many of
these regulations were developed by
States and included in their implemen-
tation plans for attaining and main-
taining the NAAQS for particulate
matter. Particulate matter, as a gener-
al class, can cause adverse health ef-
fects; and the NAAQS, which were
promulgated on April 30, 1971, were
established at levels necessary to pro-
tect the public health and welfare.
Although compliance with State or
local air pollution control regulations,
or the promulgated standards of per-
formance, can be achieved in some in-
stances by closing building doors and
windows, this is not the objective of
these regulations and is not an accept-
V-274
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AME)
able means of compliance. The objec-
tive of State and local regulations and
the promulgated standards of per-
formance is that dust be captured at
those points within grain elevators
where it is generated through the use
of effective hoods or enclosures with
air aspiration, and removed from the
grain elevator to an air pollution con-
trol device. This is the basis for the
promulgated ' standards of perform-
ance. Compliance with air pollution
control regulations and the promul-
gated standards of performance does
not require that windows arid doors in
buildings be closed to prevent escape
of dust and this practice may in fact
be a major safety hazard.
Fabric filter baghouses have been
used for many years to collect combus-
tible dusts such as wheat flour. There
have been extremely few incidences of
dust explosions or fires caused by such
emission control devices in the flour
industry. In the grain elevator indus-
try, no air pollution control device has
been identified as the cause of a grain
elevator explosion. Consequently,
fabric filter baghouses, or emission
control devices in general, which are
properly designed, operated, and main-
tained will not contribute to an in-
creased risk of dust explosions at grain
elevators.
These conclusions were supported at
& joint meeting between representa-
tives of EPA; the Federal Grain In-
spection Service (FGIS) of the Depart-
ment of Agriculture; the Occupational
Safety and Health Administration
(OSHA); the grain elevator industry;
and the fire insurance industry. Instal-
lation and use of properly designed,
operated, and maintained air pollution
control systems were found to be con-
sistent with State and local air pollu-
tion regulations, OSHA regulations,
and national fire codes. Chapter 8 of
the National Fire Code for Grain Ele-
vators and Bulk Grain Handling Fa-
cilities (NFPA No. 61-B). which was
prepared by the National Fire Protec-
tion Association, for example, recom-
mends that "dust shall be collected at
all dust producing points within the
processing facilities." The code then
goes on to specially recommend that
all elevator boots, automatic scales,
scale hoppers, belt loaders, belt dis-
charges, trippers, and discharge heads,
and all machinery such as cleaners,
scalpers, and similar devices be pro-
vided with enclosures or dust hoods
and air aspiration.
Consequently, compliance with ex-
isting State or local air pollution regu-
lations, or the promulgated standards
of performance, will not Increase the
risk of dust explosions at grain eleva-
tors if the approach taken to meet
these regulations is capture and con-
trol of dust at those points within an
elevator where it is generated. If, how-
ever, the approach taken is merely to
close doors, windows, and other open-
ings to trap dust within the grain ele-
vator, or the air pollution control
equipment is allowed to deteriorate to
the point where it is no longer effec-
tive in capturing dust as it is generat-
ed, then ambient concentrations of
dust within the elevator will increase
and the risk of explosion will also in-
crease.
The House Subcommittee on Com-
pensation, Health, and Safety is cur-
rently conducting oversight hearings
to determine if something needs to be
done to prevent these disastrous grain
elevator explosions. The FGIS, EPA,
and OSHA testified at these oversight
hearings on January 24 and 25, 1978.
The testimony indicated that dust
should be captured and collected in
emission control devices in order to
reduce the incidence of dust explo-
sions at grain elevators, protect the
health of employees from such ail-
ments as "farmer's lung," and prevent
air pollution. Consequently, properly
operated and maintained air pollution
control equipment will not increase
the risk of grain elevator explosions.
MISCELLANEOUS
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Clean
Air Act reflect the degree of emission
limitation achievable through applica-
tion of the best adequately demon-
strated technological system of con-
tinuous emission reduction (taking
into consideration the cost of achiev-
ing such emission reduction, any
nonair quality health and environmen-
tal impact and energy requirements).
State implementation plans (SIP's) ap-
proved or promulgated under section
110 of the act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIP's must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173 of the act requires, among
other things, that a new or modified
source constructed in an area in viola-
tion of the NAAQS must reduce emis-
sions to the level which reflects the
"lowest achievable emission rate" for
such category of source as defined in
section 171(3). In no event can the
emission rate exceed any applicable
standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the act (part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology for all pollutants regulated
under the act. The term "best availa-
ble control technology" (BACT), as de-
fined in section 169(3), means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stand-
ard established pursuant to sections
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty),
statutorily, costs do not play such a
role in determining the "lowest achiev-
able emission rate" for new or modi-
fied sources locating in areas violating
statutorily mandated health and wel-
fare standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stand-
ards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition. 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. Thus.
new sources may in some cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning
for such facilities.
ECONOMIC IMPACT ASSESSMENT
An economic assessment has been
prepared as required under section 317
of the Act."
V-275
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RULES AND REGULATIONS
Dated: July 26,1978.
DOUGLAS M. COSTLE,
Administrator.
REFERENCES
1. "Standards Support and Environmental
Impact Statement—Volume I: Proposed
Standards of Performance for Grain Eleva-
tor Industry," U.S. Environmental Protec-
tion Agency—OAQPS, EPA-450/2-77-001a,
Research Triangle Park, N.C., January 1977.
2. "Draft—For Review Only: Evaluation of
Public Comments: Standards of Perform-
ance For Grain Elevators." U.S. Environ-
mental Protection Agency—OAQPS, Re-
search Triangle Park, N.C., August 1977.
3. "Standards Support and Environmental
Impact Statement—Volume II: Promulgated
Standards of Performance for Grain Eleva-
tor Industry." U.S. Environmental Protec-
tion Agency—OAQPS, EPA-450/2-77-001D,
Research Triangle Park. N.C., April 1978.
Part 60 of chapter I. title 40 of the
Code of Federal Regulations is amend-
ed as follows:
Subpart A—General Provisions
1. Section 60.2 is amended by revis-
ing paragraph (v). The revised para-
garaph reads as follows:
§60.2 Definitions.
(v) "Particulate matter" means any
finely divided solid or liquid material,
other than uncombined water, as
measured by the reference methods
specified under each applicable sub-
part, or an equivalent or alternative
method.
§60.14 [Amended]
2. Section 60.14 is amended by delet-
ing the words "the stationary source
containing" from paragraph (e)(2).
3. Part 60 is amended by adding sub-
part DD as follows:
Subpart DD—Standard* of Performance for
Grain Elevators
Sec.
60.300 Applicability and designation of af-
fected facility.
60.301 Definitions.
60.302 Standard for particulate matter.
60.303 Test methods and procedures.
60.304 Modification.
AUTHORITY: Sees. Ill and 301(a) of the
Clean Air Act, as amended (42 U.S.C. 7411,
7601(a)>, and additional authority as noted
below.
Subporl DD—Standards of
Performance for Grain Elevators
§60.300 Applicability and designation of
affected facility.
(a) The provisions of this subpart
apply to each affected faculty at any
grain terminal elevator or any grain
storage elevator, except as provided
under §60.304(b). The affected facili-
ties are each truck unloading station,
truck loading station, barge and ship
unloading station, barge and ship load-
ing station, railcar loading station,
railcar unloading station, grain dryer,
and all grain handling operations.
(b) Any facility under paragraph (a)
of this section which commences con-
struction, modification, or reconstruc-
tion after (date of reinstatement of
proposal) is subject to the require-
ments of this part.
§ 60.301 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) "Grain" means corn, wheat, sor-
ghum, rice, rye, oats, barley, and soy-
beans.
(b) "Grain elevator" means any
plant or installation at which grain is
unloaded, handled, cleaned, dried,
stored, or loaded.
(c) "Grain terminal elevator" means
any grain elevator which has a perma-
nent storage capacity of more than
88,100 ms (ca. 2.5 million U.S. bushels),
except those located at animal food
manufacturers, pet food manufactur-
ers, cereal manufacturers, breweries,
and livestock feedlots.
(d) "Permanent storage capacity"
means grain storage capacity which is
inside a building, bin, or silo.
(e) "Railcar" means railroad hopper
car or boxcar.
(f) "Grain storage elevator" means
any grain elevator located at any
wheat flour mill, wet corn mill, dry
corn mill (human consumption), rice
mill, or soybean oil extraction plant
which has a permanent grain storage
capacity of 35,200 mj (ca. 1 million
bushels).
(g) "Process emission" means the
particulate matter which is collected
by a capture system.
(h) "Fugitive emission" means the
particulate matter which is not collect-
ed by a capture system and is released
directly into the atmosphere from an
affected facility at a grain elevator.
(i) "Capture system" means the
equipment such as sheds, hoods, ducts,
fans, dampers, etc. used to collect par-
ticulate matter generated by an affect-
ed facility at a grain elevator.
(j) "Grain unloading station" means
that portion of a grain elevator where
the grain is transferred from a truck,
railcar, barge, or ship to a receiving
hopper.
(k) "Grain loading station" means
that portion of a grain elevator where
the grain is transferred from the ele-
vator to a truck, railcar. barge, or ship.
(1) "Grain handling operations" in-
clude bucket elevators or legs (exclud-
ing legs used to unload barges or
ships), scale hoppers and surge bins
(garners), turn heads, scalpers, clean-
ers, trippers, and the headhouse and
other such structures.
(m) "Column dryer" means any
equipment used to reduce the mois-
ture content of grain in which the
grain flows from the top to the bottom
In one or more continuous packed col-
umns between two perforated metal
sheets.
(n) "Rack dryer" means any equip-
ment used to reduce the moisture con-
tent of grain in which the grain flows
from the top to the bottom in a cas-
cading flow around rows of baffles
(racks).
(o) "Unloading leg" means a device
which Includes a bucket-type elevator
which is used to remove grain from a
barge or ship.
§ 60.302 Standard for particulate matter.
(a) On and after the 60th day of
achieving the maximum production
rate at which the affected facility will
be operated, but no later than 180
days after initial startup, no owner or
operator subject to the provisions of
this subpart shall cause to be dis-
charged into, the atmosphere any
gases which exhibit greater than 0
percent opacity from any:
(1) Column dryer with column plate
perforation exceeding 2.4 mm diame-
ter (ca. 0.094 inch).
(2) Rack dryer in which exhaust
gases pass through a screen filter
coarser than 50 mesh.
(b) 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 provi-
sions of this subpart shall cause to be
discharged Into the atmosphere from
any affected facility except a grain
dryer any process emission which:
(1) Contains particulate matter in
excess of 0.023 g/dscm (ca. 0.01 gr/
dscf).
(2) Exhibits greater than 0 percent
opacity.
(c) On and after the 60th day of
achieving the maximum production
rate at which the affected facility will
be operated, but no later than 180
days after initial startup, no owner or
operator subject to the provisions of
this subpart shall cause to be dis-
charged into the atmosphere any fugi-
tive emission from:
(1) Any individual truck unloading
station, railcar unloading station, or
railcar loading station, which exhibits
greater than 5 percent opacity.
(2) Any grain handling operation
which exhibits greater than 0 percent
opacity.
(3) Any truck loading station which
exhibits greater than 10 percent opac-
ity.
(4) Any barge or ship loading station
which exhibits greater than 20 percent
opacity.
V-276
-------
AK©
(d) The owner or operator of any
barge or ship unloading station shall
operate as follows:
(1) The unloading leg shall be en-
closed from the top (including the re-
ceiving hopper) to the center line of
the bottom pulley and ventilation to &
control device shall be maintained on
both sides of the leg and the grain re-
ceiving hopper.
(2) The total rate of air ventilated
shall be &t least 32.1 actual cubic
meters per cubic meter of grain han-
dling capacity
-------
1. In §60.283. paragraph (a)(l) is
amended to read as follows:
§ 60.283 Standard for total reduced sulfur
(TRS>.
(a) • ' •
n I • • •
(v) The gasos from the digester
system, brown stock washer system,
condensate stripper system, or black
liquor oxidation system are controlled
by a means other than combustion. In
this case, these systems shall not dis-
charge any gases to the atmosphere
which contain TRS in excess of 5 ppm
by volume on a dry basis, corrected to
the actual oxygen content of the un-
treated gas stream.
• * • » •
2. In appendix A, paragraph 10.1 of
method 16 is amended to read as fol-
lows:
. • • • • •
10. POST-TEST PROCEDURES
10.1 Sample line loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard. ± 20 percent, must
be introduced into the sampling system in
sufficient quantities to insure that there is
an excess of sample which must be vented
to the atmosphere. The sample must be in-
troduced immediately after the probe and
filter and transported through the remain-
der of tne sampling system to the measure-
ment system in the normal manner. The re-
sulting measured concentration should be
compared to the known value to determine
the sampling system loss.
For sampling losses greater than 20 per-
cent in a sample run, the sample run is not
to be used when determining the arithmetic
mean of the performance test. For sampling
losses of 0-20 percent, the sample concen-
tration must be corrected by dividing the
sample concentration by the fraction of re-
covery. The fraction of recovery is equal to
one minus the ratio of the measured con-
centration to the known concentration of
hydrogen sulfide in the sample line loss pro-
cedure. The known gas sample may be gen-
erated using permeation tubes. Alternative-
ly, cylinders of hydrogen sulfide mixed in
air may be used provided they are traceable
to permeation tubes. The optional pretest
procedures provide a good guideline for de-
termining if there are leaks in the sampling
system.
(Sec. Ill, 301(8)), Clean Air Act as amended
(42U.S.C. 7411, 7601
-------
Yifllo
CHAPTER 0— ENVIRONMENTAL
PROTECTION A©ENCY
tFRL 1012-2]
PAST 60— STANDARDS ©F PERFORM-
ANCE FOR MEW STATIONARY
Appendix A—Befaronce Method 16
AGENCY: Environmental Protection
Agency.
ACTION: Amendment.
SUMMARY: This action amends Ref-
erence Method 16 for determining
total reduced sulfur emissions from
stationary sources. The amendment
corrects several typographical errors
and improves the reference method by
requiring the use of a scrubber to pre-
vent potential interference from high
SO, concentrations. These changes
assure more accurate measurement of
total reduced sulfur (TRS) emissions
but do not substantially change the
reference method.
SUPPLEMENTARY INFORMATION:
On Februrary 23, 1978 (43 FR 7575).
Appendix A—Reference Method 16 ap-
peared with several typographical
errors or omissions. Subsequent com-
ments noted these and also suggested
that the problem of high SOa concen-
trations could be corrected by using a
scrubber to remove these high concen-
trations. This amendment corrects the
errors of the original publication and
slightly modifies Reference Method 16
by requiring the use of a scrubber to
prevent potential Interference from
high SOa concentrations.
Reference Method 16 is the refer-
ence method specified for use in deter-
mining compliance with the promul-
gated standards of performance for
liraft pulp mills. The data base used to
develop the standards for kraft pulp
mills has been examined and this addi-
tional requirement to use a scrubber
to prevent potential interference from
high SOa concentrations does not re-
quire any change to these standards of
performance. The data used to develop
these standards was not gathered from
fcraft pulp mills with high SOa concen-
trations; thus, the problem of SOa in-
terference was not present in the data
base. The use of a scrubber to prevent
this potential interference in the
future, therefore, is completely con-
sistent with this data base and the
promulgated standards.
BUIES AND .BE6UG.ATOKIS
The increase in the cost of determin-
ing compliance with the standards of
performance for kraft pulp mills, as a
result of this additional requirement
to use a scrubber in Reference Method
16. is negligible. At most, this addition-
al requirement could increase the cost
©? Environment of a performance test by about 50 dol-
lars.
Because these corrections and addi-
tions to Reference Method 16 are
minor in nature, impose no additional
substantive requirements, or do not re-
quire a change in the promulgated
standards of performance for kraft
pulp mills, these amendments are pro-
mulgated directly.
EFFECTIVE DATE: January 12, 1979.
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.
Dated: January 2, 1979.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
APPENDIX A—REFERENCE METHODS
In Method 16 of Appendix A, Sec-
tions 3.4, 4.1, 4.3, 5. 5.5.2. 6, 8.3, 9.2.
10.3, 11.3, 12.1, 12.1.1.3, 12.1.3.1,
12.1.3.1.2, 12.1.3.2, 12.1.3.2.3, and 12.2
are amended as follows:
1. In subsection 3.4, at the end of the
first paragraph, add: "In the example
system, SOa is removed by a citrate
buffer solution prior to GC injection.
This scrubber will be used when SO,
levels are high enough to prevent
baseline separation from the reduced
sulfur compounds."
2. In subsection 4.1, change "± 3 per-
cent" to "± 5 percent."
3. In subsection 4.3, delete both sen-
tences and replace with the following:
"Losses through the sample transport
system must be measured and a cor-
rection factor developed to adjust the
calibration accuracy to 100 percent."
4. After Section 5 and before subsec-
tion 5.1.1 insert "5.1. Sampling."
5. In Section 5, add the following
subsection: "5.3 SO, Scrubber. The
SO, scrubber is a midget impinger
packed with glass wool to eliminate
entrained mist and charged with po-
tassium citrate-citric acid buffer."
Then Increase all numbers from 5.3 up
to and including 5.5.4 by 0.1, e.g.,
chartge 5.3 to 5.4, etc.
6. In subsection 5.5.2, the word
"lowest" in the fourth sentence is re-
placed with "lower."
7. In Section 6, add the following
subsection: "6.6 Citrate Buffer. Dis-
solve 300 grams of potassium citrate
and 41 grams of anhydrous citric acid
in 1 liter of deionlzed water. 284 grams
of sodium citrate may be substituted
for the potassium citrate."
8. In subsection 8.3, in the second
sentence, after "Bypassing the dilu-
tion system," insert "but using the SO,
scrubber," before finishing the sen-
tence.
9. In subsection 9.2, replace sentence
with the following: "Aliquots'of dilut-
ed sample pass through the SOa scrub-
ber, and then are injected into the
GC/FPD analyzer for analysis."
10. In subsection 10.3, "paragraph"
in the second sentence is corrected
with "subsection."
11. In subsection 11.3 under Bwo defi-
nition, insert "Reference" before
"Method 4."
12. In subsection 12.1.1.3 "(12.2.4
below)" is corrected to "(12.1.2.4
below)."
13. In subsection 12.1, add the fol-
lowing subsection: "12.1.3 SO2 Scrub-
ber. Midget impinger with 15 ml of po-
tassium citrate buffer to absorb SO, in
the sample." Then renumber existing
section 12.1.3 and following subsec-
tions through and including 12.1.4.3 as
12.1.4 through 12.1.5.3.
14. The second subsection listed as
"12.1.3.1" (before corrected in above
amendment) should be "12.1.4.1.1."
15. In subsection 12.1.3.1 (amended
above to 12.1.4.1) correct "GC/FPD-1
to "GC/FPD-I."
16. In subsection 12.1.3.1.2 (amended
above to 12.1.4.1.2) omit "Packed as in
5.3.1." and put a period after "tubing."
17. In subsection 12.1.3.2 (amended
above to 12.1.4.2) correct "GC/FPD-
11" to "GC/FPD-II."
18. In subsection 12.1.3.2.3 (amended
above to 12.1.4.2.3) the phrase
"12.1.3.1.4. to 12.1.3.1.10" is corrected
to read "12.1.4.1.5 to 12.1.4.1.10."
19. In subsection 12.2, add the fol-
lowing subsection: "12.2.7 Citrate
Buffer. Dissolve 300 grams of potas-
sium citrate and 41 grams of anhy-
drous citric acid in 1 liter»of deionized
water. 284 grams of sodium citrate
may be substituted for the potassium
citrate."
(Sec. Ill, 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601 (a>».
IFR Doc. 79-1047 Filed 1-11-79; 8:45 am]
FEOEtJAl BEGISTEH, VOL 44, NO. 9—P8IDAY, .JANUABV 12, 1979
V-279
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RULES AMD «CULATIONS
94
Tille 40-Proteetion of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
[FRL 1017-7]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Wood Residue-Fired Steam
Generators
APPLICABILITY DETERMINATION .
AGENCY: 'Environmental Protection
Agency.
ACTION: Notice of Determination.
SUtSM.AR'Y: 'This notice presents the
results of a performance review of par-
ticulate -matter control systems on
wood residue-fired steam generators.
On November 22, 1976 (41 FR 51397).
EPA amended the standards of per-
formance of new fossil-fuel-fired
steam generators to allow the heat
content of wood residue to be included
with the heat content of fossil-fuel
when determining compliance v/ith
the standards. EPA stated in the pre-
amble that there were some questions
about the feasibility of units burning a
large ^portion of wood residue to
achieve the particulate matter stand-
ard -and announced that this would be
reviewed. This review has been com-
pleted, and EPA concludes that the
particulate matter standard «an be
achieved, therefore, no revision is nec-
essary.
ADDRESSES: The document which
presents the basis for this notice may
be obtained from the Public Informa-
tion Center (PM-215), U.S. Environ-
mental Protection Agency, Washing-
ton, D.C. 20460 (specify "Wood Resi-
due-Fired Steam Generator Particu-
late .Matter Control Assessment,"
EPA-450/2-78-044.)
The document may be inspected and
copied at the Public Information Ref-
erence 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,
Enyirorunental Protection Agency,
Research Triangle Park, North
Carolina 27711, telephone number
(919).541-5271.
SUPPLEMENTARY INFORMATION:
On November 22, 1976, standards
under 40 CFR Part 60, Subpart D for
new fossil-fuel-fired steam generators
were amended (41 FR 51397) to clarify
that the standards apply to each
fossil-fuel and wood residue-fired
steanj generating unit capable of
firing fossil-fuel at a heat input of
more than 73 megawatts (250 million
Btu per hour). The primary objective
of this amendment is to allow the heat
input provided by wood residue to be
used as a dilution agent in the calcula-
tions necessary to determine sulfur
dioxide emissions. EPA recognized in
the preamble of the amendment that
questions remained concerning the.
ability of affected facilities which
burn substantially more wood residue
than fossil-fuel to comply with the
standard for particulate matter. The
preamble also stated that EPA was
continuing to gather information on
'this question. The discussion that fol-
lows summarizes the results of EPA's
examination of available information.
Wood residue Is a waste by-product
of the pulp and paper industry which
consists of bark, sawdust, slabs, chips,
shavings, and .mill trims. Disposal of
this waste prior to the 1960's consisted
mostly of Incineration in Dutch ovens
or open air tepees. Since then the
advent of the spreader stroker boiler
and the increasing costs of fossil-fuels
has made wood residue an -economical
fuel to .burn-in large boilers for the
generation of process steam.
There are several hundred steam
generating boilers in the pulp And
paper and allied forest product indus-
try that use fuel which is partly .or to-
tally derived from wood residue. These
boilers range in size from 6 megawatts
C20 million .Btu per hour) to 146
megawatts (500 million Btu per hour)
and the total emissions from all boil-
ers is estimated to be 225 tons of par-
ticulate matter per day after applica-
tion of existing air pollution control
devices.
Most existing wood residue-fired
boilers subject to State emission stand-
ards are equipped with multitube-cy-
clone mechanical collectors. Manufac-
turers of the multitube collector have
recognized that this type of control
will not meet "present new source
standards and have been developing
processes and devices to meet the new
regulations. However, the use of these
various systems on -wood residue-fired
boilers has not found widespread use
to date, resulting in tin information
gap on expected performance of col-
lector types other than conventional
mechanical collectors.
In order to provide needed informa-
tion in this area and to answer ques-
tions raised in the November 22, 1976
(41 FR 51397), amendment, a study
was conducted on the most effective
control systems in operation on wood
residue-fired boilers. Also the amount
and characteristics of the particulate'
emissions from wood residue-fired boil-
ers was studied. The review that fol-
lows presents the results of that study.
PERFORMANCE REVIEW
The combustion of wood residue re-
sults in particulate emissions in the
form -of bark char or fly ash. En-
trained with the char are varying
amounts of sand and salt, the quantity
depending on the method by which
the original wood was logged and de
livered. The'fly ash particulates have
a lower density and are larger in size
than fly ash from coal-fired boilers. In
general, the bark boiler exhaust gas
will have a lower fly ash content than
emissions from similar boilers burning
physically cleaned coals or low-sulfur
Western coals.
The bark fly ash, unlike most fly
ash, is primarily unburned carbon.
With collection and reinjection to the
FEDERAL REGISTER, VOL.44, NO. M—WEDNESDAY , JANUARY 17, 1f79
V-280
-------
boiler, greater carbon burnout can In-
crease boiler efficiency from one to
four percent. The reinjection of col-
lected ash also significantly increases
the dust loading since the sand is also
recirculated with the fly ash. This in-
creased dust loading can be accommo-
dated by the use of sand separators or
decantation type dust collectors. Col-
lectors of this type in combination
with more efficient units of air pollu-
tion control equipment constitute the
systems currently in operation on ex-
isting plants that were found to oper-
ate with emissions less than the 43
nanograms per joule (0.10 pounds per
million Btu) standard for particulate
matter.
A survey of currently operated facili-
ties that fire wood residue alone or in
combination with fossil-fuel shows
that most operate with mechanical
collectors; some operate with low
energy wet scrubbers, and a few facili-
ties currently use higher energy ven-
turi scrubbers (HEVS) or electrostatic
precipitators (ESP). One facility re-
viewed is using a high temperature
baghouse control system.
Currently, the use of multitube-cy-
clone mechanical collectors on hogged-
fuel boilers provides the sole source of
particulate removal for a majority of
existing plants. The most commonly
used system employs two multiclones
in series allowing for the first collector
to remove the bulk of the dust and a
second collector with special high effi-
ciency vanes for the removal of the
finer particles. Collection efficiency
for this arrangement ranges from 65
to 95 percent. This efficiency range is
not sufficient to provide compliance
with the particulate matter standard,
but does provide a widely used first
stage collection to which other control
systems are added.
Of special note is one facility using a
Swedish designed mechanical collector
in series with conventional multiclone
collectors. The Swedish collector is a
small diameter multitube cyclone with
a movable vane ring that imparts a
spinning motion to the gases while at
the same time maintaining a low pres-
sure differential. This system is reduc-
ing emissions from the largest boiler
found in the review to 107 nanograms
per joule.
Electrostatic precipitators have been
demonstrated to allow compliance
with the particulate matter standard
when coal is used as an auxiliary fuel.
Available information Indicates that
this type of control provides high col-
lection efficiencies on combinati6n
wood residue coal-fired boilers. One
ESP collects particulate matter from a
SO percent bark, 50 percent coal combi-
n&tion fired boiler. An emission level
of 13 nanograms per joule (.03 pounds
per million Btu) was obtained using
test methods recommended by the
American Society of Mechanical Engi-
neers.
The fabric filter (baghouse) particu-
late control system provides the high-
est collection efficency available, 99.9
percent. On one facility currently
using a baghouse on a wood residue-
fired boiler, the sodium chloride con-
tent of the ash being filtered is high
enough (70 percent) that the possibil-
ity of fire is practically eliminated.
Source test data collected with EPA
Method 5 showed this system reduces
the particulate emissions to 5 nano-
grams per joule (0.01 pounds per mil-
lion Btu).
The application of fabric filters to
control emissions from hogged fuel
boilers has recently gained acceptance
from several facilities of the paper and
pulp industry, mainly due to the devel-
opment of improved designs and oper-
ation procedures that reduce fire haz-
ards. Several large sized boilers, firing
salt and non-salt laden wood residue,
are being equipped with fabric filter
control systems this year and the per-
formance of these installations will
verify the effectiveness of fabric filtra-
tion.
Practically all of the facilities cur-
rently meeting the new source particu-
late matter standard are using wet
scrubbers of the venturi or wet-im-
pinger type. These units are usually
connected in series with a mechanical
collector. Three facilities reviewed
which are using the wet-impingement
type wet scrubber on large boilers
burning 100 percent bark are produc-
ing particulate emissions well below
the 43 nanograms per joule standard
at operating pressure drops of 1.5 to 2
kPa (6 to 8 inches, H,O). Five facilities
using venturi type wet scrubbers on
large boilers, two burning half oil and
half bark and the other three burning
100 percent bark, are producing partic-
ulate emissions consistently below the
standard at pressure drops of 2.5 to 5
kPa (10 to 20 inches, H,O).
One facility has a large boiler burn-
ing 100 percent bark emitting a maxi-
mum of 5023 nanograms per joule of
particulate matter into a multi-cyclone
dust collector rated at an efficiency of
87 percent. The outlet loading from
this mechanical collector is directed
through two wet impingement-type
scrubbers in parallel. With this ar-
rangement of scrubbers, a collection
efficiency of 97.7 percent is obtained
at pressure drops of 2 kPa (8 inches,
H,O). Source test data collected with
EPA Method 5 showed particulate
matter emissions to be 15 nanograms
per joule, well below the 43 nanograms
per joule standard.
Another facility with a boiler of sim-
ilar size and fuel was emitting a maxi-
mum of 4650 nanograms per Joule into
a multi-cyclone dust collector operat-
ing at a collection efficiency of 66 per-
cent. The outlet loading from this col-
lector is drawn into two wet-impinge-
ment scrubbers arranged in parallel.
The operating pressure drop on these
scrubbers was varied within the range
of 1.6 to 2.0 kPa (6 to 8 inches, H2O),
resulting in a proportional decrease in
discharged loadings of 25.8 to 18.5
nanograms per joule. Source test data
collected on this source was obtained
with the Montana Sampling Train.
Facilities using a venturi type wet
scrubber were found to be able to meet
the 43 nanogram per joule standard at
higher pressure drops than the im-
pingement type scrubber. One facility
with a large boiler burning 100 percent
bark had a multi-cyclone dust collec-
tor in series with a venturi wet scrub-
ber operating at a pressure drop of 5
kPa (20 inches, H,O). Source test data
using EPA Method 5 showed this
system consistently reduces emissions
to an average outlet loading of 17.2
nanograms per joule of particulate
matter. Another facility with a boiler
burning 40 percent bark and 60 per-
cent oil has a multi-cyclone and ven-
turi scrubber system obtaining 25.8
nanograms per joule at a pressure
drop of 2.5 kPa (10 inches, H,O). The
Florida Wet Train was used to obtain
emission data on this source. A facility
of similar design but burning 100 per-
cent bark is obtaining the same emis-
sion control, 25.8 nanograms per joule,
at a pressure drop of 3 kPa (12 inches,
H,O). Source test data collected on
this source were obtained with the
EPA Method 5.
This review has shown that the use
of a wet scrubber, ESP, or a baghouse
to control emissions from wood bark
boilers will permit attainment of the
particulate matter standard under 40
CFR Part 60. The control method cur-
rently used, which has the widest ap-
plication is the multitube cyclone col-
lector in series with a venturi or wet-
impingement type scrubber. Source
test data have shown that facilities
which burn substantially more wood
residue than fossil-fuel have no diffi-
culty in complying with the 43 nano-
gram per joule standard for particu-
late matter. Also the investigated
facilities have been in operation suc-
cessfully for a number of years with-
out adverse economical problems.
Therefore EPA has concluded from
evaluation of the available informa-
tion that no revision is required of the
particulate matter standard for wood
residue-fired boilers.
Dated: January 3, 1979.
DOUGLAS M. COSTLE,
Administrator.
[FR Doc. 79-1421 Filed 1-16-79; 8:45 am]
PEDEBAl DESISTED VOL 7, 1979
V-281
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RULES AND REGULATIONS
95
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
DKEGATION OF AUTHORITY TO
STATE OF TEXAS
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action amends Sec-
tion 60.4. Address, to reflect the dele-
gation of authority for the Standards
of Performance for New Stationary
Sources (NSPS) to the State of Texas.
UWKurrvis DATE: February 7. 1979.
FOR FURTHER INFORMATION
CONTACT:
James Veach, Enforcement Division,
Region 6, Environmental Protection
Agency, First' International Build-
ing. 1201 Elm Street, Dallas. Texas
75270, telephone (214) 767-2760.
SUPPLEMENTARY INFORMATION:
A notice announcing the delegation of
authority is published elsewhere in
the Notice Section In this Issue of the
FEDERAL REGISTER. These amendments
provide that all reports and communi-
cations previously submitted to the
Administrator, will now be sent to the
Texas Air Control Board, 8520 Shoal
Creek Boulevard, Austin, Texas 78758,
Instead of EPA's Region 6.
As this action Is not one of substan-
tive content, but is only an administra-
tive change, public, participation was
judged unnecessary.
(Sections 111 and 301.
Dated: November IS, 1978.
ADLXKX HARJUSOX,
Regional Adminls trntor.
Region^.
Part flO of Chapter 1, TiUe 40. Code
of Federal Regulations, is amended as
follows:
1. In S«o.4, paragraph (b) <6S) is
amended as follows:
5 60.4 Address.
96
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
P*trol«um Refineries—Clarifying
Amendment
AGENCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: These amendments clari-
fy the definitions of "fuel gas" and
"fuel gas combustion device" Included
In the existing standards of perform-
ance for petroleum refineries. These
amendments will neither increase nor
decrease the degree of emission con-
trol required by the existing stand-
ards. The objective of these amend-
ments is to reduce confusion concern-
Ing the applicability of the sulfur
dioxide standard to incinerator-waste
heat boilers Installed on fluid or Ther-
mofor catalytic cracking unit catalyst
regenerators and fluid coking unit
coke burners.
EFFECTIVE DATE: March 12, 1979.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Pro-
tection Agency, Research Triangle
Park, North Carolina 27711, tele-
phone (919) 541-5271.
SUPPLEMENTARY INFORMATION:
On March 8, 1974 (39 FR 9315), stand-
ards of performance were promulgated
limiting sulfur dioxide emissions from
fuel gas combustion devices in petro-
leum refineries under 40 CFR Part 60,
Subpart J. Fuel gas combustion de-
vices are defined as any equipment,
such as process heaters, boilers, or
flares, used to combust fuel gas. Fuel
gas is defined as any gas generated by
a petroleum refinery process unit
which ~is combusted. Fluid catalytic
cracking unit and fluid coking unit in-
cinerator-waste heat boilers, and facili-
ties in which gases are combusted to
produce sulfur or sulfurlc acid are
FEDERAL REGISTER, VOL. 44, NO. 49—MONDAY, MARCH IX 1979
(SS) State of Texas, Texas Air Con-
trol Board, 8520 Shoal Creek Boule-
vard, Austin, Texas 78758.
tra Doc. 7»-4223 Flted i-6-79; «:4S unl
ffiDERAl KGtSTEt, VOL 44, NO. ^-WEDNESDAY, fCMUARY J, W9
V-282
-------
tULES AND REGULATIONS
exempted from consideration as fuel
gas combustion devices.
Recently, the following two ques-
tions have been raised concerning the
intent of exempting fluid catalytic
cracking unit and fluid coking unit in-
cinerator-waste heat boilers.
(1) Is it Intended that Thermofor
catalytic cracking unit Incinerator
waste-heat boilers be considered the
same as fluid catalytic cracking unit
Incinerator-waste heat boilers?
(2) Is the exemption intended to
apply to the incinerator-waste heat
boiler as a whole Including auxiliary
fuel gas also combusted in this boiler?
The answer to the first question Is
yes. The answer to the second ques-
tion is no.
The objective of the standards of
performance is to reduce sulfur diox-
ide emissions from fuel gas combus-
tion in petroleum refineries. The
standards are based on amtne treating
of refinery fuel gas to remove hydro-
gen sulfide contained in these gases
before they are combusted. The stand-
ards are not intended to apply to those
gas streams generated by catalyst re-
generation in fluid or Thermofor cata-
lytic cracking units, or by coke burn-
Ing in fluid coking units. These gas
streams consist primarily of nitrogen,
carbon monoxide, carbon dioxide, and
water vapor, although small amounts
of hydrogen sulfide may be present.
Incinerator-waste heat boilers can be
used to combust these gas streams as a
means of reducing carbon monoxide
emissions and/or generating steam.
Any hydrogen sulfide present is con-
verted to sulfur dioxide. It is not possi-
ble, however, to control sulfur dioxide
emissions by removing whatever hy-
drogen sulfide may be present in these
gas streams before they are combust-
ed. The presence of carbon dioxide ef-
fectively precludes the use of amine
treating, and since this technology is
the basis for these standards, exemp-
tions are included for fluid catalytic
cracking units and fluid coking units.
Exemptions are not included for
Thermofor catalytic cracking units be-
cause this technology is considered ob-
solete compared to fluid catalytic
cracking. Thus, no new, modified, or
reconstructed Thermofor" catalytic
cracking units are considered likely.
The possibility that an incinerator-
waste heat boiler might be added to an
existing Thermofor catalytic cracking
unit, however, was overlooked. To take
this possibility into account, the defi-
nitions of "fuel gas" and "fuel gas
combustion device" have been rewrit-
ten to exempt Thermofor catalytic
cracking units from compliance in the
same manner as fluid catalytic crack-
Ing units and fluid coking units.
As outlined above, the intent is to
ensure that gas streams generated by
catalyst regeneration or coke burning
in catalytic cracking or fluid coking
units are exempt from compliance
with the standard limiting sulfur diox-
ide emissions from fuel gas combus-
tion. This is accomplished under the
standard as promulgated March 8,
1974, by exempting Incinerator-waste
heat boilers installed on these units
from consideration as fuel gas combus-
tion devices.
Incinerator-waste heat boilers In-
stalled to combust these gas streams
require the firing of auxiliary refinery
fuel gas. This is necessary to insure
complete combustion and prevent
"flame-out" which could lead to an ex-
plosion. By exempting the incinerator-
waste heat boiler, however, this auxil-
iary refinery fuel gas stream is also
exempted, which is not the intent of
these exemptions. This auxiliary refin-
ery fuel gas stream is normally drawn
from the same refinery fuel gas
system that supplies refinery fuel gas
to other process heaters or boilers
within the refinery. Amine treating
can be used, and in most major refin-
eries normally is used, to remove hy-
drogen sulfide from this auxiliary fuel
gas stream as well as from all other re-
finery fuel gas streams.
To ensure that this auxiliary fuel
gas stream fired in waste-heat boilers
is not exempt, the definition of fuel
gas combustion device is revised to
eliminate the exemption for inciner-
ator-waste heat boilers. In addition,
the definition of fuel gas is revised to
exempt those gas streams generated
by catalyst regeneration In catalytic
cracking units, and by coke burning in
fluid coking units from consideration
as refinery fuel gas. This will accom-
plish the original intent of exempting
only those gas streams generated by
catalyst regeneration or coke burning
from compliance with the standard
limiting sulfur dioxide emissions from
fuel gas combustion.
MISCELLANEOUS: The Administra-
tor finds that good cause exists for
omitting prior notice and public com-
ment on these amendments and for
making them immediately effective
because they simply clarify the exist-
ing regulations and impose no addi-
tional substantive requirements.
Dated: February 28, 1979.
DOUGLAS M. COSTLE.
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. Section 60.101 is amended by re-
vising paragraphs (d) and (g) as fol-
lows:
§60.101 Definitions.
(d) "Fuel gas" means natural gas or
any gas generated by a petroleum re-
finery process unit which Is combusted
separately or In any combination. Fuel
gas does not include gases generated
by catalytic cracking unit catalyst re-
generators and fluid coking unit coke
burners.
(g) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers, and flares used to
combust fuel gas, except facilities in
which gases are combusted to produce
sulfur or sulfuric acid.
(Sec. Ill, 301(a). Clean Air Act as amended
(42 UJS.C. 7411. 7601
[PR Doc. 79-7428 Filed 3-9-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. 49—MONDAY, MARCH 12, 1979
V-283
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Federal Register / Vol. 44. No. 77 / Thursday. April 19. 1979 / Rules and Regulations
97
40 CFR Part 60
Standards of Performance for New
Stationary Sources; Delegation of
Authority to Washington Local Agency
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final Rulemaking.
SUMMARY: This rulemaking announces
EPA's concurrence with the State of
Washington Department of Ecology's
(DOE) sub-delegation of the
enforcement of the New Source
Performance Standards (NSPS) program
for asphalt batch plants to the Olympic
Air Pollution Control Authority
(OAPCA) and revises 40 CFR Part 60
accordingly. Concurrence was requested
by the State on February 27,1979.
EFFECTIVE DATE: April 19, 1979.
ADDRESS:
Environmental Protection Agency,
Region X M/S 629,1200 Sixth Avenue.
Seattle, WA 98101.
State of Washington, Department of
Ecology, Olympia, WA 98504.
Olympic Air Pollution Control Authority,
120 East State Avenue, Olympia, WA
98501.
Environmental Protection Agency,
Public Information Reference Unit,
Room 2922, 401 M Street SW.,
Washington, D.C. 20640.
FOR FURTHER INFORMATION CONTACT:
Clark L. Gaulding, Chief, Air Programs
Branch M/S 629, Environmental
Protection Agency, 1200 Sixth Avenue,
Seattle, WA 98101, Telephone No. (206)
442-1230 FTS 399-1230.
SUPPLEMENTARY INFORMATION: Pursuant
to Section lll(c) of the Clean Air Act (42
USC 7411(c)). on February 27,1979, the
Washington State Department of
Ecology requested that EPA concur with
the State's sub-delegation of the NSPS
program for asphalt batch plants to the
Olympic Air Pollution Control Authority.
After reviewing the State's request, the
Regional Administrator has determined
that the sub-delegation meets all
requirements outlined in EPA's original
February 28,1975 delegation of
authority, which was announced in the
Federal Register on April 1,1975 (40 FR
14632).
Therefore, on March 20,1979, the
Regional Administrator concurred in the
sub-delegation of authority to the
Olympic Air Pollution Control Authority
with the understanding that all
conditions placed on the original
delegation to the State shall apply to the
sub-delegation. By this rulemaking EPA
is amending 40 CFR 60.4 (WW) to reflect
the sub-delegation described above.
The amended § 60.4 provides that all
reports, requests, applications and
communications relating to asphalt
batch plants within the jurisdiction of
Olympic Air Pollution Control Authority
(Clallam, Grays Harbor, Jefferson,
Mason, Pacific and Thurston Counties)
will now be sent to that Agency rather
than the Department of Ecology. The
amended section 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.
This rulemaking is effective
immediately, and is issued under the
authority of Section lll(c) of the Clean
Air Act, as amended. (42 U.S.C. 7411(c)).
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 (WW) as
follows:
§60.4 Address.
* * * • *
(b) * ' *
(WW) ' * *
(vi) Olympic Air Pollution Control
Authority, 120 East State Avenue,
Olympia, WA 98501.
Dated: April 13, 1979.
DougUi M. Cfxtle.
Administrator.
[FRL 1202-6)
[FR Doc. 79-12211 Filed 4-18-79: 8:49 am)
BILLING CODE »S«0-01-M
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Part SO
1240-7]
KGCT Stationary Sources Performance
Standards; Electric Utility Steam
©oneratlng Units
fl@EMCv: Environmental Protection
Agency (EPA).
A@TOON: Final rule.
Y: These standards of
performance limit emissions of sulfur
dioxide (SO,), participate matter, and
nitrogen oxides (NOJ from new,
modified, and reconstructed electric
utility steam generating units capable of
combusting more than 73 megawatts
(MW) heat input (250 million Btu/hour)
of fossil fuel. A new reference method
for determining continuous compliance
with SO, and NO. standards is also
established. The Clean Air Act
Amendments of 1977 require EPA to
revise the current standards of
performance for fossil-fuel-fired
stationary sources. The intended effect
of this regulation is to require new,
modified; and reconstructed electric
utility steam generating units to use the
best demonstrated technological system
of continuous emission reduction and to
satisfy the requirements of the Clean Air
Act Amendments of 1977.
@flTES: The effective date of this
regulation is June 11, 1979.
ADDRESSES: A Background Information
Document (BID; EPA 450/3-79-021) has
been prepared for the final standard.
Copies of the BID may be obtained from
the U.S. EPA Library (MD-35), Research
Triangle Park, N.C. 27711, telephone
919-541-2777. In addition, a copy is
available for inspection in the Office of
Public Affairs in each Regional Office,
and in EPA's Central Docket Section in
Washington, D.C. The BID contains (1) a
summary of ah the public comments
made on the proposed regulation; (2) a
summary of the data EPA has obtained
since proposal on SO,, particulate
matter, and NO, emissions; and (3) the
final Environmental Impact Statement
which summarizes the impacts of the
regulation.
Docket No. OAQPS-78-1 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., ge
alljnO.OOSMonday through Friday, at
EPA's Central Docket Section, room
2903B, Waterside Mall, 401 M Street,
SW., Washington, D.C. 20460.
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
[section 107(d)(a)].
FOB FURTHER IWFORMaTIOM CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, N.C.
27711, telephone 919-541-5271.
INFORMATION: This
preamble contains a detailed discussion
of this rulemaking under the following
headings: SUMMARY OF STANDARDS.
RATIONALE, BACKGROUND,
APPLICABILITY, COMMENTS ON
PROPOSAL, REGULATORY
ANALYSIS, PERFORMANCE TESTING,
MISCELLANEOUS.
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 SO, standards are as follows:
(1) Solid and solid-derived fuels
(except solid solvent refined coal): SO,
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 mg/J (0.60
Ib/million Btu) heat input, a 70 percent
reduction in potential emissions is
required. Compliance with the emission
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 SO» removed by all types of SO,
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 limited 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
SO, emissions into the atmosphere are
less than 86 ng/J (0.20 Ib/million Btu)
heat input. Compliance with the SOj
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 Mariana IslaHs)
are exempt from the percentage
reduction requirement of the SO,
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 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 Ib/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
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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 for SRC I, which
is to be obtained at the refining facility
itself, is 85 percent reduction in potential
SO, 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 emission to 20 percent (6-
minute average). The standards are
based on the performance of a well-
designed and operated baghouse or
electostatic precipitator (ESP).
Nd 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 any 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 would be
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 plants, using SRC I
would be 80 percent (based on a 24-hour
average). The plant producing the SRC I
would monitor to insure that the
required percentage reduction (24-hour
average) is achieved and the power
plant using the SRC I would monitor to
insure that the 520 ng/J heat 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 SOj 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 o
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:
Equivalent
Technology 'Pollutant electrical capacity
MW
Solid solvent-refined coal
Fluidized bed combustion
(atmospheric)
Fluidized bed combustion
(pressurized)
Coal liquefaction „
SO, .
so,
so.
NO,
5,000-10,000
400-3,000
200-1.200
750-10,000
Compliance Provisions
Continuous compliance with the SOi
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
continuous emission monitors
malfunction, to provide emissions data
for at least 18 hours of each day for at
least 22 days out of any 30 successive
days of boiler operation.
A malfunctioning FGD system may be
Bypassed under emergency conditions.
Compliance with the particulate
standard is determined through
performance tests. Continuous monitors
are required to measure and record the
opacity of emissions. This data is to be
used to identify excess emissions to
insure that the particulate matter control
system is being properly operated and
maintained.
Rationale
SOj Standards
Under section 111 (a) of the Act, a
standard of performance for a fossil-
fuel-fired stationary source must reflect
the degree of emission limitation and
percentage reduction achievable through
the application of the best technological
system of continuous emission reduction
taking into consideration cost and any
nonair quality health and environmental
impacts and energy requirements. In
addition, credit may be given for any
cleaning of the fuel, or reduction in
pollutant characteristics of the fuel, after
mining and prior to combustion.
ki the 1977 amendments to the Clean
Air Act, Congress was severely critical
of the current standard of performance
for power plants, and especially of the
fact that it could be met by the use of
untreated low-sulfur coal. The House, in
particular, felt that the current standard
failed to meet six of the purposes of
section 111. The six purposes are (H.
Kept, at 184-186):
1. The standards must not give a
competitive advantage to one State over
another in attracting industry.
2. The standards must maximize the
potential for long-term economic growth
by reducing emissions as much as
practicable. This would increase the
amount of industrial growth possible
within the limits set by the air quality
standards.
3. The standards must to the extent
practical force the installation of all the
control technology that will ever be
necessary on new plants at the time of
construction when it is cheaper to
. install, thereby minimizing the need for
retrofit in the future when air quality
standards begin to set limits to growth.
4 and 5. The standards to the extent
practical must force new sources to burn
high-sulfur fuel thus freeing low-sulfur
fuel for use in existing sources where it
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is harder to control emissions and where
low-sulfur fuel is needed for compliance.
This will (1) allow old sources to
operate longer and (2) expand
environmentally acceptable energy
supplies.
6. The standards should be stringent
in order to force the development of
improved technology.
To deal with these perceived
deficiences, the House initiated
revisions to section 111 as follows:
1. New source performance standards
must be based on the "best
technological" control system that has
been "adequately demonstrated," taking
cost and other factors such as energy
into account. The insertion of the word
"technological" precludes a new source
performance standard based solely on
the use of low-sulfur fuels.
2. New source performance standards
for fossil-fuel-fired sources (e.g., power
plants) must require a "percentage
reduction" in emissions, compared to
the emissions that would result from
burning untreated fuels.
The Conference Committee generally
followed the House bill. As a result, the
1977 amendments substantially changed
the criteria for regulating new power
plants by requiring the application of
technological methods of control to
minimize SOa emissions and to
maximize the use of locally available
coals. Under the statute, these goals are
to be achieved through revision of the
standards of performance for new fossil-
fuel-fired stationary sources to specify
(1) an emission limitation and (2) a
percentage reduction requirement.
According to legislative history
accompanying the amendments, the
percentage reduction requirement
should be applied uniformly on a
nationwide basis, unless the
Administrator finds that varying
requirements applied to fuels of differing
characteristics will not undermine the
objectives of the house bill and other
Act provisions.
The principal issue throughout this
rulemaking has been whether a plant
burning low-sulfur coal should be
required to achieve the same percentage
reduction in potential SOa emissions as
those burning higher sulfur coal. The
public comments on the proposed rules
and subsequent analyses performed by
the Office of Air, Noise and Radiation of
EPA served to bring into focus several '
other issues as well.
These issues included performance
capabilities of SOa control technology,
the averaging period for determining
compliance, and the potential adverse
impact of the emission ceiling on high-
sulfur coal reserves.
Prior to framing the final SOa
standards, the EPA staff carried out
extensive analyses of a range of
alternative SO« standards using an
econometric model of the utility sector.
As part of this effort, a joint working
group comprised of representatives from
EPA, the Department of Energy, the
Council of Economic Advisors, the
Council on Wage and Price Stability,
and others reviewed the underlying
assumptions used in the model. The
results of these analyses served to
identify environmental, economic, and
energy impacts associated with each of
the alternatives considered at the
national and regional levels. In addition,
supplemental analyses were performed
to assess impacts of alternative
emission ceilings on specific coal
reserves, to verify performance
characteristics of alternative SO»
scrubbing technologies, and to assess
the sulfur reduction potential of coal
preparation techniques.
Based on the public record and
additional analyses performed, the
Administrator concluded that a 90
percent reduction in potential SOj
emissions (30-day rolling average) has
been adequately demonstrated for high-
sulfur coals. This level 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 bottom ash are also
applicable. In reaching this finding, the
Administrator considered the
performance of currently operating FGD
systems (scrubbers) and found that
performance could be upgraded to
achieve the recommended level with
better design, maintenance, and
operating practices. A more stringent
requirement based on the levels of
scrubber performance specified for
lower sulfur coals in a number of
prevention of significant deterioration
permits was not adopted since
experience with scrubbers operating
with such performance levels on high-
sulfur coals is limited. In selecting a 30-
day rolling average as the basis for
determining compliance, the
Administrator took into consideration
effects of coal sulfur variability on
scrubber performance as well as
potential adverse impacts that a shorter
averaging period may have on the
ability of small plants to comply.
With respect to lower sulfur coals, the
EPA staff examined whether a uniform
or variable application of the percent
reduction requirement would best
satisfy the statutory requirements of
section 111 of the Act and the supporting
legislative history. The Conference
Report for the Clean Air Act
Amendments of 1977 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.
In the face of such language, it is clear
that Congress established a presumption
in favor of a uniform application of the
percentage reduction requirement and
that any departure would require careful
analysis of objectives set forth in the
House bill and the Conference Report.
This question was made more
complex by the emergence of dry SOj
control systems.. As a result of public
comments on the discussion of dry SOj
control technology in the proposal, the
EPA staff examined the potential of this
technology in greater detail. It was
found that the development of dry SO,
controls has progressed rapidly during
the past 12 months. Three full scale
systems are being installed on utility
boilers with scheduled start up in the
1981-1982 period. These already
contracted systems have design
efficiencies ranging from 50 to 85
percent SOa removal, long term average.
In addition, it was determined that bids
are currently being sought for five more
dry control systems (70 to 90 percent
reduction range) for utility applications.
Activity in the dry SOa control field is
being stimulated by several factors.
First, dry control systems are less
complex than wet technology. These
simplified designsjoffer the prospect of
greater reliability at substantially lower
costs than their wet counterparts.
Second, dry systems use less water than
wet scrubbers, which is an important
consideration in the Western part of the
United States. Third, the amount of
energy required to operate dry systems
is less than that required for wet
systems. Finally, the resulting waste
product is more easily disposed of than
wet sludge.
The applicability of dry control
technology, however, appears limited to
low-sulfur coals. At coal sulfur contents
greater than about 1290 ng/J (3 pounds
SO,/million Btu), or about 1.5 percent
sulfur coal, available data indicate that
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it probably will be more economical to
employ a wet scrubber than a dry
control system.
Faced with these findings, the
Administrator had to determine what
effect the structure of the final
regulation would have on the continuing
development and application of this
technology. A thorough engineering
review of the available data indicated
that a requirement of 80 percent
reduction in potential SO» emissions
would be likely to constrain the full
development of this technology by
limiting its potential applicability to high
alkaline content, low-sulfur coals. For
non-alkaline, low-sulfur coals, the
certainty of economically achieving a 80
percent reduction level is markedly
reduced. In the face of this finding, it
would be unlikely that the technology
would be vigorously pursued for these
low alkaline fuels which comprise
approximately one half of the Nation's
low-sulfur coal reserves. In view of this,
the Administrator sought a percentage
reduction requirement that would
provide an opportunity for dry SOS
technology to be developed for all low-
sulfur coal reserves and yet would be
sufficiently stringent to assure that the
technology was developed to its fullest
potential. The Administrator concluded
that a variable control approach with a
minimum requirement of 70 percent
reduction potential in SOj emissions (30-
day rolling average) for low-sulfur coals
would fulfill this objective. This will be
discussed in more detail later in the
preamble. Less stringent, sliding scale
requirements such as those offered by
the utility industry and the Department
of Energy were rejected since they
would have higher associated emissions,
would not be significantly less costly,
and would not serve to encourage
development of this technology.
In addition to promoting the
development of-dry SO8 systems, a
variable approach offers several other
advantages often cited by the utility
industry. For example, if a source chose
to employ wet technology, a 70 percent
reduction requirement serves to
substantially reduce the energy impact
of operating wet scrubbers in low-sulfur
coals. At this level of wet scrubber
control, a portion of the untested flue
gas could be used for plume reheat so as
to increase plume buoyancy, thus
reducing if not eliminating the need to
expend energy for flue gas reheat.
Further, by establishing a range of
percent reductions, a variable approach
would allow a source some flexibility
particularly when selecting intermediate
sulfur content coals. 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.
While these points alone would not be
sufficient to warrant adoption of a
variable standard, they do serve to
supplement the benefits associated with
permitting the use of dry technology.
Regarding the maximum emission
limitation, the Administrator had to
determine a level that was appropriate
when a 80 percent reduction in potential
emissions was applied to high-sulfur
coals. Toward this end, detailed
assessments of the potential impacts of
a wide range of emission limitations on
high-sulfur coal reserves were
performed. The results revealed that a
significant portion (up to 30 percent) of
the high-sulfur coal reserves in the East,
Midwest and portions of the Northern
Appalachia coal regions would require
more than a SO percent reduction if the
emission limitation were established
below 520 ng/J (1.2 Ib/million Btu) heat
input 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 (1.2 Ib/million Btu) heat input on a
30-day rolling average basis. A more
stringent emission limit would be
counter to one of the purposes of the
1977 Amendments, that is, encouraging
the use of higher sulfur coals.
Having determined an appropriate
emission limitation and that a variable
percent reduction requirement should be
established, the Administrator directed
his attention to specifying the final form
of the standard. In doing so, he sought to
achieve the best balance in control
requirements. This was accomplished by
specifying a 520 ng/J (1.2 Ib/million Btu)
heat input emission limitation with a 80
percent reduction in potential SOj
emissions except when emissions to the '
atmosphere were reduced below 260 ng/
J (0.6 Ib/million Btu) heat input (30-day
rolling average), when only a 70 percent
reduction in potential SO« emissions
would apply. Compliance with each of
the requirements would be determined
on the basis of a 30-day rolling average.
Under this 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- or low-sulfur content
coals would be permitted to achieve
between 70 and 90 percent reduction.
provided their emissions were less than
280 ng/J (0.6 Ib/million Btu). The 260 ng/
J (0.6 Ib/million Btu) level was selected
to provide for a emooth transition of the
percentage reduction requirement from
high- to low-sulfur coals. Other
transition points were examined but not
adopted since they tended to place
certain types of coal at a disadvantage.
By fashioning the SO, standard in this
manner, the'Administrator believes he
has satisfied both the statutory language
of section 111 and the pertinent part of
the Conference Report. The standard
reflects a balance in environmental,
economic, and energy considerations by
being sufficiently stringent to bring
about substantial reductions in SO*
emissions (3 million tons in 1995) yet
does so at reasonable costs without
significant energy penalties. When
compared to a uniform 80 percent
reduction, the standard achieves the
same emission reductions at the
national level. More importantly, by
providing an opportunity for full
development of dry SOB technology the
standard offers potential for further
emission reductions (100 to 200
thousand tons per year), cost savings
(over $1 billion per year), and a
reduction in oil consumption (200
thousand barrels per day) when
compared to a uniform standard. The
standard through its balance and
recognition of varying coal
characteristics, serves to expand
environmentally acceptable energy
supplies without conveying a
competitive advantage to any one coal
producing region. The maintenance of
the emission limitation at 520 ng/J (1.2 Ib
SOa/million Btu) will serve to encourage
the use of locally available high-sulfur
coals. By providing for a range of
percent reductions, the standard offers
flexibility in regard to burning of
intermediate sulfur content coals. By
placing a minimum requirement of 70
percent on low-sulfur coals, the final
rule encourages the full development
and application of dry SO, control
systems on a range of coals. At the same
time, the minimum requirement is
sufficiently stringent to reduce the
amount of low-sulfur coal that moves
eastward when compared to the current
standard. Admittedly, a uniform 90
percent requirement would reduce such
movements further, but in the
Administrator's opinion, such gains
would be of marginal value when
compared to expected increases in high-
sulfur coal production. By achieving a
balanced coal demand within the utility
sector and by promoting the
development of less expensive SO»
control technology, the final standard
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will expand environmentally acceptable
energy supplies to existing power plants
and industrial sources.
By substantially reducing SO,
emissions, the standard will enhance the
potential for long term economic growth
at both the national and regional levels.
While more restrictive requirements
may have resulted in marginal air
quality improvements locally, their
higher costs may well have served to
retard rather than promote air quality
improvement nationally by delaying the
retirement of older, poorly controlled
plants.
The standard must also be viewed
within the broad context of me Clean
Air Act Amendments of 1977. It serves
as a minimum requirement for both
prevention of significant deterioration
and non-attainment considerations.
When warranted by local conditions,
ample authority exists to impose more
restrictive requirements through the
case-by-case new source review
process. When exercised in conjunction
with the standard, these authorities will
assure that our pristine areas and
national parks are adequately protected.
Similarly, in those areas where the
attainment and maintenance of the
- ambient air quality standard is
threatened, more restrictive
requirements will be imposed.
The standard limits SOt emissions
from facilities firing gaseous or liquid
fuels to 340 ng/J {0.80 Ib/million Btu)
heat input and requires 90 percent
reduction in potential emissions on a 30-
day rolling average basis. The percent
reduction does not apply when
emissions are less than 86 ng/J (0.20 lb/
million Btu) heat input on a 30-day
rolling average basis. This reflects a
change to the proposed standards in
that the time for compliance is changed
from the proposed 24-hour basis to a 30-
day rolling average. This change is
necessary to make the compliance times
consistent for all fuels. Enforcement of
the standards would be complicated by
different averaging times, particularly
when more than one fuel is used.
Particulate Matter Standard
The standard for paniculate matter
limits the emissions to 13 ng/J (0.03 lb/
million Btu) heat input and requires a 99
percent reduction in uncontrolled
emissions for solid fuels and a 70
percent reduction for liquid fuels. No
particulate matter control is necessary
for units firing gaseous fuels alone, and
a percent reduction is not required. The
percent reduction requirements for solid
and liquid fuels are not controlling, and
compliance with the particulate matter
emission limit will assure compliance
with the percent reduction requirements.
A 20 percent (6-tninute average)
opacity limit is included in this
standard. The opacity limit is included
to insure proper operation and
maintenance of the emission control
system. If an affected facility were to
comply with all applicable standards
except opacity, the owner or operator
may request that the Administrator,
under 40 CFR 60.11(e), establish a
source-specific opacity limit for that
affected facility.
The standard is based on the
performance of a well'designed,
operated and maintained electrostatic
precipitator (ESP) or baghouse control
system. The Administrator has
determined that these control systems
are the best adequately demonstrated
technological systems of continuous
emission reduction (taking into
consideration the cost of achieving such
emission reduction, and nonair quality
health and environmental impacts and
energy requirements).
Electrostatic Precipitators
EPA collected emission data from 23.
ESP-equipped steam generating units
which were firing low-sulfur coals (0.4-
1.9 percent). EPA evaluated emission
levels from units burning relatively low-
sulfur coal because it is more difficult
for an ESP to collect particulate matter
emissions generated by the combustion
of low-sulfur coal than high-sulfur coaJL
None of the ESP control systems at the.
21 coal-fired steam generators tested
were designed to achieve a 13 ng/J (0.03
Ib/million Btu) heat input emission level,
however, emission levels at 9 of the 21
units were below the standard. All of
the units that were firing coal with a
sulfur content between 1.0 and 1.9
percent and which had emission levels
below the standard had either a hot-side
ESP (an ESP located before the
combustion air preheater) with a
specific collection area greater than 89
square meters per actual cubic meter per
second {452 ft'/l.OOO ACFM), or a cold-
side ESP (an ESP located after the
combustion air preheater) with a
specific collection area greater than 85
square meters per actual cubic meter per
second {435 ftVl.OOO ACFM).
ESP's require a larger specific
collection area when applied to units
burning low-sulfur coal than to units
burning high-sulfur coal because the
electrical resistivity of the fly ash is
higher with low-sulfur coaL Based on an
examination of the emission data in the
record, it is the Administrator's
judgment that when low-sulfur coal is
being Bred an ESP must have a specific
collection area from about 130 (hot side)
to 200 (cold side) square meters per
actual cubic meter per second (650 to
1,000 ft2 per 1,000 ACFM) to comply with
the standard. When high-sulfur coal
(greater than 3.5 percent sulfur) is being
fired an ESP must have a specific
collection area of about 72 (cold side)
square meters per actual cubic meter per
second (360 ft'per 1,000 ACFM) to
comply with the standard.
Cold-side ESP's have traditionally
been used to cqntrol particulate matter
emissions from power plants. The
problem of ESP collection of high-
electrical-resistivity fly ash from low-
sulfur coal can be reduced by using a
hot-side ESP. Higher fly ash collection
temperatures result in better ESP
performance by reducing fly ash
resistivity for most types of low-sulfur
coal. Reducing fly ash resistivity in itself
would decrease the ESP collection plate
area needed to meet the standard;
however, for a hot-side ESP this benefit
is reduced by the increased flue gas
volume resulting from the higher flue gas
temperature. Although a smaller
collection area is required for a hot-side
ESP than for a cold side ESP. this benefit
is offset by greater construction costs
due to the higher quality of materials.
thicker insulation, and special design
provisions to accommodate the
expansion and warping potential of the
collection plates.
Baghouses
The Administrator has evaluated data
from more than 50 emission test runs
conducted at 8 baghouse-equipped coal-
fired steam generating units. Although
none of these baghouse-controlled units
were designed to achieve a 13 Ng/J (0.03
Ib/million Btu) heat input emission level.
48 of the test results achieved this level
and only 1 test at each of 2 units
exceeded 13 Ng/J (0.03 Ib/million Btu)
heat input. The emission levels at the
two units with emission levels above 13
Ng/J (0.03 Ib/million Btu) heat input
could conceivably be reduced below
that level through an improved
maintenance program. It is the
Administrator's judgment that
baghouses with an air-to-cloth ratio of
0.6 actual cubic meter per minute per
square meter (2 ACFM/ft2) will achieve
the standard at a pressure drop of less
than 1.25 kilopascals (5 in. H,O). The
Administrator has concluded that this
air/cloth ratio and pressure drop are
reasonable when considering cost,
energy, and nonair quality impacts.
When an owner or operator must
choose between an ESP and a baghoose
to meet the standard, it is the
Administrator's judgment that
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baghouses have an advantage for low-
sulfur coal applications and ESP's have
an advantage for high-sulfur coal
applications. Available data indicate
that for low-sulfur coals, ESP's (hot-side
or cold-side) require a large collection
area and thus ESP control system costs
will be higher than baghouse control
system costs. For high-sulfur coals, large
collection areas are not required for
ESP's, and ESP control systems offer
cost savings over baghouse control
systems.
Baghouses have not traditionally been
used at utility power plants. At the time
these regulations were proposed, the
largest baghouse-controlled coal-fired
steam generator for which EPA had
particulate matter emission test data
had an electrical output of 44 MW.
Several larger baghouse installations
were under construction and two larger
units were initiating operation. Since the
date of proposal of these standards, EPA
has tested one of the new units. It has
an electrical output capacity of 350 MW
and is fired with pulverized,
subbituminous coal containing 0.3
percent sulfur. The baghouse control
system for this facility is designed to
achieve a 43 Ng/J (0.01 Ib/million Btu)
heat input emission limit. This unit has
achieved emission levels below 13 Ng/J
(0.03 Ib/million Btu) heat input. The
baghouse control system was designed
with an air-to-cloth ratio of 1.0 actual
cubic meter per minute per square meter
(3.32 ACFM/ft7) and a pressure drop of
1.25 kilopascals (5 in. H»O). Although
some operating problems have been
encountered, the unit is being operated
within its design emission limit and the
level of the standard. During the testing
the power plant operated in excess of
300 MW electrical output. Work is
continuing on the control system to
improve its performance. Regardless of
type, large emission control systems
generally require a period of time for the
establishment of cleaning, maintenance,
and operational procedures that are best
suited for the particular application.
Baghouses are designed and
constructed in modules rather than as
one large unit. The baghouse control
system for the new 350 MW power plant
has 28 baghouse modules, each of which
services 12.5 MW of generating
capacity. As of May 1979, at least 26
baghouse-equipped coal-fired utility
steam generators were operating, and an
additional 28 utility units are planned to
start operation by the end of 1982. About
two-thirds of the 30 planned baghouse-
controlled power generation systems
will have an electrical output capacity
greater than 150 MW, and more than .
one-third of these power plants will be
fired with coal containing more than 3
percent sulfur. The Administrator has
concluded that baghouse control
systems have been adequately
demonstrated for full-sized utility
application.
Scrubbers
EPA collected emission test data from
seven coal-fired steam generators
controlled by wet particulate matter
scrubbers. Emissions from five of the
seven scrubber-equipped power plants
were less than 21 Ng/J (0.05 Ib/million
Btu) heat input. Only one of the seven
units had emission test results less than
13 Ng/J (0.03 Ib/million Btu) heat input.
Scrubber pressure drop can be
increased to improve scrubber
particulate matter removal efficiencies;
however, because of cost and energy
considerations, the Administrator
believes that wet particulate matter
scrubbers will only be used in special
situations and generally will not be
selected to comply with the standards.
Performance Testing
When the standards were proposed,
the Administrator recognized that there
is a potential for both FGD sulfate
carryover and sulfuric acid mist to affect
particulate matter performance testing
downstream of an FGD system. Data
available at the time of proposal
indicated that overall particulate matter
emissions, including sulfate carryover,
are not increased by a properly
designed, constructed, maintained, and
operated FGD system. No additional
information has been received to alter
this finding.
The data available at proposal
indicated that sulfuric acid mist (HjSO4)
interaction with Methods 5 or 17 would
not be a problem when firing low-sulfur
coal, but may be a problem when firing
high-sulfur coals. Limited data obtained
since proposal indicate that when high-
sulfur coal is being fired, there is a
potential for sulfuric acid mist to form
after an FGD system and to introduce
errors in the performance testing results
when Methods 5 or 17 are used. EPA has
obtained particulate matter emission
test data from two power plants that
were fired with coals having more than
3 percent sulfur and that were equipped
with both an ESP and FGD system. The
particulate matter test data collected
after the FGD system were not
conclusive in assessing the acid mist
problem. The first facility tested
appeared to experience a problem with
acid mist interaction. The second facility
did not appear to experience a problem
with acid mist, and emissions after the
ESP/FGD system were less than 13 ng/J
(0.03 Ib/million Btu) heat input. The tests
at both facilities were conducted using
Method 5, but different methods were
used for measuring the filter
temperature. EPA has initiated a review
of Methods 5 and 17 to determine what
~ modifications may be necessary to
avoid acid mist interaction problems.
Until these studies are completed the
Administrator is approving as an
optional test procedure the use of
Method 5 (or 17) for performance testing
before FGD systems. Performance
testing is discussed in more detail in the
PERFORMANCE TESTING section of
this preamble.
The particulate matter emission limit
and opacity limit apply at all times,
except during periods of startup,
shutdown, or malfunction. Compliance
with the particulate matter emission
limit is determined through performance
tests using Methods 5 or 17. Compliance
with the opacity limit is determined by
the use of Method 9. A continuous
monitoring system to measure opacity is
required to assure proper operation and
maintenance of the emission control
system but is not used for continuous
compliance determinations. Data from
the continuous monitoring system
indicating opacity levels higher than the
standard are reported to EPA quarterly
as excess emissions and not as
violations of the opacity standard.
The environmental impacts of the
revised particulate matter standards
were estimated by using an economic
model of the coal and electric utility
industries (see discussion under
REGULATORY ANALYSIS). This
projection took into consideration the
combined effect of complying with the
revised SO,, particulate matter, and NO,
standards on the construction and
operation of both new and existing
capacity. Particulate matter emissions
from power plants were 3.0 million tons
in 1975. Under continuation of the
current standards, these emissions are
predicted to decrease to 1.4 million tons
by 1995. The primary reason for this
decrease in emissions is the assumption
that existing power plants will come
into compliance with current state
emission regulations. Under these
standards, 1995 emissions are predicted
to decrease another 400 thousand tons
(30 percent).
NOt Standards
The NO, emission standards are
based on emission levels achievable
with a properly designed and operated
boiler that incorporates combustion
modification techniques to reduce NO,
formation. The levels to which NO,
emissions can be reduced with
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combustion modification depend not
only upon boiler operating practice, but
also upon the type of fuel burned.
Consequently, the Administrator has
developed fuel-specific NO. standards.
The standards are presented in this
preamble under Summary of Standards.
Continuous compliance with the NOE
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.
One change has been made to the*
proposed NO, standards. The proposed
standards would have required
compliance to be based on a 24-hour
averaging period whereas the final
standards require compliance to be
based on a 30-day rolling average. This
change was made because several of the
•comments received, one of which
included emission data, indicated that
more flexibility in boiler operation on a
day-to-day basis is needed to
accommodate slagging and other boiler
problems that may influence NO.
emissions when coal is burned. The
averaging period for determining
compliance with the NO. limitations for
gaseous and liquid fuels has been
changed from the proposed 24-hour to a
30-day rolling average. This change is
necessary to make the compliance times*
consistent for all fuels. Enforcement of
the standards would be complicated by
different averaging times, particularly
where more than one fuel is used. More
details on the selection of the averaging
period for coal appear in this preamble
under Comments on Proposal.
The proposed standards for coal
combustion were based principally on
the results of EPA testing performed at
six electric utility boilers, all of which
are considered to represent modem
boiler designs. One of the boilers was
manufactured by the Babcock and
Wilcox Company (B&W) and was
retrofitted with low-emission burners.
Four of the boilers were Combustion
Engineering, Inc. (CE) designs originally
equipped with overfire air, and one
boiler was a CE design retrofitted with
overfire air. The six boilers burned a
variety of bituminous and
subbituminous coals. Conclusions
drawn from the EPA studies of the
boilers were that the most effective
combustion modification techniques for
reducing NO. emitted from utility
boilers are staged combustion, low
excess air, and reduced heat release
rate. Low-emission burners were also
effective in reducing NO. levels during
the EPA studies.
In developing the proposed standards
for coal, the Administrator also
considered the following: (1) data
obtained from the boiler manufacturers
on 11 CE, three B&W. and three Foster
Wheeler Energy Corporation (FW)
utility boilers; (2) the results of tests
performed twice daily over 30-day
periods at three well-controlled utility
boilers manufactured by CE; (3) a total
of six months of continuously monitored
NO. emission data from two CE boilers
located at the Colstrip plant of the
Montana Power Company; (4) plans
underway at B&W, FW, and the Riley
Stoker Corporation (RS) to develop low-
emission burners and furnace designs;
(5) correspondence from CE indicating
that it would guarantee its new boilers
to achieve, without adverse side-effects,
emission limits essentially the same as
those proposed; and (6) guarantees
made by B&W and FW that their new
boilers would achieve the State of New
Mexico's NO, emission limit of 190 ng/J
(0.45 Ib/million Btu) heat input.
Since proposal of the standards, the
following new information has become
available and has been considered by
the Administrator. (1) additional data
from the boiler manufacturers on four
B&W and four RS utility boilers; (2) a
total of 18 months of continuously
monitored NO, data from the two CE
utility boilers at the Colstrip plant; (3)
approximately 10 months of
continuously monitored NO. data from
five other CE boilers; (4] recent
performance test results for a CE and a
RS utility boiler; and (5) recent
guarantees offered by CE and FW to
achieve an NO. emission limit of 190 ng/
J (0.45 Ib/million Btu) heat input in the
State of California. This and other new
information is discussed in "Electric
Utility Steam Generating Units,
Background Information for
Promulgated Emission Standards" (EPA
450/3-79-021).
The data available before and after
proposal indicate that NO. emission
levels below 210 ng/J (0.50 Ib/million
Btu] heat input are achievable with a
variety of coals burned in boilers made
by all four of the major boiler
manufacturers. Lower emission levels
are theoretically achievable with
catalytic ammonia injection, as noted by
several commenters. However, these
systems have not been adequately
demonstrated at this time on full-size
electric utility boilers that burn coal.
Continuously monitored NO. emission
data from coal-fired CE boilers indicate
that emission variability during day-to-
day operation is such that low NO,
levels can be maintained if emissions
are averaged over 30-day periods.
Although the Administrator has not
been able to obtain continuously
monitored data from boilers made by
the other boiler manufacturers, the
Administrator believes that the emission
variability exhibited by CE boilers over
long periods of time is also
characteristic of B&W, FW, and RS
boilers. This is because the
Administrator expects B&W, FW, and
RS boilers to experience operational
conditions which are similar to CE
boilers (e.g., slagging, variations in fuel
quality, and load reductions) when
burning similar fuel. Thus, the
Administrator believes the 30-day
averaging time is appropriate for coal-
fired boilers made by all four
manufacturers.'
Prior to proposal of the standards
several electric utilities and boiler
manufacturers expressed concern over
the potential for accelerated boiler tube
wastage (i.e., corrosion) during low-NO.
operation of a coal-fired boiler. The
severity of tube wastage is believed to
vary with several factors, but especially
with the sulfur content of the coal
burned. For example, the combustion of
high-sulfur bituminous coal appears to
aggravate tube wastage, particularly if it
is burned in a reducing atmosphere. A
reducing atmosphere is sometimes
associated with low-NO, operation.
The EPA studies of one B&W and Eve
CE utility boilers concluded that tube
wastage rates did not significantly
increase during low-NO, operation. The
significance of these results is limited,
however, in that the tube wastage tests
were conducted over relatively short
periods of time (30 days or 300 hours).
Also, only CE and B&W boilers were
studied, and the B&W boiler was not a
recent design, but was an old-style unit
retrofitted with experimental low-
emission burners. Thus, some concern
still exists over potentially greater tube
wastage during low-NO, operation
when high-sulfur coals are burned. Since
bituminous coals often have high sulfur
contents, the Administrator has
established a special emission limit for
bituminous coals to reduce the potential
for increased tube wastage during low-
NO. operation.
Based on discussions with the boiler
manufacturers and on an evaluation of
all available tube wastage information.
the Administrator has established an
NO. emission limit of 260 ng/J (0.60 lb/
million Btu) heat imput for the
combustion of bituminous coal. The
Administrator believes this is a safe
level at which tube wastage will not be
accelerated By low-NO, operation. In
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support of this belief, CE has stated that
it would guarantee rts BCW boilers, when
equipped with overfire air, to achieve
the 260 ng/J (0.60 Ib/million Btu) heat
input limit without increased tube
wastage rates when Eastern bituminous
coals are burned. In addition. B&W has
noted in several recent technical papers
that its low-emission burners allow the
furnace to be maintained in an oxidizing
atmosphere, thereby reducing the
potential for tube wastage when high-
sulfur bituminous coals are burned. The
other boiler manufacturers have also
developed techniques that reduce the
potential for tube wastage during k>w-
NO, operation. Although the amount of
tube wastage data available to the
Administrator on B&W, FW and RS
boilers is very limited, it is the
Administrator's judgement that all three
of these manufacturers are capable of
designing boilers which would not
experience increased tube wastage rates
as a result of compliance with the NO.
standards.
Since the potential for increased robe
wastage during low-NO, operation
appears to be small when low-sulfur
subbituminous coals are burned, the
Administrator has established a lower
NO, emission limit of 210 ng/J (0.50 lb/
million Btu) heat input for boilers
burning subbituminous coal. This limit is
consistent with emission data from
boilers representing all four
manufacturers. Furthermore, CE has
stated that it would guarantee its
modern boilers to achieve an NO, limit
of 210 ng/J (0.50 Ib/million Btu) heat
input, without increased tube wastage
rates, when subbituminous coals are
burned.
The emission limits for electric utility
power plants that burn liquid and
gaseous fuels are at the same levels as
the emission limits originally
promulgated in 1971 under 40 CFR Part
60, Subpart D for large steam generators.
It was decided that a new study of
combustion modification or NO, flue-gas
treatment for oil- or gas-fired electric
utility steam generators would not be
appropriate because few, if any, of these
kinds of power plants are expected to be
built in the future.
Several studies indicate that NO,
emissions from the combustion of fuels
derived from coal, such as liquid
solvent-refined coal (SRC II) and low-
Btu synthetic gas, may be higher than
those from petroleum oil or natural gas.
This is because coal-derived fuels have
fuel-bound nitrogen contents that
approach the levels found in coal rather
than those found in petroleum oil and
natural_gas. Based on limited emission
data from pilot-scale facilities and on
the known emission characteristics of
coal, the Administrator believes that an
achievable emission limit for solid
liquid, and gaseous fuels derived from
coal is 210 ng/j (O50 Ib/million Btu) beat
input Tube wastage and other boiler
problems are not expected to occur from
boiler operation at levels as low as 210
ng/J when firing these fuels because of
their low sulfur and ash contents.
NO, emission limits-for lignite
combustion were promulgated in 1978
(48 FR 9276) as amendments to the
original standards under 40 CFR Part 60,
Subpart D. Since no new information on
NO, emission rates from lignite
combustion has become available, the
emission limits have not been changed
for these standards. Also, these
emission limits are the same as the
proposed.
Little is known about the emission
characteristics of shale oil. However,
since shale oil typically has a higher
fuel-bound nitrogen content than
petroleum oil, it may be impossible for a
well-controlled unit burning shale oil to
achieve the NO, emission limit for liquid
fuels. Shale oil does have a similar
nitrogen content to coal, and it is
reasonable to expect that the emission
control techniques used for coal could
also be used to limit NO, emissions from
shale oil combustion. Consequently, the
Administrator has limited NO,
• emissions from units burr Jng shale oil to
210 ng/J (0.50 Ib/million Btu) heat input.
the same limit applicable to.
subbituminons coaL which is the same
as proposed. There is no evidence that
tube wastage or other boiler problems
would result from operation of a boiler
at 210 ag/J when shale oil is burned.
The combustion of coal refuse was
exempted from the original steam
generator standards under 40 CFR Part
60, Subpart D because the only furnace
design believed capable of burning
certain kinds of coal refuse, the slag tap
furnace, inherently produces NO,
emissions in excess of the NO,
standard. Unlike lignite, virtually no
NO, emission data are available for the
combustion of coal refuse in slag tap
furnaces. The Administrator has
decided to continue the coal refuse
exemption under the standards
promulgated here because no new
information on coal refuse combustion
has become available since the
exemption under Subpart D was
established.
The environmental impacts of the
revised NO, standards were estimated
by using an economic model of the coal
and electric utility industries (see
discussion under REGULATORY
ANALYSIS). This projection took into
consideration the combined effect of
complying with the revised SO»
particulate matter, and NO, standards
on the construction and operation of
both new and existing capacity.
National NO, emissions from power
plants were 6.8 million tons in 1975 and
are predicted to increase to 9.3 million
tons by 1995 under the current
standards. These standards are
projected to reduce 1995 emissions by
600 thousand tons (6 percent).
Background
In December 1971, under section 111
of the Clean Air Act the Administrator
issued standards of performance to limit
emissions of SO* particulate matter,
and NO, from new, modified, and
reconstructed fossil-fuel-fired steam
generators (40 CFR 60.40 et seq.). Since
that time, the technology for controlling
emissions from this source category has
improved, but emissions of SO,,
particulate matter, and NO, continue to
be a national problem. In 1976, steam
electric generating units contributed 24
percent of the particulate matter, 65
percent of the SO* and 29 percent of the
NO, emissions on a national basis.
The utility industry is expected to
have continued and significant growth.
The capacity is expected to increase by
about 50 percent with approximate 300
new fossil-fuel-fired power plant boilers
to begin operation within the next 10
years. Associated with utility growth is
the continued long-term increase in
utility coal consumption from some 400
million tons/year in 1975 to about 1250
million tons/year in 1995. Under the
current performance standards for
power plants, national SO* emissions
are projected to increase approximately
17 percent between 1975 and 1995.
Impacts will be more dramatic on a
regional basis. For example, in the*
absence of more stringent controls,
utility SOj emissions are expected to
increase 1300 percent by 1995 in the
West South Central region of the
country (Texas, Oklahoma, Arkansas,
and Louisiana).
EPA was petitioned on August 6,1976,
by the Sierra Club and the Oljato and
Red Mesa Chapters of the Navaho Tribe
to revise the SO, standard so as to
require a 90 percent reduction in SO»
emissions from all new coal-fired power
plants. The petition claimed that
advances in technology since 1971
justified a revision of the standard. As •
result of the petition, EPA agreed to
investigate the matter thoroughly. On
January 27.1977 (42 FR 5121). EPA
announced that it had initiated a study
to review the technological, economic,
and other {actors needed to determine to
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what extent the~SOa standard for fossil-
fuel-fired steam generators should be
revised.
On August 7,1977, President Carter
oigned into law the'Clean Air Act
Amendments of 1977. The provisions
under section lll(b)(6) of the Act, as
amended, required EPA to revise the
otandards of performance for fossil-fuel-
fired electric utility steam generators
within 1 year after enactment.
After the Sierra Club petition of
August 1976, EPA initiated studies to
review the advancement made on
pollution control systems at power
plants. These studies were continued
following the amendment of the Clean
Air Act. In order to meet the schedule
established by the Act, a preliminary
assessment of the ongoing studies was
made in late 1977. A National Air
Pollution Control Techniques Advisory
Committee meeting was held on
December 13 and 14,1977, to present
EPA preliminary data. The meeting was
open to the public and comments were
solicited.
The Clean Air Act Amendments of
1977 required the standards to be
revised by August 7,1978. When it
appeared that the Administrator would
not meet this schedule, the Sierra Club
filed a complaint on July 14,1978, with
the U.S. District Court for the District of
Columbia requesting injunctive relief to
require, among other things,, that the
Administrator propose the revised
standards by August 7,1978 (Sierra Club
v. Costle, No. 78-1297). The Court,
approved a stipulation requiring the
Administrator to (1) deliver proposed
regulations to the Office of the Federal
Register by September 12,1978, and (2)
promulgate the final regulations within 6
months after proposal (i.e., by March 19,
1979).
The Administrator delivered the
proposal package to the Office of the
Federal Register by September 12,1978,
and the proposed regulations were
published September 19,1978 (43 FR
42154). Public comments on the proposal
were requested by December 15, and a
public hearing was held December 12
and 13, the record of which was held
open until January 15,1979. More than
625 comment letters were received on
the proposal. The comments were
carefully considered, however, the'
issues could not be sufficiently
evaluated in time to promulgate the
standards by March 19,1979. On that
date the Administrator and the other
parties in Sierra Club v. Costle filed
with the Court a stipulation whereby the
Administrator would sign and deliver
the final standards to the Federal
Register on or before June 1.1978.
The Administrator's conclusions and
responses to the major issues are
presented in this preamble. These
regulations represent the
Administrator's response to the petition
of the Navaho Tribe and Sierra Club and
fulfill the rulemaking requirements
under section lll{b)(6) of the Act.
Applicability
General
These 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. This is principally
the same as the proposal. Some minor
changes and clarification in the
applicability requirements for
cogeneration facilities and resource
recovery facilities have been made.
On December 23,1971, the
Administrator promulgated, under
Subpart D of 40 CFR Part 60, standards
of performance for fossil-fuel-fired
steam generators used in electric utility
and large industrial applications. The
standards adopted herein do not apply
to electric utility steam generating units
originally subject to those standards
(Subpart D) unless the affected facilities
. are modified or reconstructed as defined
under 40 CFR 60 Subpart A and this
subpart. Similarly, units constructed
prior to December 23,1971, are not
subject to either performance standard
(Subpart D or Da) unless they are
modified or reconstructed.
Electric Utility Steam Generating Units
An electric utility steam generating
unit is defined as any steam electric
generating unit that is physically
connected to a utility power distribution
system and is constructed for the
purpose of selling more than 25 MW
electrical output and more than one
third of its potential electrical output
capacity. Any steam that is sold and
ultimately used to produce electrical
power for sale through the utility power
distribution system is also included
under the standard. The term "potential
electrical generating capacity" has been
added since proposal and is defined as
33 percent of the heat input rate at the
facility. The applicability requirement of
selling more than 25 MW electrical
output capacity has also been added
since proposal.
These standards cover industrial'
steam electric generating units or
cogeneration units (producing steam for
both electrical generation and process
heat) that are capable of firing more
than 73 MW (250 million Btu/hr) heat
input of fossil fuel and are constructed
for the purpose of selling through a
utility power distribution system more
than 25 MW electrical output and more
than one-third of their potential
electrical output capacity (or steam
generating capacity ultimately used to
produce electricity for sale). Facilities
with a heat input rate in excess of 73
MW (250 million Btu/hour) that produce
only industrial steam or that generate
electricity but sell less than 25 MW
electrical output through the-utility
power distribution system or sell less
than one-third of their potential electric
output capacity through the utility
power distribution system are not 0
covered by these standards, but will
continue to be covered under Subpart D,
if applicable.
Resource recovery units incorporating
steam electric generating units that
would meet the applicability
requirements but that combust less than
25 percent fossil fuel on a quarterly (90-
day) heat-input basis are not covered by
the SO» percent reduction requirements
under this standard. These facilities are
subject to the SOs emission limitation
and all other provisions of the
regulation. They are also required to
monitor their heat input by fuel type and
to monitor SOj emissions. If more than
25 percent fossil fuel is fired on a
quarterly heat input basis, the facility
will be subject to the SO» percent
reductipn requirements. This represents
a change from the proposal which did
not include such provisions.
These standards cover steam
generator emissions from electric utility
combined-cycle gas turbines that are
capable of being fired with more than 73
MW (250 million Btu/hr) heat input of
fossil fuel and meet the other
applicability requirements. Electric
utility combined-cycle gas turbines that
use only turbine exhaust gas to provide
heat to a steam generator (waste heat
boiler) or that incorporate steam
generators that are not capable of being
fired with more than 73 MW (250 million
Btu/hr) of fossil fuel are not covered by
the standards.
Modification/Reconstruction
Existing facilities are only covered by
these standards if they are modified or
reconstructed as defined under Subpart
A of 40 CFR Part 60 and this standard
(Subpart Da).
Few, if any, existing facilities that
change fuels, replace burners, etc. will
be covered by these standards as a
result of the modification/reconstruction
provisions. In particular, the standards
do not apply to existing facilities that
are modified to fire nonfossil fuels or to
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existing facilities that were designed to
fire gas or oil fuels and that are modified
to fire shale oil, coal/oil mixtore*, coal/
oil/water mixtures, solvent refined coal,
liquified coal, gasified coal, or any other
coal-derived fuel. These provisions were
included in the proposal but have been
clarified in the final standard. '
Comments oa Proposal
Electric Utility Steam Generating Units
The applicability requirements are
basically the same as those in the
proposal; electric utility steam
generating units capable of firing greater
than 73 MW (250 million Btu/hour) heat
input of fossil fuel for which
construction is commenced after
September 18,1978, are covered. Since
proposal changes have been made to
specific applicability requirements for
industrial cogeneration facilities,
resource recovery facilities, and
anthracite coal-fired facilities. These
revisions are discussed later in this
preamble.
Only a limited number of comments
were received on the general
applicability provisions. Some
commenters expressed the opinion that
the standards should apply to both
industrial boilers and electric utility
steam generating units. Industrial.
boilers are not covered by these
standards because there are significant
differences between the economic,
structure of utilities and the industrial
sector. EPA is currently developing
standards for industrial boilers and
plans to propose them in 1980.
Cogeneration Facilities
degeneration facilities are covered
under these standards if they have the
capability of firing more than 73 MW
(250 million Btu/hour) heat input of
fossil fuel and are constructed for the
purpose of selling more than 25 MW of
electricity and more than one-third of
their potential electrical output capacity.
This reflects a change from the proposed
standards under which facilities selling
less than 25 MW of electricity through
the utility power-distribution system
may have been covered.
A number of commenters suggested
that industrial cogeneration facilities are
expected to be highly efficient and that
their construction could be discouraged
if the proposed standards were adopted.
The commenters pointed out that
industrial cogeneration facilities are
unusual in that a small capacity (10 MW
electric output capacity, for example)
steam-electric generating set may be
matched with a much larger industrial
steam generator (larger than 250 million
Btu/hr for example). The Administrator
intended that the proposed standards
cover only electric generation sets that
would seU more than 25 MW electrical
output on the utility power distribntion
system. The final standards allow the
sale of up to 25 MW electrical output
capacity before a facility is covered.
Since most industrial cogeneration units
are expected to be less than 25 MW
electrical output capacity, few, if any,
new industrial cogeneration units will
be covered by these standards. The
standards do cover large electric utility
cogeaeration facilities because such
units are fundamentally electric utility
steam generating units.
Comments suggested clarifying what
was meant hi the proposal by the sale of
more than one-third of its "maximum
electrical generating capacity". Under
the final standard the term "potential
electric output capacity" is used in place
of "maximum electrical generating
capacity" and is defined as 33 percent of
the steam generator heat input capacity.
Thus, a steam generator with a 500 MW
(1,700 million Btu/hr) heat input
capacity would have a 165 MW
potential electrical output capacity and
could sell up to one-third of this
potential output capacity on the grid (55
MW electrical output) before being
covered under the standard. Under the
proposal, it was unclear if the_standard
allowed the sale of up to one-third of the
actual electric generating capacity of a
facility or one-third of the potential
generating capacity before being
covered under the standards. The
Administrator has clarified his
intentions in these standards. Without
this clarification the standards may
have discouraged some industrial
cogeneration facilities that have low in-
house electrical demand.
A number of commenters suggested
that emission credits should be allowed
for improvements in cycle efficiency at
new electric utility power plants. The
commenters suggested that the use of
electrical cogeneration technology and
other technologies with high cycle
efficiencies could result in less overall
fuel consumption, which in turn could
reduce overall environmental impacts
through lower air emissions and less
solid waste generation. The final
standards do not give credit for
increases in cycle efficiency because the
different technologies covered by the
standards and available for commercial
application at this time are based on the
use of conventional steam generating
units which have very similar cycle
efficiencies, and credits for improved
cycle efficiency would not provide
measurable benefits. Although the final
standards do not address cycle
efficiency, this approach will not
discourage the application of more
efficient technologies.
If a facility that is planned for
construction will incorporate an
innovative control technology (including
electrical generation technologies with
inherently low emissions or high
electrical generation efficiencies) the
owner or operator may apply to the
Administrator under section 1110) of the
Act for an innovative technology waiver
which will allow for (1) ap to four years
of operation or (2) up to seven.years
after issuance of a waiver prior to
performance testing. The technology
would have to have a substantial
likelihood of achieving greater
continuous emission reduction or.
«chieve equivalent reductions at low
cost m terms of energy, economics, or
nonair quality impacts before a waiver
would be issued.
Resource Recovery Facilities
Electric utility steam generating unite
incorporated into resource recovery
faculties are exempt from the SO*
percent reduction requirements when
less than 25 percent of the heat input is
from fossil fuel on a quarterly heat input
basis. Such facilities are subject to all
other requirements of this standard. This
represents a change from the proposed
regulation, under'which any steam
electric generating unit that combusts
non-fossil fuels such as wood residue,
sewage sludge, waste material, or
municipal refuse would have been
covered if the facility were capable of
firing more than 75 MW (250 million
Btu/hr) of fossil fuel
A number of comments indicated that
the proposed standard could discourage
the construction of resource recovery
facilities that generate electricity
because of the SO, percentage reduction
requirement One commenter suggested
that most new resource recovery
facilities will process municipal refuse
and other wastes into a dry fuel with a
low-sulfur content that can be stored
and subsequently fired. The commenter
suggested that when firing processed
refuse fuel, little if any fossil fuel will be
necessary for combustion stabilization
over the long term; however, fossil fuel
will be necessary for startup. When a
cold unit is started, 100 percent fossil
fuel (oil or gas) may be fired for a few
hours prior to firing 100 percent
processed refuse.
Other commenters suggested that
resource recovery facilities would in
many cases be owned and operated by a
municipality and the electricity and
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steam generated would be sold by
contract to offset operating costs. Under
such an arrangement, commenters
suggested that there may be a need to
fire fossil fuel on a short-term basis
when refuse is not readily available in
order to generate a reliable supply of
steam for the contract customer.
The Administrator accepts these
suggestions and does not wish to
discourage the construction of resource
recovery facilities that generate
electricity and/or industrial steam. For
resource recovery facilities, the
Administrator believes that less than 25
percent heat input from fossil fuels will
be required on a long-term basis; even
though 100 percent fossil fuel firing
[greater than 73 MW (250 million Btu/
hour)] may be necessary for startup or
intermittent periods when refuse is not
available. During startup such units are '
allowed to fire 100 percent fossil fuel
because periods of startup are exempt
from the standards under 40 CFR 60.8(c).
If a reliable source of refuse is not
available and 100 percent fossil fuel is to
be fired more than 25 percent of the
time, the Administrator believes it is
reasonable to require such units to meet
the SOj percent reduction requirements.
This will allow resource recovery
facilities to operate with fossil fuel up to
25 percent of the time without having to
install and operate an FGD system.
Anthracite
These standards exempt facilities that
burn anthracite alone from the
percentage reduction requirements of
the SOj standard but cover them under
the 520 ng/J (1.2 Ib/million Btu) heat
input emission limitation and all
requirements of the particulate matter
and NO, standards. The proposed
regulations would have covered
anthracite in the same maner as all
other coals. Since the Administrator
recognized that there were arguments in
favor of less stringent requirements for
'anthracite, this issue was discussed in
the preamble to the proposed
regulations.
Over 30 individuals or organizations
commented on the anthracite issue.
Almost all of the commenters favored
exempting anthracite from the SO,
percentage reduction requirement. Some
of the reasons cited to justify exemption
were: (1) the sulfur content of anthracite
is low; (2) anthracite is more expensive
to mine and burn than bituminous and
will not be used unless it is cost
competitive; and (3) reopening the
anthracite mines will result in
improvement of acid-mine-water
conditions, elimination of old mining
scars on the topography, eradication of
dangerous fires in deep mines and culm
banks, and creation of new jobs. One '
commenter pointed out that the average
sulfur content of anthracite is 1.09
percent. Other commenters indicated
that anthracite will be cleaned, which
will reduce the sulfur content. One
commenter opposed exempting
anthracite, because it would result in
moreSOi emissions. Another
commenter said all coal-fired power
plants including anthracite-fired units
should have scrubbers.
After evaluating all of the comments,
the Administrator has decided to
exempt facilities that bum anthracite
alone from the percentage reduction
requirements of the SOi standard. These
facilities will be subject to all other
requirements of this regulation,
including the particulate matter and NO,
' standards, and the 520 ng/J (1.2 lb/
million Btu) heat imput emission
limitation under the SO, standard.
In 10 Northeastern Pennsylvania
counties, where about 95 percent of the
nation's anthracite coal reserves are
located, approximately 40,000 acres of
land have been despoiled from previous
anthracite mining. The recently enacted
Federal Surface Mining Control and
Reclamation Act was passed to provide
for the reclamation of areas like this.
Under this Act, each ton of coal mined is
taxed at 35 cents for strip mining and 15
cents for deep mining operations. One-
half of the amount taxed is
automatically returned to the State
where the coal mined and one-half is to
be distributed by the Department of
Interior. This tax is expected to lead
eventually to the reclamation of the
anthracite region, but restoration will
require many years. The reclamation
will occur sooner if culm piles are used
for fuel, the abandoned mines are
reopened, and the expense of
reclamation is born directly by the mine
operator.
The Federal Surface Mining Control
and Reclamation Act and a similar
Pennsylvania law also provide for the
establishment of programs to regulate
anthracite mining. The State of
Pennsylvania has assured EPA that total
reclamation will occur if anthracite
mining activity increases. They are
actively pursuing with private industry
the development of one area involving
12,000 to 19,000 acres of despoiled land.
In Summary, the Administrator
concludes that the higher SO2 emissions
resulting-from the use of anthracite
without a flue gas desulfurization
system is acceptable because of the
other environmental improvements that
will result. The impact of facilities using
anthracite on ambient air quality will be
minimized, because they will have to be
reviewed to assure compliance with the
prevention of significant deterioration
provisions under the Act.
Alaskan Coal
The final standards are the same as
the proposed; facilities fired with
Alaskan coal are covered in the same
manner as facilities fired with other
coals.
Commenters suggested that problems
unique to Alaska justify special
provisions for facilities located in
Alaska and firing Alaskan coal. Reasons
cited as justification for less stringent
standards by commenters on the
proposal were freezing conditions,
problems with sludge disposal, adverse
impact of FGD on the reliability of plant
operation, low-sulfur content of the coal,
and cost impact on the consumer. The
Administrator has examined these
factors and has concluded that
technically and economically feasible
means are available to overcome these
problems; therefore special regulatory
provisions are not justified.
In reaching this conclusion the
Administrator considered whether these
factors demonstrated that the standards
posed a substantially greater burden
unique to Alaska. In other northern
States where" severe freezing conditions
are common, plants are enclosed in
buildings and insulated vessels and
piping provide protection from freezing,
both for scrubber operation and for
liquid sludge dewatering. For an
equivalent electrical generating
capacity, the disposal sites for Alaskan
plants could be smaller than those for
most plants in the contiguous 48 States
because of the lower sulfur content of
Alaskan coal. Burying pipes carrying
sludge to waste ponds below the frost
line is feasible, except possibly in
permafrost areas. The Administrator
expects that future steam generators
cannot be sited in permafrost areas
because fly ash as well as scrubber
sludge could not be properly disposed of
in accordance with requirements of the
Resource Recovery and Reclamation
Act. In permafrost areas, turbines or
other non-iwaste-producing processes
are used or electricity is transmitted
from other locations.
One commenter pointed out that
failures of the FGD system would have
an adverse impact on the ability to
supply customers with reliable electric
service, since there are no extensive
interconnections with other utility
companies. The Administrator has
provided relief from the standards under
emergency conditions that would
require a choice between meeting a
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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 SO, 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 SO, percentage reduction
requirements. Such facilities are
required, however, to meet the SO,
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 SO,
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 SO, 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 NOE 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 SO, 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 provisions
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 SOi control systems as discussed
later in this section.
Since the standards were proposed,
EPA has continued to collect SOi 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 run-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 SOt removal, and
outlet SOS 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 lb SO,/million Btu and
89.2 percent SOi removal for fifty-six 24-
hour periods.
From December 1978 to February 1979,
'EPA gathered SOt 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.
I 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
SOi monitored data follows:
Scrubber
Coal«ulfur,
PCI
No. 0124-
hour periods
Average SOi
removal, pa
Conetvtne No. 6..
NIPSCO
LmmnceNo.4.
. Thiosorbic fcne/TCA......
. WellmarvUxd
. Ume/TCA
. Urnestone/cpny tower..
4.S
3.5
3.0
0.5
34
56
42
22
692
B9.2
ea.e
06.6
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 SOi 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 SO2 concentrations,
SO: 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 s
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 SO2 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 SO* emission
reduction. Coal cleaning does offer the
following benefits when used in
conjuction with an FGD system: (1) the
SO* 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 SOZ standard
percent removal requirement, and (3) the
SOa 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-600/7-78-030b) 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 -SCO/
7-7-78-030b) also acknowledge that SO
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 SO? 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 TV A,
Widows Creek No. 8 shows that FGD
systems can operate successfully at high
SOa 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 SO> 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 SO* concentrations
where ambient SOa 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 PCD 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
SOa emissions by 80 percent with a
limestone system at greater than 80
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
84 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 SOS 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 SO0 removal
exists. One comment was received
stating that 95 percent SO8 removal
should be required. The Administrator
concludes that higher SOa removals are
achievable for low-sulfur coal which
was the basis of this comment. While 95
percent SOa 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
alkali/regenerable systems would far
exceed vendor capabilities. When the
uncertainties of extrapolating
performance from GO 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 85 percent SO0 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 SO0 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
80 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'o background
documents and was not excluded from
consideration. Five commercial dry SO8
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) SO2
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 SOa and an
average of 2 gr/acf particulate matter.
With lime as the sorbent, the control
system removed over 86 percent SOD
and 99.88 percent particulate matter at a
stoichiometric ratio of 2.1 moles of lime
absorbent per inlet mole of SOs>. When
the spent lime dust was recirculated
from the bag filter to the lime slurry feed
tank, SOi removal efficiencies up to 80
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 SOa removal using lime as the
reactanUs technically feasible and
economically attractive in comparison
to wet scrubbing when coals containing
leoe 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 SO, 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 SOa
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 SO, 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 SOi 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 SO*
removal in context with averaging time,
that vendor guarantees were not based
on specific averaging times, and that
quoted SOa 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
SOj standards (a continuous 24-hour
average basis]. Concern was expressed,
however, about the proposed 24-hour
averaging requirement, and this
commenrer 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 SO, 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 SO, 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 SO, 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 SO,.
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 how 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 Regulatory 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 80 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 SO 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
email 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
60 percent reduction in potential SO3
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 SOi 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 80 percent
reduction if the 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 Sd
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 thai 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 SO» 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 SOj control systems which they felt
held considerable promise for bringing
about SOi 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 detailed
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 SO. emissions
except when emissions to the
atmosphere were reduced below 260 ng/
} (0.60 Ib/million Btu), when only a 70
percent reduction in potential SO>
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 SOi
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 spinnjng 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 SO,
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 SOa emissions from a
unit held in spinning reserve with
reduced output is expected to have
minor impact on the amount of SO»
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 SOj 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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SOa emitted on a pounds per hour basis,
but would also allow and exemption
from the percentage of SO: removal
specified by the SO» 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 colnmenter,
neglect of the FGD system would be
encouraged because an exemption
would allow routine operation at
reduced percentages of SOn 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-genera ting 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 SO2 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 SOj 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 SOa removal
requirement is not necessary to protect
electric service reliability or to maintain
compliance with these SOa standards.
Particu/ate 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 Btu)
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 (0.01 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
participate 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
450/3-7&-021), supports the conclusion
that ESPs ere applicable to both oil
firing and coal firing. The Administrator
believes that emissions from bil-fired
utility boilers should be controlled to the
same level as coal-fired boilers.
NO, 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 Btu)
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 comment 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 achieve 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 1*3 CE, seven Babcock and
Wilcox (BfiW), 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 NOn
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 y-,l 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-NOt
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 gurvey 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 260 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.)
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 SO percent NO,
removal at a coal-fired utility 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 180 ng/J (0.45 lb/
million Btu) heat input is based on boiler
manufacturer guarantees in 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 ISO 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, whicfi
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
1976 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 450/2-78-0078-1.
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 used 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 Avas specified approximately
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1979 / Rules and Regulations
equal to the moderate 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 SO 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 imp1 acts on full control than on
partial control options, the relative
differences in impacts w«,i*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 SOn
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
1260 ng/I or 3 Ib SOa/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 NOB 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 (SIP) regulations
and prevention of significant
deterioration requirements should not
be charged to the standards. These costs
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 SIP 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 participate 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/J (1.2 Ib/million Btu) emission limit
with a 90 percent reduction in potential
SO, 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 oition 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 SO, 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 SO, 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 emission reductions achieved
by new plants subject to the standard.
Projections of 1995 regional SO,
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 reduced 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 SOj
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 SO,
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 SO, 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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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1970 / Rules and Regulations
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 in 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 intermediate 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) nder 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 the 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
full 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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Federal Register f Vol. 44. No. 113 / Monday, June 11. 1979 / Rules and Regulations
Tobto 1.—Key Modeling Assumptions
Assumption
Growth latos...—_.
Nuclear capacity
Ol price* K 187S)_
Cos* 11
Coal mring labor costs—
Capital charge rate—
Coat reporting basis _
FGOoo*ts_
1975-1985: 4.8%/yr.
1965-1995: 4.0%.
1965: 97 GW.
1990: 165.
1995:228.
1985: 612.90/llOt
1990: »16.40.
1995:S21.00.
1% per ye* real increase.
U.M.W. settlement and 1* rod Incraau thereafter.
12.5% tor poMton control expendiue*.
1978do«af*.
< Cod dooninQ Graft.—.-™.m_™
Bottom ash and fty ash content..
No change from phase 2 analysis except for the addition of dry
• scrubbing systems tor certain apulicallons.
5%-35% SO, reduction assumed for Mgh suNur bkumhous coats
only.
No wwJrt *ttsurnod.
Table a.—National 1995 SO, Emissions From Utility Boilers •
(Minion tons]
Rant category
Level of control1
1975
Current standards
ItotM control
33% minimum
Variable control
70% minimum
Cry
Dry
WVNSPS Plants*
NewPtanti'-
Ol Plena..
ToM National
7.1
1.0
7.0
1.0
16.0
»1
1.4
3.1
1.4
rW Dry
15.9 16.2
34 8.4
14 1.2
Vet Dry
16.0 16.1
S.3 a.1
U 1.2
18.6
23.7
23.8
20.6
M.7
C0.6
(0.9
80.8
(0.5
Total Coal
Capacity (GW) 205
Skjdge generated (million
tons dry) . .. .
552
23
654
27
621
66
620
66
634
43
637
38
533
SO
537
41
•Results of joint EPA/DOE analyses completed In May 1979 baaed on ol price* of $12-90. $16.40, and KLOO/bbl to tne
yean 198S. 1990. and 1995. respectively.
•With 520 ng/J maximum emission limit
< Plants subject to existing State regulations or the current NSPS of t.21> SCVmMon 8TU
•Baaed on wet SO, scrubbing costs.
• Based on dry SO, scrubbing costs where ypf1 »¥»
'Plants subject to the revised standards.
Tabto 3.—Regional 1995 SO, Emissions From Utility Boilers *
(Million tons]
Level of control'
1975
Current standards
Ful control
Partial uoiiiiul
33% minimum
Variable uufiUul
70% minimum
Total National
Wtt- By4
184 23.7 23.8
TM Dry
IDS 10.7
20.8
oy
20.9
20.6
Dry
20.5
Fit"
MirJwost'
West South Central '.-.
Wfiatk
Total Coal
Capacity (GW) 205
115
8.1
2.6
1.7
6S2
112
iJ
2.6
1.7
554
\
SC2S
621
10.1
7J»
1.7
0.9
620
0.8
74
13
\2
634
8.8
•.0
1.8
\2
637
0.8
1»
1.8
1.1
633
».7
8.0
1.7
1.1
637
•Resutts of joint EPA/DOE analyses completed in May 1979 based on ol price* ol 612.90, $16.40. and S2t.00/bbl In the
years 1985.1990. and 1995. respectively.
•With 520 ng/J maximum emission fentl
• Based on wet SO, scrubbing costs.
• Based on dry SO, scrubbing costs where applicable.
• New England. Middle Atlantic, Soutf. Atlantic, and East South Central Census Ragtona.
•East North Central and West North Central Census Regions.
• West South Central Census Region.
» Mountain and Pactfle Census Regions.
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 participate 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 ra£ed 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 4—Impacts on Fuels In 199?
Level of control •
1975
actual
U.S. Coal Production (million
tons):
Appalaehia _ — —.
Midwest
Northern Great Plains....
West
Total
Western Coal Shipped East
(million tons) _
01 Consumpton by Power
Plants (million bbl/day):
Power Plants
Coal Transportation
Total
396
151
64
46
647
21
•3.1
Current standards
Wet*
489
404
655
~ 230
1.778
122
1.2
07
1.4
Dry'
524
391
630
222
1,767
89
17
07
1.4
Full control
Wet
463
487
633
182
1,765
69
1.6
07
1.6
465
488
628
160
1.761
65
1.6
07
1.8
. Partial control
33% minimum
Wet
475
456
622
212
1.765
68
1.4
0.2
1.6
Dry
486
452
676
226
1.742
59
1.4
07
1.6
Variable control
70% minimum
Wet
470
465
632
203
1.770
71
1.4
07
1.6
Dry
484
450
602
217
1.752
70
1.4
1.6
* Results of EPA analyses completed In May 1979 based on ol prices of $12.90. $18.40, and $21.00/bbl in the years 1985.
1990. and 1995. respectively.
• Wrth 520ng/J maximum emission NmrL
' Based on wet SO, scrubbing costs.
•Based on dry SO, scrubbing where applicable.
Tab* 5.—1995 Economic Impacts •
(1978 dollars)
Level of control'
Currant standards
Wet* Dry'
Average Monthly Residential Bills ($/
month) _ $53.00 $52.85
Indirect Consumer Impacts ($/month) „
Incremental Utility C0lal ExpenoV .
lures. Cumulative 1976-1995 ($ bi-
Knns)
Incremental Armuafaed Coat ($ bil-
lions) __.._
Present Value of Incremental Utility
Incremental Cost of SO* Reduction ($/
FuB control
Wet
$54.50
1.50
4
4.1
41
1,322
Dry
$54.45
1.60
5
4.4
45
1,426
Partial control
33% minimum
Wet
$54.15
1.15
6
37
32
1,094
Dry
$53.95
1.10
-3
3.0
31
1,012
Variable control
70% minimum
Wet
$54.30
1.30
10
3.6
37
1.163
Dry
$54.05
-1
3.3
33
1.036
•Results of EPA analyses completed in May 1979 based on OR prices of $12.90. $16.40, and $21.00/bbl in the years 1985,
1990, and 1995, respectively.
'With 520 ng/J maximum emission limit
' 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 sulfuric acid mist, which is
condensed in the FGD system, the
Administrator does not believe the
participate 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 5
or 17 are available.
SO, and NO,
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 (SOa only), except for those
periods when the CMS is inoperative
because of malfunctions, 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 it'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 the 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 SOi 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
SO2 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 n«ed to record the
operating parameters at all times, and
would imfjose 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 Tor a determination of compliance.
One commentsr provided calculations
showing that the CMS could report an
FGD efficiency ranging from 77.5 to SO
percent, with the scrubber operating at
an efficiency of 85 percent The analysis
submitted by the commenier 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 ia developing quality
assurance procedures, which wfll
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 for
fuel pretreatsaent to remove oulfur or
increase beat content. Paid {pratoastraent
credits are determined in accordance
with Method 19. Thio means that coal or
oil may be treated before firing and the
sulfur removed may be credited toward
meeting the SOi percentage Reduction
requirement Ths final Itiel prelreatestit
provisions are the came as these
proposed.
Most all oommienters on this issue
supported the fuel pretreatment
crediting procedureo 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 aloo allowed under tite proposal in
the optional "as-fired" fuel sampling
procedures muter the SOs esaiosion
monitoring requirements. By s&onitoring
SOa emissions (ng/J, Ib/million StoJ with
an as-fired fuel sampling system located
upstream of coal pulverizers find with
an in-stack continuous SOa saoaitoring
system downstream of the FGD system,
sulfur removal credits are combined for
the coal pulverizer, bottom •ash, By ash
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 £o?
refined fuel oil. The Administrator
intended to allow fuel pretreatment
credits for ell fuel oil desulfurization
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 owlfiar utility steam generator
fuel through ths •UBS of desulfurizatica
technology (soch as
hydrodesulfurization). The
Administrator believes that it is
appropriate to give full fue! pretreatment
credit for hydro treatment units and not
to penalize hydrodesulfurization units
which are used to process high-sulfur
residual oils. Thus, the input to the
hydrodesulfurization unil is sssed to
determine oil pretreatment credits and
nol the lower sulfur refinery input erode.
This procedure will allow fufl 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 ths
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 mot result im
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 o?
other similar reject material will oot •
change the potential SOa emission rats
(ng/J; Ib/million Btu).
An owner or operator of an affected
facility who elects to use fuel
pretreatment credits io {responsible for
insuring that the EPA Method 10
procedures ore followed in dstenrnnigg
SO] 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 feealth or
welfare (36 FR 5931), and by proposal of
regulations on September 19,1978 (<33 FR
42154). In addition, a preproposal public
hearing (May 25-26,1677) and a
postproposal public hearing (December
12-13,1978) was held after notification
was given in the Federal Kegister. Udder
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 til o? the
Clean Air Act reflect
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Application of the best technological
oyotem 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
a more stringent emission standard in
oeveral 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 (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, 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: Tune 1,1079.
Kouglas 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 Portorr.ianca teoto.
(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.
00000
(f) Unless otherwise specified in the
applicable subpart, each puformance
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:
flor Fossil-Fuel-Fired Steam Generators
(tor Which Construction Is Commenced
Atter August 17, 1 8711
3. Section 60.40 is amended by adding
paragraph (d) as follows:
Applicability end designation of
affected facility.
O 0 O O 6
(d) Any facility covered under Subpart
Da is not covered under Thip Subpart.
(Sec. Ill, 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601(a)).)
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 participate matter.
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogen oxides.
60.45a Commercial demonstration permit.
60.46a Compliance provisions.
60.47a Emission monitoring.
60.48a Compliance determination
procedures and methods.
80.49a Reporting requirements.
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1979 / Rules and Regulations
Authority: Sec. 111. 90Ha) of fce CSeati Air
Act as amended (42 U.S.C. 7411,76OT(«j), and
additional authority «* aoted below.
Subpart Da—Standard* of
Performance for EJectrtc Utility Steam
Generating Units for Which
Construction Is Commenced After
September W, 1976
160.40a Appncabfltty and designation of
affected facility.
(a) The affected facility to which this
•ubpart 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.
(b) This subpart applies to electric
utility combined cycle gas turbines that
are capable of combusting more than 73
megawatt* (250 million Btu/bour) 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 subpart
(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.
f 60.41a 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 used for
combusting fuel for the purpose of
producing steam (including fossfl-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 fen-
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 nch
material for the purpose of creating
useful heat.
"Sabbiruminons coat" means coal that
is classified as subbitaminow A, B, or C
according to the American Society of
Testing and Materials' (ASTM)
Standard Specification for Classification
of Coals by Rank 0388-06.
"Lignite" swans coal that M classified
as lignite A or B according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-66.
"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/miilion Btu heat input) that would
result from combustion of a fuel in an
uncleaned state 9without emission
control systems) and:
{a) For particulate matter is:
(1) 3,000 ng/J (7JO Ib/million Btu) heat
input for solid fuel; and
(2) 75 ng/J (0.17 Ib/million Btu) 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) beat
-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 Bin) 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, unclear units, hydroelectric
units, and all other electric generating
equipment) plus firm contractual
purchases that are interconnected to the
affected facility that has the
malfunctioning flue gas desolfuriration
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 (e-g.,
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)
BBSS 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 1CO-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 D388-86.
"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.
§ 80.42s Standard tor ^articulate 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 participate 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.
g S0.43a Standard (or ouNur dlcmldo.
(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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Federal Register / Vol. 44. No. 113 / Monday, June 11, 1979 / Rules and Regulations
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
Ego, = 1340 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 + 520 y]/100 and
PSO, = [90 x + 70 y]/100
where:
Eto, 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—PSO,)-
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)
J 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
Emission bruit
ng/J (fc/milbon Btu)
heat Input
Gaseous Fuels:
CoaWetived fuels „
M other fuels...
UquM Fuels:
CoeMertved fuels.
210
86
210
210
130
(0.60)
(0.20)
«0.50)
(0.50)
COJO)
SOU Fuels:
Coal-derived fuels 210
Any tu8l contsJnmQ rnoro thftn
25%, by weight, coal refuse. Exempt from NO,
standards and NO,
(0.50)
requirements
Any fuel containing more than
25%, by weight Ignite II the
Ignite is mined in North
Dakota. South Dakota, or
Montana, and is combusted
m a slag tap furnace ._
Lignite not subject to the 340
ng/J heat input emission limit
Subbituminous coal
Bituminous coal ,
Anthracite coal
AH other fuels
340
260
210
260
860
260
(OJO)
(0.60)
(0.50)
(0.60)
(0.60)
(0.60)
(2) NO, reduction requirements—
Fuel type
Pircont reduction
of potential
combustion
concentration
Gaseous fuels...
Liquid fuels
SoUd fuels
25%
90%
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 z)/100
where:
END, is 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
z is the percentage of total heat input derived
from the combustion of fuels subject to
the 260 ng/J heat input standard.
S 60.4Sa 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 issued 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 SO, 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 SO, 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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Keg&fltoff / VoL 414. No. 113 / Monday, jfune 11. 3979 / Sules and Regulations
heat input on a 30-day rolling average
bo ois.
(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
1S.CDQMW.
YccJuttfogy
PoZutaU
cfcctricof
ccpectly
(fcKV ctectnccl
E«Cif covert icSncd cod
(SRC 0
F&rtOzed ted ocmQustion
PtoBzed bsd ccmb«3tton
To3d cCoscto Cw ca
SO. 3,000-10,000
SO. CCO-S^JOO
SO.
KO,
400-1.2OO
730-10.000
15.000
(a) Compliance with the particulate
matter emission limitation under
8 a0.42a(a)(l) constitutes compliance
with the percent reduction requirements
for particulate matter under
8 eO.<92a(a)(2) and (3).
(to) Compliance with the nitrogen
oxides emission limitation under
0 &OMa(a] constitutes compliance with
the percent reduction requirements
under g B0.44a(a)(2).
{c) The particulate matter emission
otandardD under B 60.42a and the
nitrogen oxides emission standards
wtder § 80.44a apply at all times except
during periods of startup, shutdown, or
saelfunction. The sulfur dioxide emission
otondardo under § @Q.43a apply at all
times except during periods of startup,
ohutdown, or when both emergency
conditions exist and the procedures
tander paragraph (d) of this section are
implemented,
(d) During emergency conditions in
She 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
(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 60 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 Hue 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 g 60.43a and the nitrogen oxides
emission limitations under g
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Federal Register / Vol. 44, No. 113 / Monday. June 11, 1979 / Rules and Regulations
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 { 60.48a. 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
corrective 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 SO, 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
§ 60.13fc) and calibration checks under
J 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:
Fond fuel
Span value for
nitrogen oxides (ppm)
Gas..
Uquk)..
Solid
Combfnatia
600
600
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
x 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).)
8 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 that
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 points 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 S 60.43a.
(1) Determine the percent of potential
combustion concentration (percent PCC)
emitted to the atmosphere as follows:
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Federal Register / Vol. 44. No. 113 / Monday. June 11, 1979 / Rules and Regulations
(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 Rf 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 (%
Rg): 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 (% R,):
Determine the overall percent reduction
using the results obtained in paragraphs
(b)M (>) 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
paniculate 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.
S 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-is
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.
(8) 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 (nj
and inlet emission rates (n,) as
applicable.
(2) The standard deviation of hourly
averages for outlet emission rates (s0)
and inlet emission rates (s,) 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
(E,*) and the allowable emission rate
(£«,,) 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 (ng/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 $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
\. Principle and Applicability
1.1 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 Btu)
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 (pacing.
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
sixes may be specified subject to prior
approval of the Administrator.
2.1.3 Cross 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 ' following the practices outlined
• for continuous sampling for each gross
sample representing each fuel lot.
2.2.2 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 d6finitions 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 desutfurizajion 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 ' for the sample analysis. This value
can be assumed to be on a dry basis.
1 Use the moat recent revision or designation of
the ASTM procedure specified.
1 Use the most recent revision or designation of
the ASTM procedure specified.
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
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:
100 1
1
Where:
«R<=Sulfur dioxide removal efficiency due
pretreatment; percent.
%£>„=Sulfur content of the product fuel lot on
a dry basis: weight percent.
%S,=Sulfur content of the inlet fuel lot on a
dry basis; weight percent.
GCV0=Gross calorific value for the outlet
fuel lot on a dry basis; kj/kg (Btu/lb).
GCV,=Gross 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:
IS/GCV
n
.1
k-1
Where:
Yk=The fraction of total mass input derived
from each type, k, of fuel.
*S»=Sulfur content of each fuel type, k.'on a
dry basis; weight percent
GCVk=Gross 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 SOt
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
6. 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:
a
9(m)
• 100 x (1.0 -
ES02o
Where:
«R, = Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
inlet and outlet monitoring data; percent.
EIO 0=Sulfur dioxide emission rate from the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
~ EJO 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:
'•
'•
Where:
I
2.0(tSf)
~~GCV
2.0(«Sf)
GCV
x 10' for S. I. units.
x 10 for English units.
s » Sulfur dioxide Input rate from as-fired fuel analysis,
ng/J (Ib/million Btu).
ISf • 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, ESOJ. 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:
K9(0
100 x (1.0 -
'SO,
Where:
*"g(f) " Su1fur dioxide removal efficiency of the sulfur
dioxide control system using as-fired fuel analysis
data; percent.
Eso » Sulfur dioxide emission rate from sulfur dioxide control
. 2
system; ng/J (Ib/n1ll1on Btu).
I$ • Sulfur dioxide Input rate from as-fired fuel analysis;
ng/J (1b/m1111on Btu).
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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
W,
the base value. Any sulfur redaction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, WR,.-
4.2 Calculate the overall percent
sulfur reduction as:
Where:
JW • Overall sulfur dlcxtde'reduction; percent.
SR, • Sulfur dioxide removal 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
device either 0. or CO- - based calculation or calculated
fro* 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. (FH) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(F,i) 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
shows 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 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
Oi or CO* concentrations data obtained
in Section 3.1. Determine the particulate,
NO,, and O» or COt 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 (Fv) 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:
227.0(«Q * 95.7(tt) 4 35.4(tS) + 8.6(tN) - 28.5(M)
SCV
347.4(SH)+95.7(tC)+35.4(JS)+8.6(XN)-28.5(%0)+13.0(XH20)**
For English Units:
106C5.57(*H) * 1.53(»C) * 0.57(*S)
GCV
0.14(«) - 0.46«0)3
10[5.57(XHH .53(IC)+0.57(1S)+0.14(JN)-0.46(M)+0.
106[0.3?1(K)]
KV
The tHjO tent «ay be wonted if » and SO Include the unavailable
hydrogen and oxygen In the fora of H.O.
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Federal Register /Vol. 44, No. 113 / Monday, June 11, 1979 / Rules and Regulations
Where:
F* F,, and F, have the units of scm/J, or scf/
million Btu; «H, %C, %S, %N, %O, and
%H,O are the concentrations by weight
(expressed in percent) of hydrogen,
carbon, sulfur, nitrogen, oxygen, and
water from an ultimate analysis of the
fuel; and GCV is the gross calorific value
of the fuel in kj/kg or Btu/lb and
consistent with the ultimate analysis.
Follow ASTM D 2015* for solid fuels, D
240* for liquid fuels, and D 1826* for
gaseous fuels as applicable in '
determining GCV.
5.2.3 Combined Fuel Firing F Factor.
For affected facilities firing
combinations of fossil fuels or fossil
fuels and wood residue, the Fd, Fw, or Fe
factors determined by Sections 5.2.1 or
5.2.2 of this section shall be prorated in
accordance with applicable formula as
follows:
20.9
20.9
n
£
k-1
n
Z x
k-1
"k rdk
k Fwk
or
or
Fc " r xk Fck
c fcm1 k ck
Where:
xk=The fraction of total heat input derived
from each type of fuel, K,
n=The number of fuels being burned in .
combination.
5.3 Calculation of Emission Rate.
Select from the following paragraphs the
applicable calculation procedure and
calculate the particulate. SO,, and NO,
emission rate. The values in the
equations are defined as:
E = Pollutant emission rate, ng/J (Ib/million
Btu).
C= Pollutant concentration, ng/scm (Ib/scf).
Note. — It is necessary in some cases to
convert measured concentration units to
other units for these calculations.
Use the following table for such
conversions:
Conversion Factor* for Concentration
From-
To-
Multiply by—
ng/Kffl
no/son
ng/scni
ng/acm
b/«cf
ppm/(NOJ
5.3.1 Oxygen-Based F Factor
Procedure.
5.3.1.1 Dry Basis. When both percent
oxygen (%O,J and the pollutant
concentration (CJ are measured in the
flue gas on a dry basis, the following
equation is applicable:
,.
2fl.9 -
U2d
5.3.1:2 Wet Basis. When both the
percent oxygen (%Ot,) 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.)
C.F,
20.9
Where:
Bn^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
•elected to assure that any negative error
Introduced in the term:
(^
20.9
1 ' V"2w
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) 6,.=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 B.,
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.
20.9
(b) E - cw Fd [„
Where:
8,,=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 (%Oiw) is
measured on a wet basis, the following
equation is applicable:
B • 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. — F. 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;
F« or Fe 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:
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Federal RegUter / Vol. 44. No. 113 / Monday, )une 11, 1979 / Rules md 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
« - loon.o. O.o -
the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %R,.
4.2 Calculate the overall percent
sulfur reduction «s:
Where:
1R • Overall sulfur dioxide reduction; percent.
JR. » Sulfur dioxide removal efficiency of fuel pretreatment
fro* Section 2; percent. Refer to applicable subpart
for definition of applicable averaging period.
SR • Sulfur dioxide removal efficiency of sulfur dioxide control
device either 02 or CO- - based calculation or calculated
fro* 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 ire not applicable and may
not be used after wet scrubbers; (FJ or
{F
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1979 / Rules and Regulations
Where:
E»= Pollutant emission rate from steam
generator effluent. ng/J (Ib/million Btu).
E,=Pollutant emission rate in combined
cycle effluent; ng/J (Ib/million Btu).
Ew=Pollutant emission rate from gas turbine
effluent; ng/J (Ib/million Btu).
Xw=Fraction of total heat input from
supplemental fuel fired to the steam
generator.
X€t=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.
Table 19-1.—F Factors lor Various fuels'
Fuel type
dscm
J
dscl
10* Btu
•set
10-Btu
•cm
J
•cf
10* Btu
Coal:
Anthracite-
BHuminous '.
UonrM ,
<»•
Q*K
Mem* - , ,
Propone ,.„ ,1111J,.J , „ .,,
Butane. .
•tax
*>«W<"»A
2.71x10"
2.63x10"
2.65x10-
2.47x10"
2.43x10"
2.34x10"
. 2.34x10"
248x10"
2.56x10"
(10100)
(9780)
(9660)
(81 BO)
(8710)
(8710)
(8710)
(9600) _
2.83x10"'
2.86x10"'
3.21 X10"'
2.77x10"'
2.65x10"'
2.74x10"'
2.79X10"'
(10540)
(10640)
(11950)
(10320)
(10810)
(10200)
(10390)
0530x10"
0464x10"
0513x10"
0.363x10"
0.267x10"
0 321 x 10"
0337X10"
0497X10"
(1970)
(1600)
(1910)
11420)
(1040)
(1250)
(1650)
•A* classified acconSng to ASTM 0368-66.
• Crude, residual, or distillate.
•Determined at standard conditions: 20' C (68' F) and 760 mm Ho. (29.92 ra Hg).
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 SOt
and NO, outlet data and, if applicable,
SOs inlet data using the following
equations:
I x.
"1
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).
Xj=Hourly average in let emission rate; ng/j
(Ib/million Btu).
n<,=Number of outlet hourly averages
available for the reporting period.
Ill—Number of inlet hourly averages
available for reporting period.
6.2 Standard Deviation of Hourly
Emission Rates. Calculate the standard
deviation of the available outlet hourly
average emission rates for SO, and NOE
and, if applicable, the available inlet
hourly average emission rates for SO,
using the following equations:
Where:
•»= Standard deviation of the average outlet
hourly average emission rates for the
reporting period: ng/J (Ib/million Btu).
•1= 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:
E,*=E,-f-U.i.81
Where:
Eg* «=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).
U.««= Values shown below for the indicated
number of available data points (n):
Values fork.
10
11
12-16
17-21
22-26
27-31
32-51
52-91
92-151
162 or more
6.31
2.42
2.35
2.13
2.02
1.94
1.89
1.86
1.83
1.81
1.77
1.73
1.71
1.70
1.68
1.67
1.66
1.65
PCC
PCC
E1*
*• 2
* 2
Where:
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 (PCC) for SO*
7.1.1 When the removal efficiency
due to fuel pretreatment (% Rf) is
included in the overall reduction in
potential sulfur dioxide emissions (% RJ
and the "as-fired" fuel analysis is not
used, the potential combustion
concentration (PCC) is determined as
follows:
ng/J
1b/m1llion Btu.
Potential emissions removed by the pretreatment
process, using the fuel parameters defined In
section 2.3; ng/J (Ib/m1ll1on Btu).
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Federal Register / Vol. 44. No. 113 / Monday, June 11, 1978 / Rules and Regulations
7.1.2 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% Rf)
is not included in the overall reduction
in potential sulfur dioxide emissions (%
RO). the potential combustion
concentration (PCC) is determined as
follows:
PCC
PCC
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 (% RO), 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 (Baa}.
7.2.1 NO*. Use the allowable
emission rates for NO, as directly
defined by the applicable standard in
terms of ng/J (Ib/million Bra).
7.2.2 SO,. Use the potential
combustion concentration (PCC) for SOi
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
Whew:
U=The nilfnr dioxide input rate a* defined
in section 3.3
7.1.3 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% Rf)
is included in the overall reduction (%
RO), the potential combustion
concentration (PCC) is determined as
follows:
ng/J
is used as EM,,. If the applicable standard
is an allowable percent emission,
calculate the allowable emission rate
(E,td) using the following equation:
E^ = » PCC/100
Where:
% PCC = Allowable percent emission as
defined by the applicable standard;
percent.
7 3 Calculate Ea'fEua. 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).
Em = Allowable emission rate ai defined in
section 7.2; ng/| (Ib/million Btu).
V Eo'/E.u, la equal to or less than 1.0, the
facility is hi compliance; if E^/E^a is greater
than 1.0, the facility is not in compliance for
the reporting period.
|FR Doc. 7»-17«07 PIM fr-e-7* &4S m|
BIOINO OOOC tSta 01 •
V-330
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
IFKL127S-3J
^glorify UcS ondl AddiStoao to fflriQ UsS
n@SK>ev: Environmental Protection
Agency.
: Final rule.
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 19B2.
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
(stationary sources of air pollution.
QPFECTIVE BATE: August 21, 1979.
A@BBE§SGi: 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.
P©(3 FUBTHSB
Gary D. McCutchen, Emission Standards
and Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, N.C. 27711,
telephone number (919) 541-5421.
OUPPUsKlSNTABV IMP©HKJA70@C3: On
August 31,1978 (43 FR 38872). EPA
proposed a priority list of major source
catagories 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 111(0-
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-each 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.
participate 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 rates
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.
V-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 io 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, wher •.-.easet; v< «he
atmosphere, can reir.?;". lor.j =•>••..'• ah to
participate in photochemical ••,-. v.-iions.
Since VOC contribute to e^V':.nt 5c«»ls
of photochemical oxidants *v.-y ere
considered a cHt- • • •''. .-••• •
Thp ranking o* jouri. ','? ivies or;
the I'1".' end the differed »•'•• -i ;•>. we^n
maji; -uid minor sou-; '•••• .as s>3:r!3:.'.ivc
to th ; ••• acy of the ..-.:;B utilized. Tiie
data base usec to establish '-.? pric:>,/
list was obtained Iroi'i a wi/nb-i ,if
litere'.ure so-.n^s ir.ciud-n;? EF'A
screening studies. Howe", • screy -.-x
studies were ncv avail?'/ e for hi. :?-„..-. , •.
categories. There/ore, i> ;iew ;n'i-. :i; . r
becomi-s available after pmrf'^a:: .>•• 1?
the list, the AdminisUatoi n.... ...c-Jc'..:
from o: i.dd to the list in -'espouse to 'his
new information.
Addiiiun&l detail on the prioritizetion
methodology, the input factors useu, and
the ranking of individual source
categories is available in the two
background documents (see
"ADDRESSES").
Significance of Priority Last
The promulgated list is essemip"y an
advance notice of future s'.aiid,;.:u
development activity 'A identifies n; -.r
source categories and the approxirvile
order in which NSPS development
would be iiiii;...-J However, if furthv
stuHy indicates that an ?-'SP? wz-J.t
ha • 'ittle or no effect on err.'rsio- >. or
th;:. •••.• \SPS would hp impi-artic-... ..
so:.,c:< L 'ego'. ••• :.u L, p;ven a Ij/. ;•.
pn.'••••.;> '. •emovt-:' '.-om th'-. l-s'
Sir.-:'.- •;•• --w in.fO'..i..:' "\ Tiay iic~f-r.?
the -.,-: '!•'.',' •':' a sou- •..•• •jgo/v. Ts.-c
Afi -.;•• : i.;. ." ;nay a.''? roncL-rremiy
dev:.-'. •_... >-..-.i':ards fo; -•• .rces vhioh ar-,
no! .v" ''•-. ...:•.'"'" !;st, esptcialiy fTui'ti
"mi':-; *. f.i-ces which, it, a£,, :-^.';',e,
repres;r: i large quantity ••.''sir.ijsicris
The distinction t>.;>••• ?gn ;.is;oi ar.r
minor source categorit-B ;c- deiips- inly
for the purpose ol determining !\SPS
priorities and should not be used '•
determine sources subject to Ne'-v
Source Review, whic - is conducted • a
case-by-case basis. Moreover, some
New Source Review programs, such • s
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
minoi 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
mil. therefore, are probably not major
sourcss. Nevertheless, the Administrator
will continue to investigate th?se
«ourc«s and will consider development
of NSPS for any which are identified as
being significant sources of air pollution.
Thf second group of source categories
i.:j( o:: the jiiioiity Hot consists cf those
lis'sd under section lll(b)(l)(A) on or
before August 7,1977. These are:
>'-_!>sii->uel-hred glean; generator?
Inrine-ators
Portland Cement Plants
Nitric Acid Plants
S.-lfuiic 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:
Superphosphoric Acid Plants
Phosphate Fertilizer Indus'/y: Diamirc.-niMm
Phosphate Plants
'•?:-.!•'ph'ate Fc-lilizer Industry: Triple
Supf-phosphcle F'ants
Phospi,t)le FertiliZ!1! tadusti-y: Granular T.'jplc-
Sup>-,-phosphate Storage raciiitir:-
'.Joo! Preparation Plants
^fvroal'oy Production Facihtu'^
?"..:-2l Pisnts: Electric Arc FLIT., '-.es
Kraft Pi-ip Mills
Ume Pi.inls
Urain Elevators
There «re, however, some facilities i •
suhca'.egories) wi-'vln these source
categories for which KiPS V svs no'
been duveloped, b'lt which may by
themsrlve:; be ' ignificant souvces o.C ri;
pollution. A number oi these ic'.wiiitics
• -'ere evah-.aisJ c-.s if they were sepa.-ait;
i-"5.rce cait-30'-ic;, ilunc which rank high
in priority are iacluded on tha
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 fror. time to
time develop NSP3 for sush 'sciiities.
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 sctive 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 t:-i effort to determine the relative
sigrjiuearice of emissions from each
process, in addition, byproduct coke
uvpii, netHy always associated with
Bi'-.zi inills, ere included on the priority
fci snd are undergoing standard
!J,i:'V?)opinent sH'dies.
Thsre ere some differences nelween
••:•.(•; f-.nnet of the list in the background
report, "Revised Prior;i::.ed Lis! 'f
Source Categories for NSF?
Promulgation" and the formpi of the list
which appears here. These differences
are primarily a result of aggregation of
subcategories 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)
?nd one of which is considered a minor
source (w'ca milling). EPA plqns to
.-.tufiy the entire non-metallic :.iincral
pr-:..".o«sin« industry at one time r-ince
many of the processes and "n'.ro'.
tei'h-.icini-s are similar. For this reuson,
tho •noustry is identified by 8 single
;;&;,:evated listing This does n-.-t
:,r?'.:'assarily imply that s single standard
would apply to a:i sources w.tl.in the
listed category R&iher, «s described
below in the case of the synthetic
:V.!'.-:;ti-y. thn nature ar.d scope of
."ipndards will be determined only after
v detailed s.tudy of sources within the
rair-govy.
*r addition to the major sources, three
source categoi i-is not identified as being
;rii
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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, National 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 NAPCTAC 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 same 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 seta 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
into 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
conunenters 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 fur
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
V-333
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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
tinder 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 commenters 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,
since 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). It
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
jc) Fugitive emission sources
(d) Secondary1 sources
2. Industrial Surface Coating: Cans
3. Petroleum Refineries: Fugitive Sourci-s
4. Industrial Surface Coating: Paper
S. Dry Cleaning
(a) Perchloroethylene
(b) Petroleum solvent
6. Graphic Arts
7. Polymers and Resins: Acrylic Resins
8. Mineral Wool
9. Stationary Internal Combustion Engines
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: eg N
high priority. No. 59 is low priority.
V-334
-------
Federal Register / Vol. 44. No. 163 / Tuesday. August 21.1979 / Rules and Regulations
I 15. Secondary Copper
' 16. Phosphate Rock Preparation
17. Foundries: Steel and Gray Iron
18. Polymer* and Resins: Polyethylene
19. Charcoal Production
20. Synthetic Rubber
(a) Tire manufacture
(b) SBR production
21. Vegetable Oil
22. Industrial Surface Coating: Metal Coil
23. Petroleum Transportation and Marketing
24. By-Praduct Coke Ovens
28. Synthetic Fibers
26. Plywood Manufacture
27. Industrial Surface Coating: Automobiles
28. 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—Melamine
38. 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
M. Ammonium Nitrate Fertilizer
49. Castable Refractories
SO. Borax and Boric Acid
51. Polymers and Resins: Polyester Resins
52. Ammonium Sulfate
53. Starch
54. Perlite
55. Phosphoric Acid: Thermal Process
56. Uranium Refining
57. Animal Feed Defluorination
58. 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. 111. 301(a). Clean Air Act as amended
(42U.S.C. 7411. 7601))
|PR Doc. 7S-26BS6 Piled 8-2O-79: 8:45 am]
MUJNG COOC »MO-01-«i
" Minor source category, but included on list
since tin NSPS it being developed for that source
category.
''' Not prioritized, since an NSPS for this major
source category has already been nronnspH
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 the
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.
V-335
-------
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 particulate 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 dryer-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
Mg'/dscm (.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 to 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 that
this can be done without sacrificing the
Agency's responsibility for assuring
V-336
-------
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
V-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 small
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 industrj.
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 Coslle,
Administrator
-------
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 Ubrary (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 atmosphere) 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 NO,
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 whin ice fog
created by the gas turbine is deemed by
the 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 SOa 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 percent
sulfur by weight (see Table 1 for
summary of exemptions and SO?
emission limits).
Table 1.—Summary of Gas Turtine Ne* Source Performance Standard
Gas turbine size and usage
NO, emis-
sion limit '
Applicability date for
NO,
SO, emission Itmil
Applicability date 101
SO,
Less than 10.7 gigajoules/hour (all uses) None
Between 10.7 end 107.2 gigajoules/hour (all 150 ppm..,
uses).
Greater than or equal to 107.2
pgajoules/hour:
1. Gas and oil transportation or produc- ISO ppm...
Bon not located rn an MSA.
2. Gas and oil transportation or produc- 75 ppm
lion located in an MSA.
3. AB other uses 75 ppm.....
Emereency standby, firelighting. military None..
(except tor garrison facility), military train-
ing, and research and development tut
. Standard does not None Standard dous noi
apply. apply
October 3.1982 150 ppm SO, 01 toe a October 3. 1977
fuel with less man
0.8% suKut
. October 3.1977 Same as above October 3. '977
. October 3,1977 Same as above October 3. 1977
. October 3, 1977 Same as above October 3. 1977
. Standard does not Same as above October 3 1977
apply
'NO, emission Omit adjusted upward tor gas turbines with thermal efficiencies greater than 25 percent and lor gas turbines
drtng fuatt with • nitrogen content of more than 0.015 weight percent Measured NO, emissions adjusted to ISO conditions in
detemwung compliance with the NO, emission limit
_T TO
-------
Federal Register / Vol. 44, No. 176 / Monday, September 10, 1979 / Rules and Regulations
Environmental, Energy, and Economic
tapact
The promulgated standards will
reduce NO,, emissions by about 1SO.CDO
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 NO0
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 NOa
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
3982. 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 198 . 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.
Genera]
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
NOn 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 NOX
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
NOj 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 NO, 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
wfeuld 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 SSEIS 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 NO,
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
commenters1 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
e 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 NOE
production, or installation of new NOB
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 NOa
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 NOE
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 commentere stated that
the costs associated with wet controls
on gas turbines located on offshore
platforms, and in arid and remote
regions were unreasonable. These
commentere 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 fell thai
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 NOX 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
NO, 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 th« SSEIS, as
fuel-bound nitrogen increases, organic
NO, emissions from a gas turbine
become the predominant fraction of
total NO x, 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
usedi 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 mean* of
allowing flexibility in the selection of
fuels while achieving reductions in NO,
emissions from stationary gas turbines.
(See Control Technology for further
discussion.)
A number of commenters felt the
efficiency correction factor included in
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/opera tor. 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
§ 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) "Stationa'-y 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 gas 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.
(j) "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.
(1) '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 8 60.8 is
completed, every owner or operator
subject to the provisions of this subpart,
as specified in paragraphs (bj, (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:
STD = 0.0075
+ F
32
where:
STD = allowable NO, emissions (percent by
volume at 15 percent oxygen and op a
dry basis).
Y= manufacturer's rated heat rate at
manufacturer's rated load [kilojoules 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=NOi emission allowance for fuel-bound
nitrogen as defined in part (3) of this
paragraph.
• f2) 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
volume at 15 percent oxygen and on a
dry basis).
Y = manufacturer's rated heat rate at .
manufacturer'* rated peak load
(kilojoules 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
(percent by Height)
H « 0.015
0.015 < N < 0.1
0.1 « N • 0.?5
II > 0.25
i'!S». Percent by
0.041K)
0.004' » 0.0067(H-0.1)
0.005
where:
N = the nitrogen content of the fuel (percent
by weight).
or.
Manufacturers may develop custom
fuel-bound nitrogen allowances for each
gas 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 $ 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 load 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 3,1982 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 while1
the mandatory water restrictions are in
effect.
S 60.333 Standard for sulfur dioxide.
On and after the date on which the
performance test required to be .
conducted by { 60.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 $ 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 in $ 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 tne
period of excess emissions, and the
graphs or figures developed under
S 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 § 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
p
'NOW = (NO. ) (D-^)0'5 e19(H
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. 1B57C-9]).
S 60.335 Test methods and procedures.
(a) The reference methods in
Appendix A to this part, except as
provided in S 60.8(b), shall be used to
determine compliance with the
standards prescribed in § 60.332 as
follows:
(I) 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:
*obs
obs
obs
n
' °-
where:
NO,=emissions of NO, at 15 percent oxygen
and ISO standard ambient conditions,
NO10U=measured NO. emissions at 15
percent oxygen, ppmv. :
Pr,r= reference combuster inlet absolute
pressure at 101.3 kilopascals ambient
pressure.
Poa. = measured combustor inlet absolute
pressure at test ambient pressure.
H,,^ = specific humidity of ambient air at test.
e = transcendental constant (2.718).
TAHB = temperature of ambient air at test.
The adjusted NO, emission level shall
be used to determine compliance with
S 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
§ 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 § 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, majTbe
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. 1857C-91]).
Appendix 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
1. Applicability and Principle
1.1 Applicability. This method is
applicable for the determination of nitrogen
oxides (NO.), sulfur dioxide (SO,), and
oxygen (Oj) emissions from stationary gas
turbines. For the NO, and O, 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
stream of a stationary gas turbine; a portion
of the sample stream is conveyed to
instrumental analyzers for determination of
NO, and Ot content. During each NO, and
OO> determination, a separate measurement
of SO, emissions is made, using Method 6, or
it equivalent. The Oi determination is used to
adjust the NO, and SO, 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 O. Analyzer. That portion of the
system that senses Oi 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.
2.3 Calibration Gas. A known
concentration of a gas in an appropriate
dihient gas.
2A Calibration Error. The difference
between the gas concentration indicated by
the measurement system and the known
concentration of the calibration gas.
2.5 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 NO> 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 Oa 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 sufficient length to traverse the sample
points.
4.1.2 Sample Line. Heated (> 95'C)
stainless steel or Teflonfebing 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 NOt to NO Converter. That portion
of the system that converts the nitrogen
dioxide (NO,) in the sample gas to nitrogen
oxide (NO). Some analyzers are designed tu
measure NO, as NO, on a wet basis and can
be used without an NO> to NO converter or »
moisture removal trap provided the sample
line to the analyzer is heated (>95'C) to the
inlet of the analyzer. In addition, an NOS to
NO converter is not necessary if the NO,
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 9(>
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 (hi
approval of the Administrator, and (c) correc1
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 i<
minimize transport delay. The pump shall he
made from stainless steel or coated with
Teflon or equivalent.
4.1.8 Sample Gas Manifold. A sample gas
manifold to divert portions of the sample g.is
stream to the analyzers. The manifold may In-
constructed of glass, Teflon, type 316
stainless steel, or equivalent.
4.1.9 Oxygen and Analyzer. An analyze!
to determine the percent O, 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 reagents.
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 N«. For NO, measurement analyzers thai
require oxidation of NO to NO>. the
calibration gases must be in {he form of NO
in N2. 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
>!"S.
4.4 O, Calibration Gases. Use ambient air
iit 20.9 percent as the high-level Ot gas. Use a
pas concentration that is equivalent to 11-14
percent O- for the mid-level gas. Use purified
nitrogen for the zero gas.
4.5 NOz/NO Gas Mixture. For
determining the conversion efficiency of th<-
N'O3 to NO converter, use a calibration gas
mixture of NO: and NO in N,. The mixture
tvill be known concentrations of 40 to 60 ppm
NO, and 90 to 110 ppm NO and certified by
the gas manufacturer. This certification of gas
concentration must include a brief
description of the procedure followed in
determining the concentrations.
5. Measurement System Performance Test
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 lest runs for a given gas turbine
engine.
5.1 Calibration Gas Checks. There art-
two alternatives for checking the
concentrations of the calibration gases. (H)
The first is to use calibration gases that ary
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) thai 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 8.1 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,
analytical results must be within 10 percent
(or 10 ppm. whichever is greater) of the
triplicate set average (Ot test results must be
within 0.5 percent O,): otherwise, discard the
entire set and repeat the triplicate analyses.
If the uvurage of the triplicate reference
method test results is within 5 percent for
NO, gas or 0.5 percent Ot 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 (O.
test results must be within 0.5 percent O2).
Then use this average for the cylinder value.
5.2 Measurement System Preparation.
Prior to Ihe emission test, assemble the
measurement system following the
manufacturer's written instructions in
preparing and operating the NO, to NO
converter, the NO, analyzer, the Ot analyzer,
and other components.
Date.
_l(Must be within 1 month prior to the test period)
Reference method used.
Sample run
1
2
3
Average
Maximum % deviation1*
Gas concentration, ppm
Low level8
Mid leveJb
High level0
3 Average must be 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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Federal Register / Vol. 44. No. 176 / Monday, September 10. 1979 / Rules and Regulations
5.3 Calibration Check. Conduct the
calibration checks for both the NO, and the
Oi analyzers as follows:
6.3.1 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 O. 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 Oa analyzers is
greater than 2 percent of the applicable span
value, take corrective measure on the
measurement system.
Table 20-1.—Interference Test Gas Concentration
CO S00±50 ppm.
SO, 200±20 ppffl.
CO, - __ io± 1 peicent
O,._ :.... _ 20.9+1
percent.
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
X 100.
Span value
Zero and calibration data.
Conduct an interference response test uf
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 aucepl;il>le.
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, firsl
introduce zero gas into the system at the
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Federal Register / Vol. 44. No. 176 / Monday. September 10, 1979 / Rules and Regulations
calibration valve until all readings are stable:
then, switch to monitor the stack effluent
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
lest 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.
Span gas concentration.
Analyzer span setting
Upscale
1.
2.
3.
. S/N.
-Ppm
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
5.1> NOj NO Conversion Efficiency.
Introduce to thi: system, al the calibration
valve assembly the NO2/NO gas mixture
(Section 4.5} Record the response of the NO,
analyzer. If (he instrument response indicates
less than 90 percent NO2 to NO conversion.
make corrections to the measurement system
and repeat the check. Alternatively, the NO-..
tn N'O converter check described in Tide 40
I'arl 80: Certification and Test Procedure.* fur
Hi-in-y-Duty Engines for 1979 and Later
•Mi'>li:l 1'ears may be used. Other alternate
procedures may be used with approval of the
•Vlniinistiator.
<>' t'/;i:.s-Mc«n Measurement Test Procedure
1>.1 Preliminaries.
01.1 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 end 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 O« 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 1.5 m= (16.1 ft*): (2) one sample point
for each 0.2 m" (2.2 ft* of areas, for stacks of
1.5 mMo 10.0 m* (16.1-107.6 ft5) in cross-
sectional area: and (3) one sample point for
each 0.4 n;-(4.4 ft3) of area, for stacks greater
than 10.0 m - (107.6 ft -1} 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 numbt-i
of traverse points for the preliminary O:
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 the
lowest percent of peak load, conduct a
preliminary O-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 O'at
each point and record thr data on P;JI;.;!' 20-
6.
6.1.2.4 Selection of Emission Tusl
Sampling Points. Select the eight sampling
points at which the lowest O-cones rtration
were obtained. Use these same points for al!
the test runs at the different turbine load
conditions. More than eight points- ry.ay lie
used, if desired.
Table 20-2.—Cross-sectional Layout >&
Rectangular Slacks
NO oi trave
9
12
16
20
25
30
36
42
layout
3
3
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Federal Register / Vol. 44, No. 176 / Monday. September 10, 1979 / Rules and Regulations
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 O2 Measurement. This test is
to be conducted at each of the specified load
conditions. Three test runs at each load
condition constituty a complete test.
6.2.1 At the beginning of each NO, test
run and, as applicable, during the run. record
turbine data as indicated in Figure 20-7. Also,
record the location and number of the
traverse points on a diagram.
BILLING CODE tMO-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 20-8.
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Federal Register / Vol. 44, No. 176 / Monday. September 10,1979 / Rules and Regulations
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 rate3.
Va
etc"
Water or steam.
Flow rate3
Ambient Pressure.
Operating load.
aDescribe measurement method, i.e., continuous flow meter,
start finish volumes, etc.
"i.e., additional elements added for smoke suppression.
Figure 20-7. Stationary gas turbine data.
Turbine identification: Test operator name.
Manufacturer
instrument type.
Serial No
Model, serial No.
Location:
Plant
NOX instrument type.
Serial No
Sample
point
Sfato
t tpmppratnrp
t prp«llrp
IP - start
Time,
min.
02-
%
NO;.
ppm
Date.
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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Federal Register / Vol. 44. No. 176 / Monday. September 10, 1979 / Rules and Regulations
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 SO> 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 O»
readings taken during the NO, test runs at
sample points corresponding to the SO>
traverse points (see Section 6.2.2) and use
this average O, concentration to correct the
integrated SO, concentration obtained by
Method 6 to 15 percent Oi (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
SO, concentrations (adjusted to 15 percent
Oi). The correction to 15 percent O, is
sensitive to the accuracy of the O»
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 O,
content of the exhaust is above 16 percent Ot.
Therefore O, analyzer stability and careful
calibration are necessary.
C»dj * Cre«s * \-'-'- (Equation 20-1)
Where:
C^j=Pollutant concentration adjusted to
15 percent O, (ppm)
Cnxl>=Pollutant concentration measured,
dry basis (ppm)
5.9=20.9 percent O3—15 percent O3, the
defined O, correction basis
Percent O>=Percent O2 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. 79-27993 Filed 9-7-78; 8:45 am]
BILLING CODE «S60-01-M
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Federal Register / Vol. 44, No. 187 / Tuesday, September 25, 1979 / Rules and Regulations
102
40 CFR Part 60
[FRL 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 (§ 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 S 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. 1657 et seq.. as amended by Pub.
L. 91-604, 64 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.
V-354
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Federal Register / Vol. 44. No. 1B7 / 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
I 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 and7601(a))
|FR Due 79-M768 Kiled 9-:«-79. 8 45 am|
BILLING CODE CMO-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.
FCR 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
pt iroleum refinery, 40 CFR 60.100 (1978).
"Small petroleum refinery" was defined
as a "petroleum refinery which htis 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 cnich; oil
processing capacity of 137.500 barrels
per stream day or less," 40 CFK
fiOIOI(m) (1978).
On May 12, 1978, two oil companies
filed a Petition for Review of these new
source performance standards. One
issue was whether the definition of
"smfill petroleum refinery" was unduly
r<-s!ricti\e.
On March 20,1379, EPA proposed to
amend the 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 (SO?) emissions, costs.
and energy consumption. The oil
company petitioners agreed to dismiss
their entire Petition for Review if the
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, the final standard will
apply to any petroleum refinery Claus
sulfur recovery plant of more than ZO
LTD processing capacity. This
amendment will apply, like the
standards themselves, to affected
facilities., die 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 xvill 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"
WHS still too restrictive, as explained
liclu iv.
Two of the four argued for deletion of
the 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.
The 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 SOa 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 SOZ (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
impact on energy and economic impacts.
compared to the proposed amendment.
Ducket
Docket NQ. 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 2903D
(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 Uic rulemaking process. Alonjj wit!)
V-356
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Fedsral Kegista? / 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)(al].
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 18,1979.
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:
g 80.100 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 Claus 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. i 60.101 is amended by revoking
and reserving paragraph (m), as follows:
g 60.101 Definitions
* « * « 6
(m) [Reserved]
(Sec. Ill, 30l(a), Clean Air Act as amended
(42 U.S.C. 7411, 7601(a)).)
|FR Doc. 79-32778 Filed 10-24-79: 8:45 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:
§ 60.25 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. 79-34625 Filed 11-8-79: BM5 am|
Federal Register / Vol. 44. No. 233 / Monday. December 3, 1979
105
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
refiect.ihis 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 imports, 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.
(AHU) • • •
fV) 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.
V-358
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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 in, 6th and
Walnut Streets, Philadelphia,
Pennsylvania 19106, Telephone (215)
597-4561.
SUPPLEMENTARY INFORMATION:
1. 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 HI, 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.
D. 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 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 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) State of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants; asphalt concrete plants; storage
vessels for petroleum liquids; sulhiric acid
plants: and sewage treatment plants only.
Delaware Department of Natural Resources
and Environmental Control, Edward Tatnall
Building. Dover, Delaware 19901.
IFF 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 CFR 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 petition
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 /Vet 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. 79-39509 Filed 12-27-79: 8:45 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.
n. 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.
HI. 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) • • '•
(AHNN) * * *
(OO) Commonwealth of Pennsylvania:
Department of Environmental Resources,
Post Office Box 2063, Harrisburg,
Pennsylvania 17120.
(IK Doc. HM46B Filed 1-1S-K 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)J. 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, $ 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
a 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
{ 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 95-05, 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 I 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 (fj 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, 7601(a)]).
|FR Doc. 80-2122 Filed 1-22-80; 6:45 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 (SOi), 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 EOF.
BATES: 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
(NOJ 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 States 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 SO: 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 SO2
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 SO* removed by all types of SO»
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 SOi
emissions is required. The percent
reduction requirement does not apply if
SOZ emissions into the atmosphere are
less than 86 ng/J (0.20 Ib/million Btu)
heat input. Compliance with the SOa
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
SO2 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 SO2 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 s'ubject 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 NO0 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/
J'heat 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 SO> standard and to
the particulate matter and NO,
standards. However, the reduction in
potential SO» 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
Fluidized bed combustion
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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continuous emission monitors
malfunction in order to provide emission
data for at least 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
bypassed under emergency conditions.
Compliance with the participate
standard is determined through
performance tests. Continuous monitors
are required to measure and record the
opacity of emissions. The continuous
opacity 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
I. SOi Maximum Emission Limitation of
520 ng/J (1.2 Ib/Million Blu) Heat Input
The Environmental Defense Fund
(EOF), Sierra Club, and State of
California Air Resources Board (CARB)
requested that a proceeding be
convened to reconsider the maximum
SOZ emission limitation of 520 ng/J (1.2
Ib/million Btu) heat input. In their
petition, EOF set 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
parts 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 performance could create a
significant disincentive against the
burning of high-sulfur coal reserves. The
Sierra Club maintained that this
information 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
this 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 SOs 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
1CF, 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 broached 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-«0).
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) heal 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 SOj 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 SOa 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 %-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
baying 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 of the SO2 standard on coal
production, the Administrator judged
that utilities would be inclined to select
coals that would meet the emission limit
with no more than 90 percent reduction
in potential SO2 emissions ' (44 FR
33596, left column). With this
assumption, the analysis revealed that
an emission limit of less than 520 ng/J
(1.20 Ib/million Btu) 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 analvsis had
assumed either 65 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 than
90percent in some cases.
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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 SOi 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/
] (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
assessed 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, lV-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 SOi 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 parts 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 v. 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
communcations 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
ex parte. 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 EDFs assertion, the
Administrator's decision on the
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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
rulcmaking. 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 ex parte 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 EOF has done. No new information
was presented to the Administrator at
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 to
the outcome of the rule.
//. SO,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 SO,
scrubbing technology since the phase 3
macropconomic 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 SO> 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 SOj
scrubbing technology.
In their petition KCPL sought either an
elimination 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 in
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 their 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 SO?
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 SOi scrubbing systems, it was
necessary to introduce a new alternative
standard—the variable control standard
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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 SOi
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 NOa
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 systeme (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 SO» 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 SOj 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 SOj
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 SO» 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
rncognized 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-7a-l, IV-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
provision 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
plant 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 that
"while the dry scrubbing approach is
new, the technology is proven."
Economic Modeling
The Agency's regulatory analysis
concluded that the1 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 met 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,
1V-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-78-1, VI-B-1G). 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:
t
1985
1990
1995
Assumed Oil Prices
I Dollars per Barrel]
Sensitivity
analysis
.. • 25
........ 30
38
Phases
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:
Ti lie 1.—Summary of 1995 Impacts With Phase 3 Assumptions'
Level ol control with 520 ng/J maximum emission limit
Current Variable con- Variable con- Full
standards trol. 50 pet trol, 70 pet control
minimum minimum
National SO, Emissions (million tons)
East'
Midwest ,
West South Central
West
Incremental Annualized Cost (billions 1978 S)
Incremental Cosl of SO, Reduction (1978 $/ton)....
Oil Consumption (million obi/day)
Coal Production (million tons) „
Total Coal Capacity (GW)
23.8
11.2
8.3
26
1.7
1.4
1.767
554
20.6
9.7
8.0
1.8
1.1
2.9
914
1.6
1.745
537
20.5
9.7
8.0
1.7
1.1
3.3
1.036
1.6
1.752
537
20.7
10.1
7.9
1.7
0.9
44
1.428
1.8
1.761
520
1 With wet and dry scrubbing and the following energy assumptions:
Oil prices
($ 1975)
Year
1985
1990
1995
$12.90
16.40
21.00
Nuclear
Capacity
(GW)
97
165
228
1 See 44 FR 33608 lor designation of census regions.
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Federal Register / Vol. 45. No. 26 / Wednesday, February 6,1980 / Rules and Regulations
Table 2.—Summary of 1995 Impacts With Higher Oil Prices'
Level of control with 520 ng/J maximum emission limit
Current Variable con- Variable con- Full
standards trol. 50 pet trol, 70 pet control
minimum minimum
National SO» Emissions (million tons)
East '
West South Central „
West .- .
Incremental Annualized Cost (billions 1978$)
Incremental Cost of SO, Reduction (1978 S/ton) '
Total Coal Capacity (GW)
23.2
10.9
8.2
2.6
1.6
0.9
1.800
588
19.8
9.1
7.9
1.7
1.1
3.3
967
0.9
1.797
587
. 19.6
9.1
7.8
1.6
1.0
3.6
977
0.9
1.B02
587
19.7
9.5
7.8
1.5
0.9
5.0
1.049
0.9
1.832
587
1 With wet and dry scrubbing and the following energy assumptions
Oil prices Nuclear
(S 1975) capacity
(GW)
Year:
1985
1990
1995
$20.20
24.20
30.70
97
165
228
•'See 44 FR 33608 for designation of census regions
Table 3.—-Summary of 1995 Impacts With Higher Oil Prices and Less Nuclear Growth'
Level of control with 520 ng/J maximum emission limit
Current • Variable con- Variable con- Full
standards trol. 50 pet trol. 70 pet control
minimum minimum
National SOa Emissions (million tons) '.
East'
Midwest
V»est South Central
' West ,
Incremental Annualized Cost (billions 1978 S)
Incremental Cost of SO, Reduction (1978 S/ton)..
Oil Consumption (million bbl/day)
Coal Production (million tons)
Total Coal Capacity (GW)
25.0
12.0
8.6
1.7
09
1.940
644
20.9
9.8
6.2
1.8
1.2
3.6
883
0.9
1.943
644
20.6
9.7
8.1
1.7
1.1
4.1
914
0.9
1.946
644
20.5
10.1
8.0
1.6
0.9
5.9
1.259
0.9
1.984
643
' With wet and dry scrubbing and the following energy assumptions:
Oil prices Nuclear
(S 1975) Capacity
(GW)
Year:
1985 S20.20 92
1990 24.20 141
1995 30.70 173
J See 44 FR 33608 for designation of census regions
Assumed Nuclear Capacity
Sensitivity Phase 3
analysis
1985...
1990...
1995...
92 GW 97 GW
141 GW 165 GW
173GW 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 SOi 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 SO?
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
SOj 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 Ihe
alternative standards changed
somewhat. National emissions were
predicted to be 100,000 tons les_s 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 wore 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 aliernafives
increased by about 100 million tons per
year.
Even considering the uncertainty of
future 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 slewed 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 Sl.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 national parks (44 FR 33584,
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
macroeconomic 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 macroeconomic
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 was 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 seem 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 removal 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
1 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 ol UARG and EPA dry SO,
Scrubbing Costs * fMills/kwhJ
Percent removal
50
70
Inlet sulfur (Ibs UARG
SO,/million
Btu)
080 M.68
2.00 '213
0 80 1 97
2.00 2.54
EPA
206
2.44
266
2.66
1 Wet scrubbing costs range up to 6 mills/kwn.
- UARG costs 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
crlivercd. 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
SOi 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 SO»
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 SO»
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 SOj 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 B
tons of coal per hour to operate the
scrubber. Considering their operating
requirement of 460 tons of coal per hour.
the energy penalty of SOj control is 1.7
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
•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 S5 percent
= rather than 56 percent as calculated by
KCPL At Ga percent scrubbing, the cost
per ton of suifur removed is $3100. This
converts to a cost of $1550 per ton of
sulfur dioxide removed which is similar
to the costs estimated by EPA for low-
sulfur coal applications (OAQPS-78-1,
III-B-3 and IV-B-14).
Thus, the Administrator has already
concluded that energy and economic
costs greater than those cited by KCPL
arc justified to achieve the emission
reductions required by the standard.
Conclusions on Minimum Control Level
After carefully weighing the
arguments by the three petitioners, the
Administrator can find no new
information 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 not based on phase 3 alone, but a
series 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 germane 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 emis?ions 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 SO2
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
SOj 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
percent 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 SO» emissions, 30-day rolling
average. The other petitions did not
address this issue. However, in a July 18,
1979, letter, the Environmental Defense
Fund (EDF) 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 deadline of January
31,1980, for EPA to respond to the
petitions. However, the only issue not
previously raised by I'ARC (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 SO2 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 FGD systems
for the control of SO, 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 SOZ
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 SOZ
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-78-1,1II-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
reguirement. 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 SO 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 SOa
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, H-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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Federal Register / Vol. 45. No. 26 / Wednesday. February 6. 1980 / Rules and Regulations
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, II-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
(o-,=0.20 on average and o-,=0.23 at the
95 percent confidence level), (2) the
same process control demonstrated at
Louisville which represents a peak
loaded, existing plant (IT,=0.32 on
average and Estimates are based on probability of only 1 violation in 10 years. Process variation ( Estimates are based on probability of only 1 violation In
10 years. Process variation (
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Federal Register / Vol. 45, No. 26 / Wednesday. February 6. 1980 / Rules and Regulations
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, II-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 SO, 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 SOS reduction can be attributed
to sulfur retention in coal ash.
These credits together with an FCD
system continuously achieving as little
as 85 percent reduction are sufficient to
attain compliance with the final SO2
percent reduction standard as is shown
in Table 6:
Table 6.—Impact of Sulfur Reduction Credits
on Required FGD Control Efficiencies to
A ttain 90 Percent Overall SOt Reduction
SO, removal method
Compliance
•Option
C
Coal washing removal, percent ....
Pulverizer, fly ash, and bottom ash
reduction, percent --- „___
FGD system removal, percent.™
Overall SO, reduction in potential
27
10
BS
00
20
4
87
80
0
89
80
Table 8 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/I (6.0 Ibs/million Btu) heat
input (OAQPS-78-1. IV-E-12. page 18),
less than 90 percent reduction in
potential SO» 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 SO,
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 SO, removal" in the
promulgation, it is 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
SO> 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
SO, 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
Grocp (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
maintaining a baghouse. Contrary to
UARG's position, the cost estimates
developed by EPA provide liberal
allowances for start-up and continued
maintenance. 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-78-1. 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 dees 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
baghouses for peaking units. For
example, the baghouse control system
on four subbituminous, pulverized coal-
Tired 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,
III-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 */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 VlOOO ACFM)
hot-side ESP would typically be used.
The Administrator believed that it
would have 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
?mploy 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 st y 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
paniculate 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 II-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, H-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 end 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. NOZ 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 78-1, IV-D-611.
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,
1II-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 threo
additional plants (OAQPS 78-1, H-B-62
and II-B-70) enabled the Administrator
to conclude that emission variability
under low-NOz 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. III-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 NOn
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 NOC 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 to
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 NOn 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-NOs
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-NO2 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 SOa and NOn
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, Q-A-68, 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-7&-
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-78-1, 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 SO,
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. That
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 frqm 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
participate 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
subparl 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 00-
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 60-
day requirement in section lll(b](l|(B] no longer
governs the promulgation or revision of new source
standards. It has been replaced by procedures set
forth in section 111(0 enacted by the 1977
amendments.
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 SO3 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 SO2 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
40 CFR Part 60
[FRL 1370-5]
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 6 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 61-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 IB, 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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Federal 'Register / Vol. 45, No. 67 / Friday, April 4. 1980 / Rules and Regulations
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 ti.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 that 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.
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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 field 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
Vi percent of the height of the vessel and
the roundness specification is grouped
by vessel diameter as follows:
Storage Ve**el Diameter and Radius Tolerance
Inches
0 to 40 leet exclusive....
40 to 150 feet exclusive....
ISO to 250 leet exclusive....
250 feet and over
±Vi
±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 (CARB) 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'8
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 in 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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Federal KegisSer / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
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 ouch
a source to the VOC emiosiono
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
reevaluation 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 exempto
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 tha
floating roof on its leg supports aad the
time it remains in this condition
determines the amount of VOC
saturation of the vapor space and the
subsequent emissions upon refilling the
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 ell 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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Federal Register / Vol. 45, No. 67 / Friday, April 4. 1980 / Rules and Regulations
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
eir 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 cost)" 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 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.
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. CosUe,
Administrator.
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 § 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:
5 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
! 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. .
eO.llOa Applicability and designation of
affected facility.
60.111a 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 18,1978.
(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.
§60.111a 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 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.
(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 76.0
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
•hall not exceed 212 cm1 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 (1V4
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 in1 per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm(V41n).
(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
tunes (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 cover 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
S 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
V-392
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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 Va" 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.
(in) Add the gap surface area of each
gap location for the primary seal and the
secondary seal individually. Divide the
sum for each seal 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
§ 60.112a(a)(l)(ii).
(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))
§ 60.114a 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))
§ 60.11Sa 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 am)
BILLING CODE 6560-01-11
V-393
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112
Federal Register / Vol. 45, No. 105 / Thursday, May 29, 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL-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 i, 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:
§ 60.45 Emission and fuel monitoring.
(g) * * *
(D * * *
(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. 80-16409 Filed 5-28-60; 8:45 am)
BILLING CODE 6560-01-M
V-394
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Federal Register / Vol. 45. No. 121 / Friday. June 20.1980 / Rules and Regulations
ENVIRONMENTAL PROTECT1OK1
AGENCY
40 Cm Part SO
[FRL 1458-4]
Standards of Performance for Ctew
Stationary Sources; Revised
Reference Methods 13A and 13®
AGEWCV: 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 13A 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
7801(a))
Dated: June 16,1980.
Administrator.
40 CFR Part 60 is amended by revising
Methods 13A 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 participate P
are withdrawn isokinetically 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/m'. 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 0.084 mg F/ms
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
V-395
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Federal Register / Vol. 45, No. 121 / Friday. June 20,1980 / Rules and Regulations
TEMPERATURE
SENSOR
/
STACK WALL
— ' PROBE
^
---} PITOTTUBE
=K
I 1
I OPTIONAL FILTER
iHOLDER LOCATION
PROBE
STACK WALL
FILTER HOLDER
u
ip" C" "
/**—
REVERSE TYPE
n
V
r-
/
•ty
\
i j
PITOT MANOMETER
THERMOMETER
-CHECK VALVE
VACUUM LINE
VACUUM EAU6E
;\, AIR TIGHT PUMP
DRY TEST METER
Figure 13A 1. Fluoride sampling train.
CONNECTING TUBE •
12 mm ID
J24/40
THERMOMETER
124/40
CONDENSER
impingers. use the Greenburg-Smith design,
modified by replacing the tip with a 1.3-cm-
inside-diameter (Vb in.) glass tube extending
to 1.3 cm {Vz 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
Figure 13A 2. Fluoride distillation apparatus, 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 i*
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.
Beakers. 500-ml and 1500-ml.
Volumetric Flasks. 50-ml.
Erlenmeyer Flasks.or Plastic Bottles.
5.3.5
5.3.6
5.3.7
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 run and
provides at least a 1-cm light path.
5.3.11 Spectrophotometer Cells. 1-cm
pathlength.
6, 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 Tilter 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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Federal Register / Vol. 45. No. 121 / Friday, June 20, 1980 / Rules and Regulations
6.1.1.2 If the filter ia 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 (275T). (2) The
filter has at least 95 percent collection
efficiency (<5 percent penetration) for 0.3 fim
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 (<0.01S mg F/cm2 of 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.
6.1.2 Water. Deionized distilled, to
conform to ASTM Specification D 1193-74,
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.
9.1.3 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.
0.3 Sample Preparation and Analysis.
The reagents needed for sample preparation
and analysis are as follows:
8.3.1 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 60 ml of 80 percent ethanol and 50 ml of
deionized distilled water.
0.3.3 Silver Sulfate (AgsSO.).
6.3.4 Sodium Hydroxide (NaOH).
Pellets.
6.3.5 Sulfuric Acid (H^SO.), Concentrated.
6.3.6 Sulfuric Acid, 25 percent fV/V).
Mix 1 part of concentrated HSSO« with 3
parts of deionized distilled water.
0.3.7 Filters. Whatman No. 541, or
equivalent.
6.3.8 Hydrochloric Acid (HC1),
Concentrated.
0.3.9 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 this
solution to 1 liter with deionized distilled
water.
6.3.11 SPADNS Solution [4, 5 dihydroxy-3-
(p-8ulfophenylazo)-2,7-naphlhalene-disuifonic
acid trisodium salt]. Dissolve 0.980 ± 0.010
g of SPADNS reagent in SCO 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 ICO 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,Q) 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.
0 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 impingers, 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
participate 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 silicone 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
silicone 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 showe 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 participate
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
participate 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 H,SO4. (Caution: Observe
standard precautions when mixing HjSO,
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 Ag2SO4
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 H*SO4
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 fig/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 B.2) for 30
minutes before reading the absorbance on the
spectroph otometer.
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 fig/
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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Federal Register / Vol. 45, No. 121 / Friday, June 20, 1980 / Rules and Regulations
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.
0. 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.
Aa =f Aliquot of distillate taken for color
development, ml.
At = Aliquot of total sample added to still.
ml.
B», = Water vapor in the gas stream,
proportion by volume.
C, = Concentration of F in stack gas, mg/m5,
dry basis, corrected to standard
conditions of 760 mm Hg (29.92 in. Hg)
and 293°K (528'R).
F, = Total F in sample, mg.
>ig 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.
Vm(itd) = 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.
Vwuui> = 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(,ui 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
Va^td) and moisture content Bwt 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:
10 JT
At
F)
Eq. 13A-1
9.5.2 Fluoride Concentration in Stack Gas. Determine the F concentration in the stack
gas using the following equation:
vm(std)
Eq. 13A-2
Where:
K = 35.31 ft'/m' if Vn,!,,,,) is expressed in •
English units.
= 1.00 m3/m * if Vm
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Federal Register / Vol. 45. No. 121 / Friday, June 20,1980 / Rules and Regulations
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, 58 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 (NaF) 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, 7.2, 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
stirrer generates enough heat to change
solution termperalure, place a piece of
temperature insulating material such as cork,
between the stirrer and the beaker. Hold
dilute samples (below 1CT *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.
6.2 Fluoride Electrode. Prepare fluoride
standardizing solutions by serial dilution of
the 0.1 M fluoride standard solution. Pipet 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 10"'and 10"s 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-JM."
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
concentrated standards. A straight-line
calibration curve will be obtained, with
nominal concentrations of 10~4,10'MO"1,
and 10"' fluoride molariry 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:
(Vd) (M) Equation 13B-1
Where:
K=19mg/ml.
10. References
1. Same as Method 13A. Citations 1 and 2
of Section 10.
2. MacLeod, Kathryn E. and Howard L.
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. 00-18658 Filed 0-19-80: 8:45 am]
BILLING CODE 656O-01-M
V-400
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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 Soderberg 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 arguments
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
(he 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 FR 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 Sebree
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 % ariable as potroom
emissions, there it, 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 [I] 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 to
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
amendments and Reference Method 14
revisions. The»« comments were
reviewed and considered in developing
the final amendments. All of the
comments 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 that the
proposed requirement to conduct
performance testing at least once each
month throughout the life of a new
primary aluminum 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.
(2) 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 an alternative test schedule for
primary and bake plant emissions be
extended to Include secondary
emissions. 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 Ib/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
shouid 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
divided 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 fallowed 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 provide 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)J 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
consecutively, 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 at
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 determined
and corrective actions taken. It is
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preferable that 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 contributes 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: June 24. 1980.
Douglas M. Costle,
A dministrator.
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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Federal Register ,/ Vol. 45. No. 127 / Monday. June 30. 1980 / Rules and Regulations
Section 60.191 is revised lo read as
follows:
§60.191 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.
"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.
"Potrooni 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 60.192 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 facility 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/lon) 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 for 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 or potline voltages.
(Section 114 of the Clean Air Ad as amended
(42 U.S.C. 7414))
Section 60.195 is revised as follows:
§ 60.195 Test methods and procedures.
(a) 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 give the Administrator at
least 15 days advance 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 •
alternative testing requirement that
requires testing less frequently than
once each month for a primary 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 primary
control system emissions for the purpose
of performance tests. The Administrator
shall publish the alternative testing
requirement in the Federal Register.
(c) Except as provided 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:
(1) For sampling emissions from
stacks:
(i) Method 1 for sample and velocity
traverses,
(ii) Method 2 for velocity and
volumetric flow rate.
(iii) 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 velocity
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) 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 the minimum sample
volume shall be 6.8 dscm (240 dscf) fdr
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:
(CsQs),10 "-,(CsQs),10-«
Epg- .
M
Where:
Epg = potroom group emissions of total
fluorides in kg/Mg of aluminum
produced.
Cs = concentration of total fluorides in mg/
dscm as determined by'Method 13A or
13B. or by Method 14. as applicable.
Qs = volumetric flow rate of the effluent
gas stream in dscm/hr as determined by
Method 2 and/or Method 14. as
applicable.
10 ~'= conversion factor from mg to kg.
M = rate of aluminum production in Mg/hr
as determined by § 60.195(f).
(CsQs)i = product of Cs and Qs for
measurements of primary control system
effluent gas streams.
(CsQs)i = product of Cs and Qs for
measurements of secondary control
system or roof monitor effluent gas
streams.
Where an alternative testing requirement has
been established for the primary control
system, the calculated value (CsQs) i from
the most recent performance test will be
used.
(i) For each run, as applicable, anode
bake plant emissions expressed in kg/
Mg of aluminum equivalent shall be
determined using the following equation:
CsOs10-«
Ebp=
Where:
Ebp = anode bake plant emissions of total
fluorides in kg/Mg of aluminum
equivalent.
Cs = concentration of total fluorides in
mg/Uscm as determined by Method 13A
or 13B.
Qs = volumetric flow rate of the effluent
gas stream in dscm/hr as determined by
Method 2.
10 "• = conversion factor from mg to kg.
Me = aluminum equivalent for anodes
produced by anode bake plants in Mg/hr
as determined by § 60.195(g).
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 7414))
2. Method 14, under Appendix A—
Reference Methods, is revised to read as
follows:
Appendix A—Reference Methods
METHOD 14—DETERMINATION OF
FLUORIDE EMISSIONS FROM POTROOM
ROOF MONITORS FOR PRIMARY
ALUMINUM PLANTS
1. Applicability and Principle.
1.1 Applicability. This method is
applicable for the determination of fluoride
emissions from stationary sources only when
specified by the test procedures for
determining compliance with new source
performance standards.
1.2 Principle. Gaseous and participate
fluoride roof monitor emissions are drawn
into a permanent sampling manifold through
several large nozzles. The sample is
transported from the sampling manifold to
ground level through a duct. The gas in the
duct is sampled using Method 13A or 13B—
Determination of Total Fluoride Emissions
from Stationary Sources. Effluent velocity
and volumetric flow rate are determined with
anemometers located in the roof monitor.
2. Apparatus.
2.1 Velocity measurement apparatus.
2.1.1 Anemometers. Propeller
anemometers, or equivalent. Each
anemometer shall meet the following
specifications: (1) Its propeller shall be madi;
of polystyrene, or similar material of uniform
density. To insure uniformity of performance
among propellers, it is desirable that all
propellers be made from the same mold; (2)
The propeller shall be properly balanced, to .
optimize performance: (3) When the
anemometer is mounted horizontally, its
threshold velocity shall not exceed 15 m/min
(50 fpm): (4) The measurement range of the
anemometer shall extend to at least 600 m/
min (2,000 fpm); (5) The anemometer shall be
able to withstand prolonged exposure to
dusty and corrosive environments; one way
of achieving this is to continuously purge the
bearings of the anemometer with filtered air
during operation; (6) All anemometer
components shall be properly shielded or
encased, such that the performance of the
anemometer is uninfluenced by potroom
magnetic field effects: (7) A known
relationship shall exist between the electrical
output signal from the anemometer generator
and the propeller shaft rpm. at a minimum of
Ihree evenly spaced rpm settings between 60
and 1800 rpm; for the 3 settings, use 60±15.
aOO±100. and 1800±100 rpm. Anemometers
having other types of output signals (e.g.,
optical) may be used, subject to the approval
of the Administrator. If other types of
anemometers are used, there must be a
known relationship (as described above)
between output signal and shaft rpm: also,
each anemometer must be equipped with a
suitable readout system (See Section 2.1.3).
2.1.2 Installation of anemometers.
2.1.2.1 If the affected facility consists of a
single, isolated potroom (or potroom
segment), install at least one anemometer for
every 85 m of roof monitor length. If the
length of the roof monitor divided by 85 m is
not a whole number, round the fracticn to the
nearest whole number to determine the
number of anemometers needed. For
monitors that are less than 130 m in length.
use at least two anemometers. Divide the
monitor cross-section into as many equal
areas as anemometers and locate an
anemometer at the centroid of each equal
area. See exception in Section 2.1.2.3.
2.1.2.2 If the affected facility consists of
two or more potrooms (or potroom segments)
ducted to a common control device, install
anemometers in each potroom (or segment)
that contains a sampling manifold. Install at
least one anemometer for every 85 m of roof
monitor length of the potroom (or segment). If
the polroom (or segment) length divided by 85
is not a whole number, round the fraction to
the nearest whole number to determine the
number of anemometers needed. If the
potroom (or segment) length is less than 130
m. use at least two anemometers. Divide the
potroom (or segment) monitor cross-section
into as many equal areas as anemometers
and locate an anemometer at the centroid of
each equal area. See exception in Section
2.1.2.3.
2.1.2.3 At least one anemometer shall be
installed in the immediate vicinity (i.e.,
within 10 m) of the center of the manifold
(See Section 2.2.1). For its placement in
relation to the width of the monitor, there art1
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two alternatives. The first is to make a
velocity 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 Method 2.
2.1.6 Differential pressure gauge. Inclined
manometer or equivalent, as described in
Section 2.1.2 of Method 2.
2.2 Roof monitor air sampling system.
2.2.1 Sampling ductwork. A minimum of
one manifold system shall be installed for
each polroom 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
fil 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 AdminiHrator. the 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 be 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 into each
sample nozzle.
BILLING CODE 6560-01-M
V-408
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SAMPLE
MANIFOLD
W/8 NOZZLES
ROOF MONITOR
SAMPLE EXTRACTION
DUCT
35 cm 1.0.
£>•
O
EXHAUST
STACK
10DUCTDIA.
MINIMUM
CL
n
rw
4
SAMPLE PORTS IN
VERTICAL DUCT
SECTION AS SHOWN
7.5cm DIA.
V
A
POT ROOM
EXHAUST BLOWER
O
o
3
O.
01
a
m
u
o
co
CO
o
Figure 14-1. Roof monitor sampling system.
yo
c_
fO
ta
CD
Q.
50
m
OQ
c
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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
Fiyure 14 2. Sampling manifold and nozzles.
BILLING CODE 6680-01 -C
V-410
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TACHOMETER • O.C. MOTOR
COMBINATION
(ACCURATE TO +54%)
POWER
SUPPLY
\
VOLTAGE
REGULATOR
a
CONNECTOR
ANEMOMETER
DIGITAL
VOLTMETER
(ACCURATE
CD
I
CO
I
*>.
Figure 14-3. Typical RPM generator.
o
Q.
03
c.
a
I
ffi
3
Q.
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
The manifold shull be located in the
immediate vicinity of one of the propeller
anemometers (see Section 2.1.2.3) and as
close as possible to the midsection of the
potroom (or polroom segment). Avoid
locating the manifold near the end of a
potroom or in a section where the aluminum
reduction pot arrangement is not typical of
the rest of the potroom (or potroom segment).
Center the sample nozzles in the throat of the
roof monitor (see Figure 14-1). Construct all
sample-exposed surfaces within the nozzles.
manifold and sample duct of 316 stainless
steel. Aluminum may be used if a new
ductwork system is conditioned with
fluoride-laden roof monitor air for a period of
six weeks prior to initial testing. Other
materials of construction may be used if it is
demonstrated through comparative testing
that there is no loss of flourides in the
system. All connections in the ductwork shall
be leak free.
Locate two sample ports in a vertical
section of the duct between the roof monitor
and exhaust fan. The sample ports shall be at
least 10 duct diameters downstream and
three diameters upstream from any flow
disturbance such as a bend or contraction.
The two sample ports shall be situated 90°
apart. One of the sample ports shall be
situated so that the duct can be traversed in
the plane of the nearest upstream duct bend.
2.2.2 Exhaust fan. An industrial fan or
blower shall be attached to the sample duct
at ground level (see Figure 14-1). This
exhaust fan shall have a capacity such that a
large enough volume of air can be pulled
through the.ductwork to maintain an
isokinctic sampling rate in all the sample
nozzles for all flow rates normally
encountered in the roof monitor.
The exhausl fan volumetric flow rate shall
be adjustable so thai the roof monitor air can
be drawn isokinetically into the sample
nozzles. This control of flow may be achieved
by a damper on the inlet to the exhauster or
by any other workable method.
2.3 Temperature measurement apparatus.
2.3.1 Thermocouple. Install a
thermocouple in the roof monitor near th«
sample duct. The thermocouple shall conform
to the specifications outlined in Section 2.3 of
Method 2.
2.3.2 Signal transducer. Transducer, to
change the thermocouple voltage output to a
temperature readout.
2.3.3 Thermocouple wire. To reach from
roof monitor to signal transducer and
recorder.
2.3.4 Recorder. Suitable recorder to
monitor the output from the thermocouple
signal transducer.
2.4 Fluoride sampling train. Use the train
described in Method 13A or 13B.
3. Reagents.
3.1 Sampling and analysis. Use reagents
described in Method 13A or 13B.
4. Calibration.
4.1 Initial performance checks. Conduct
these checks within 60 days prior to the first
performance test.
4.1.1 Propeller anemometers.
Anemometers which meet the specifications
outlined in Section 2.1.1 need not be
calibrated, provided that a reference
performance curve relating anemometer
signal output to air velocity (covering the
velocity range of interest) is available from
the manufacturer. For the purpose of this
method, a "reference" performance curve is
defined as one that has been derived from
primary standard calibration data, with the
anemometer mounted vertically. "Primary
standard" data are obtainable by: (1) Direct
calibration of one or more of the
anemometers by the National Bureau of
Standards (N'BS): (2) NBS-traceable
calibration; or (3) Calibration by direct
measurement of fundamental parameters
such as length and time (e.g., by moving the
anemometers through still air at measured
rates of speed, and recording the output
signals). If a reference performance curve is
not available from the manufacturer, such a
curve shall be generated, using one of the
three methods described as above. Conduct a
performance-check as outlined in Section
4.1.1.1 through 4.1.1.3, below. Alternatively.
the tester may use any other suitable method.
subject to the approval of the Administrator.
that takes into account the signal output,
propeller condition and threshold velocity of
the anemometer.
4.1.1.1 Check the signal output of the
anemometer by using an accurate rpm
generator (see Figure 14-3) or synchronous
motors to spin the propeller shaft at each of
the three rpm settings described in Section
2.1.1 above (specification No. 7), and
measuring the output signal at each setting. If,
at each setting, the output signal is within ±
5 percent of the manufacturer's value, the
anemometer can be used. If the anemometer
performance is unsatisfactory, the
anemometer shall either be replaced or
repaired.
4.1.1.2 Check the propeller condition, by
visually inspecting the propeller, making note
of any significant damage or warpage;
damaged or deformed propellers shall be
replaced.
4.1.1.3 Check the anemometer threshold
velocity as follows: With the anemometer
mounted as ihown in Figure 14-4(A). fasten a
known weight (a ttraight-pin will suffice) to
the anemometer propeller at a fixed distance
from the center of the propeller shaft. This
will generate a known torque: for example, a
0.1 g weight, placed 10 cm from the center of
the ihnft. will generate a torqwe of 1.0 g-o». W
the known torque causes the propeller to
rotate downward, approximately 90° [nee
Figure 14-4(B)j. then the known torque is
greater than or equal to the starting torque: if
the propeller fails to rotate approximately
90°, the known torque is less than the starting
torque. By trying different combinations of
weight and distance, the starting torque of a
particular anemometer can be satisfactorily
estimated. Once an estimate of the starting
torque has been obtained, the threshold
velocity of the anemometer (for horizontal
mounting) can be estimated from a graph
such as Figure 14-5 (obtained from the
manufacturer). If the horizontal threshold
velocity is acceptable [<15 m/min (50 fpm),
when this technique is used], the anemometer
can be used. If the threshold velocity of an
anemometer is found to be unacceptably
high, the anemometer shall either be replaced
or repaired.
BILLING CODE 6560-01-M
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SIDE
(A)
FRONT
SIDE
(B)
FRONT
Figure 14-4. 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."
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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 calibration 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
system: otherwise, the system can be used.
4.1.4 Manifold Intake Nozzles. In order to
balance the flow rates in the eight individual
nozzles, 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 pilot 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
drawn into each nozzle is not the same, open
or close each blast gate (or valve) unlil the
velocity in each nozzle is the same. Fasten
each blast gate (or valve) so that it will
remain in this position and close the pilot
port holes. This calibration shall be
performed when the manifold system is
installed. Alternatively, the manifoTd may be
prcassembled and the flow rates balanced on
the ground, before being installed.
4.2 Periodical performance checks.
Twelve months after their initial installation.
check the calibration of the propeller
anemometers, thermocouple-potentiometer
system, and the recorders and/or counlers 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, unlil 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 not 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 ihe seclion of
Ihe roof monilor conlaining 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 conlaining the
sampling manifold may be continuously
monitored during the 24-hour period prior lo
the test run).
If there is question as to whether a single
estimate of average velocity is adequate for
an enlire test run (e.g., if velocities are
anticipated to be significantly different
during different potroom operations), the
tesler may opl to divide the tesl run into two
or more "sub-runs," and to use a different
estimated average velocity for each sub-run
(see Seclion 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
monilor. Readings shall be taken for each
anemometer every 15 minutes or at shorter
equal lime 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 exiling 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
5.1.1 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 al a velocity equal to the
appropriate estimated average velocity.
determined under Seclion 5.1.1. Equation 14-1
gives the correct stream velocity needed in
the duel 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 pilot lube traverse of Ihe sample
duct (using either a standard or type S pilot
lube): use the procedure outlined in Method 2.
8 (D,)1 1 min
v.= (v») . . (Equation 14-1)
(0.1* 60 sac
Where:
,vd = Desired velocity in duct al sampling
location, m/sec.
Dn = Diameter of a roof monitor manifold
nozzle, m.
Da = Diamelcr of duel 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 Adjustment during run. If the test
run is divided into two or more "sub-runs"
(see Section 5.1.1), additional isokinetic rate
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 adjuslments 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 Irain 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 Iho 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 tesl. 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 13A
or 13B.
5.4 Analysis. Use the analysis procedures
described in Method 13A or 13B.
6. Calculation.1!.
6.1 Isokinetic sampling check.
6.1.1 Calculate the mean velocity (v,n) 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 duel 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 vt from Section
6.1.3 as a percentage of the corresponding va
value from Section 8.1.2.
V-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 vt, 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 is 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.
(lOOv./v,,) -120
1 ^
200
• 6.2 Average velocity of roof monitor
gases. Calculate the average roof monitor
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:
(V
m(std)}1
(Equation 14j2)
Where:
C, = Average fluoride concentration in roof
monitor air. mg F/dscm.
F,=Tolal fluoride mass collected during a
particular sub-run, mg F (from Equation
13A-1 of Method 13A or Equation 13B-1
of Method 13B).
Vm(sid)=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.
,,,(293 K)
(Equation 14-3)
(Tm t 273 ) (760 mm Hg)
Where:
Qm = Average volumetric flow from roof
monitor at standard conditions on a dry
basis. mVmin.
A = Roof monitor open area. m2.
vmi = 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. = (1 B.J
Note.—Bw. 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 6-27-60: aM am|
BILLING CODE 6560-01-M
V-416
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Federal Register / Vol. 45, No. 136 / Monday, July 14, 1980 / Rules and Regulations
115
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1537-1]
Standards of Performance of New
Stationary Sources: Adjustment of
Opacity Standard for Fossil Fuel-Fired
Steam Generator
AGENCY: Environmental Protection
Agency.
ACTION: Correction of final rulemaking.
SUMMARY: On May 29,1980, at 45 FR
36077 a Final Rule was published setting
forth an adjustment of the opacity
standard for Interstate Power
Company's Lansing Unit No. 4, in
Lansing, Iowa. The promulgation
contained two typographical errors. In
the Summary, the action was described
as an adjustment of the capacity rather
than the opacity standard. Although in
the Summary the unit was correctly
described as Unit No. 4, the
promulgation below contained a
reference to Unit No. 1. This notice is to
correct those errors.
EFFECTIVE DATE: July 14, 1980.
FOR FURTHER INFORMATION CONTACT:
Henry F. Rompage, Enforcement
Division, EPA, Region VII, 32$ East llth
Street, Kansas City, Missouri 64106,
telephone 816/374-3171 or FTS 758-3171.
Dated: June 27,19OX
Kathleen Q. Camin,
Regional 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
1. Section 60.42 is amended by adding
paragraph (b)(2):
§60.42 [Amended]
except that a maximum of 39% opacity
shall be permitted for not more than six
minutes in any hour.
(Sec. 111.301(a), Clean Air Act as amended
(42 U.S.C. 7411, 7601))
2. Section 60.45 is amended by adding
paragraph (ii) as follows:
5 60.45 Emission and fuel monitoring.
*****
(8) * ' *
(1) * * *
(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.
|KR Doc. 8O-20947 Filed 7-11-TO 8:45 am|
(b) * * *
(2) Interstate Power Company shall
not cause to be discharged into the
atmosphere from its Lansing Station
Unit No. 4 in Lansing, Iowa, any gases
which exhibit greater than 32% opacity,
116
40 CFR Part 60
[FRL 1392-6]
Standards of Performance for New
Stationary Sources: Delegation of
Authority to Commonwealth of
Pennsylvania; Correction
AGENCY: Environmental Protection
Agency.
ACTION: Final rule, correction.
SUMMARY: On December 7.1979 the
Environmental Protection Agency
amended 40 CFR 60.4 to relect
delegation to the Commonwealth of
Pennsylvania for authority to implement
and enforce certain Standards of
Performance for New Stationary
Sources. The notice appeared in the
Federal Register on Wednesday.
January 16,1980 (45 FR 3034). Due to an
oversight that notice contained an error
in the lettering of the amendment of
i 60.4 Address. Today's notice provides
an amendment and revision to correct
that error.
FOR FURTHER INFORMATION CONTACT:
Joseph Arena, Environmental Scientist.
Air Enforcement Branch. Environmental
Protection Agency, Region III. 6th &
Walnut Streets, Philadelphia.
Pennsylvania 19106. Telephone (215)
597-4561.
SUPPLEMENTARY INFORMATION:
Correction: On page 3035. Column 1.
§ 60.4 Address is corrected to read as
follows:
1. NN(b] is added to read as follows:
§ 60.4 Address.
*****
(b) ' ' '
(A)-(NNJ(a) • ' '
(NN) (b) Commonwealth of Pennsylvania.
Department of Environmental Resources, Post
Office Box 2063, Harrisburg. Pennsylvania
17120.
2. (OO) is revised to read as follows:
*****
(OO) State of Rhode Island, Department of
Environmental Management. 83 Park Street.
Providence, Rhode Island 02906.
Dated: July 17,1980.
Stanley L. Laskowski.
Acting Director, Enforcement Division,
|FR Doc. 80-23133 Filed 7-3O-80 8:45 an I
V-417
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17
Federal Register / Vol. 45, No. 194 / Friday. October 3, 1980 / Rules and Regulations
40 CFR Part 60
[FRL 1525-7]
Standards of Performance for New
Stationary Sources; Addition of
Reference Methods 24 and 25 to
Appendix A
AGENCV: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action establishes two
,new reference methods to be added to
Appendix A of 40 CFR Part 60,
Standards of Performance for New
Stationary Sources. Reference Method
24 will be used to determine the volatile
organic compound (VOC) content of
coating materials, and Reference
Method 25 will be used to determine the
percentage reduction of VOC emissions
achieved by emission control devices.
These reference methods will be used in
several air pollution regulations for
industrial surface coatings which are
being developed for proposal and
promulgation.
EFFECTIVE DATE: October 3,1980.
ADDRESSES: Background Information
Document. The Background Information
Document (BID) for the promulgated test
methods 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
"Reference Methods 24 and 25—
Background Information for
Promulgated Test Methods." EPA-450/
3-79-030C.
Docket. Docket No. A-79-05,
containing all supporting information
and public comments, is available for
public inspection and copying between
8:00 a.m. and 4:00 pm., Monday through
Friday, at EPA's Central Docket Section,
Room 2902, Waterside Mall, 401 M
Street SW., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Gene W. Smith. Standards
Development Branch (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5421.
SUPPLEMENTARY INFORMATION:
Summary of Reference Methods
Reference Method 24, "Determination
of Volatile Matter Content, Water
Content, Density, Volume Solids, and
Weight Solids of Surface Coatings," is
used to determine the volatile matter
content, water content, density, volume
solids, and weight fraction solids of
paint, varnish, or related surface
coatings. Several ASTM standard
methods which comprise Method 24 are
used to make these determinations. All
coatings are analyzed by the same
procedure except for the additional step
of measuring the water content of
waterborne (water reducible) coatings.
A data validation procedure is used to
establish precision limits for the coating
analysis. This verifies the ability of the
analyst and the analytical procedure to
obtain reproducible results for the
coatings tested. In addition for
waterborne coatings, the measured
parameters are modified by the
appropriate confidence limits based on
between-laboratory precision
statements.
Reference Method 25, "Determination
of Total Gaseous Nonmethane Organic
Emissions as Carbon," is used to
measure the total gaseous nonmethane
organics in source emissions. An
evacuated cylinder is used to withdraw
emission samples from the stack through
a chilled condensate trap. After
sampling is completed, the contents of
the condensate trap and evacuated
cylinder are analyzed separately. The
organic content of the condensate trap is
oxidized to COj which is quantitatively
collected in an intermediate collection
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
chromatograph which separates the
nonmethane organics from carbon
monoxide, methane, and carbon dioxide;
the nonmethane organics are oxidized to
carbon dioxide, reduced to methane,
and measured by FID. The results of the
analyses are combined and reported as
total gaseous nonemethane organics.
Background
On October 5,1979, as an appendix to
the proposed standards of performance,
for automobile and light-duty truck
surface coating operations, EPA
proposed reference methods for
analyzing the volatile organic compound
(VOC) content of coatings. These
proposed methods were Reference
Method 24 (Candidate 1) and (Candidate
2). Candidate 1 expresses the VOC
content of surface coating in terms of
mass of carbon. Candidate 2, based on
the use of several ASTM methods,
reports the mass of VOC. Both test
methods were proposed to obtain public
comment.
Reference Method 25 was proposed at
the same time. It measures the volatile
organic emissions in effluent streams
from stationary sources. When used to
measure the inlet and outlet streams of
an emission control device, the
efficiency of the device can be
determined.
These methods would normally be
promulgated with the standards of
performance for automobile and light-
duty truck surface coating operations
which are scheduled to be promulgated
in the fall of 1980. However, the methods
are.being promulgated earlier because
several changes have been made to the
proposed methods, and several
regulations are being developed for
proposal in the near future which will
require the use of these methods. This
will allow the public to have the
opportunity to comment on the use of
these final methods in their respective
industries.
Public Participation
During development of the test
methods, trade and professional
associations and individual companies
supplied information and data on these
methods. After proposal on October 5,
1979, comments were received from
coatings manufacturers and suppliers.
trade and professional associations, and
State air pollution control agencies. The
methods were also discussed at a public
hearing held on November 9,1979. The
public comment period was extended
from October 5,1979, to December 14,
1979.
Public Comments and Changes Made to
Proposed Reference Methods
Fifteen comment letters were received
on the proposed test methods. These
comments have been carefully
considered and, where determined to be
appropriate by the Administrator,
changes have been made in the
proposed test methods. A detailed
discussion of these comments is
contained in the background document
entitled, "Reference Methods 24 and
25—Background Information for
Promulgated Test Methods," which is
referred to in the ADDRESSES section
of this preamble.
General
The Administrator has rejected
proposed Reference Method 24
(Candidate 1) and selected proposed
Reference Method 24 (Candidate 2) as
the test method to be used to determine
the volatile organic content of coatings.
Conclusive data were presented by
commenters showing that certain
coatings representing a significant
portion of those in use could not be
distilled as required by proposed
Method 24 (Candidate 1). For this
reason, the Administrator concluded
that proposed Method 24 (Candidate 1)
is not applicable to all coatings and
should not be selected as the reference
method.
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Federal Register / Vol. 45. No. 194 / Friday, October 3. 1980 / Rules and Regulations
Several procedural anH editorial
changes have been made to Reference
Method 24 (Candidate 2) and Reference
Method 25 as proposed in order to
clarify and to improve the sampling and
analytical procedures. These changes
are based on additional information
obtained by EPA from experience with
the methods and on the public
comments received.
Reference Method 24
The following discussion summarizes
the procedural changes made to
proposed Reference Method 24,
Candidate 2. The procedures were
added to protect the source owner from
invalid results that might result from
poor analytical techniques, application
of the method to a coating not suitable
for analysis with Reference Method 24,
or imprecision in Reference Method 24
resulting from a high percentage of
water in the solvent.
The promulgated reference method
requires the analyst to complete
duplicate analyses on each sample
tested. A comparison is then made
between these results and the within-
laboratory precision statements for each
parameter. Duplicate analyses are made
until the results fall within the range
established for the within-laboratory
precision statements. The purpose of the
procedures is to verify that the analyst
can achieve a level of precision for the
coating under analysis equal to or better
than the precision obtained by
experienced analysts participating in the
ASTM studies of the method. Because of
the variety of coatings that may be
subject to analysis, it is possible that
certain coatings may not be amenable to
analysis using Reference Method 24;
that is, in certain cases it may not be
possible to achieve results which meet
the precision limits. In this case, the
method provides for a case-by-case
evaluation and development of a
suitable procedure.
An additional procedure for
waterborne coatings was adde^ to the
promulgated reference method to protect
the source owner or operator from a
determination of noncompliance when
the owner is actually in compliance.
This procedure is needed because the
results of Reference Method 24 are
dependent on the difference between
the weight of total solvents and the
weight of water. As the percent weight
of water increases, the difference
decreases. As a result, any imprecision
in the measurement of the weight of
total solvent in water is magnified in the
calculation of organic solvent content.
For example, if the total solvent of a
coating is measured as 100±2 units and
the water content is measured at 90±2
units, the organic solvent content would
be in the range of 6 to 14 units. The
magnitude of the range, as a percent of
the true organic solvent content,
increases with increasing water content
and could, as shown in the example,
lead to a conclusion of noncompliance
even when the owner is in compliance.
The procedure added to Reference
Method 24 for waterborne coatings
protects the owner or operator from this
erroneous determination by minimizing
the calculated value for VOC content.
This is done, for example, by subtracting
the between-laboratory precision
statement from the average value of
total solvent and adding the between-
laboratory precision statement to the
average value for water content. Thus, if
a source owner is in compliance based
on average coating values, the
compliance method will automatically
show a lower VOC content because of
the adjustments made to the average
values based on the between-laboratory
precision statements.
Based on comments from
manufacturers that ASTM 2697 has only
been shown to bo applicable to
architectural coatings, the analytical
procedure for determining volume solids
has been eliminated from Reference
Method 24. The commenters stated that
this ASTM procedure was not
applicable to all the coatings that
Method 24 was intended to cover.
Therefore, Method 24 requires that the
volume solids be calculated from
manufacturer's formulation data.
The coatings classifications step in
the proposed method was eliminated
because industry comments indicated
that it was.only necessary to separate
waterborne (water reducible) and
solvent-borne (solvent reducible)
coatings. Therefore, the "Procedure"
discussed in Section 4 of the proposed
method has been simplified.
Several commenters recommended
that the use of coatings manufacturers'
data be allowed in calculating VOC
content of coatings rather than required
Method 24. Coatings manufacturers'
data will be allowed in calculating VOC
content of coatings because this will
reduce the burden on the industry to
measure all coatings with Method 24.
Use of this method to calculate VOC
content of coatings will require
industries to closely monitor and record
all organic solvents added to the
coatings at the plant Method 24 will be
the reference method.
One commenter suggested that EPA
should specify the volume fraction of
solids for the various types of coatings
similar to the way transfer efficiencies
were listed. Based on comments from
manufacturers that ASTM 2897 has only
been shown to be applicable to
architectural coatings, the volume
fraction of solids determination in
Method 24 has been removed. Method
24 specifies the use of manufacturer's
formulation data for calculating volume
fraction of solids.
Reference Method 25
The majority of the procedural
changes made to Method 25 relate to
calibration requirements and are meant
to improve quality assurance and at the
same time simplify the daily operation
of the analytical equipment. This is
accomplished by requiring performance
tests on the analytical equipment
(nonmethane organic analyzer and
condensate recovery and conditioning
apparatus) prior to initial use; specific
criteria for the performance tests are
provided. Routine daily calibrations
(much less time consuming than
previously required) are conducted and
the results are compared to performance
test reference values to determine
whether the performance of the
analytical equipment is still acceptable.
In the promulgated test method,
several important system components
are not specified; instead, minimum
performance specifications for these
components are provided. The method is
written in this manner to allow
individual preference in choosing
components, as well as to encourage
development and use of improved
components. Therefore, Addendum I
which lists specific information
regarding system components found to
be acceptable has been added to the
method to provide guidance for users.
Specifics of the most important
procedural changes that have been
included in the promulgated test method
are as follows:
1. Section 1.1. Applicability. This
section was rewritten to clarify the
applicability of Method 25 in relation to
several other organic measurement
methods.
2. Section 2.2.2 Nonmethane Organic
Analyzer. The reference to the analyzer
is changed from "total gaseous
nonmethane organic analyzer" to
nonmethane organic analyzer (NMO).
The description is clarified to indicate
that the NMO analyzer is also used to
quantify COi from trap condensate
recovery. Furthermore, a requirement
that the NMO analyzer meet an initial
performance test with specific criteria is
added. Previously, only demonstration
of "proper separation, oxidation,
reduction end measurement" was
required.
3. Section 4.1.3 Pretest Leak Check.
The leak check procedure is simplified.
Instead of evacuating the sample train,
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Federal Register / Vol. 45. No. 194 / Friday. October 3, 1980 / Rules and Regulations
the sample probe is plugged and then
the sample value is opened; the sample
tank vacuum gauge is monitored for a
change in vacuum.
4. Section 4.1.4 Sample Train
Operation. This section is clarified to
indicate that any probe extension used
must be positioned totally in the stack
effluent; any portion of the sample probe
outside the stack wall must be analyzed
as part of the condensate trap.
5. Section 4.1.5 Post Test Leak Check.
The leak check procedure is simplified
(see "3" above).
6. Section 4.3.3 Recovery of
Condensate Trap Sample. A
requirement for mixing auxiliary oxygen
with the carrier gas just prior to the
catalyst is added. The procedures are
clarified to indicate that the condensate
trap is placed in a muffle furnace at
500° C (changed from 600°C) and that the
probe must be heated.
7. Section 5.1 Initial Performance
Check for Condensate Recovery and
Conditioning Apparatus. A requirement
is added for an initial performance test
of the system which includes a carrier
gas blank value determination (section
5.1.1), and oxidation catalyst efficiency
check (section 5.1.2), and an overall
system performance check via liquid
injections (section 5.1.3). Previously,
only a catalyst efficiency check was
required.
8. Section 5.2 Initial NMO Analyzer
Performance Test. The calibration
criteria for the NMO analyzer are
changed to include an initial
performance test. This performance test
requires an oxidation catalyst check
(5.2.1), and an analyzer linearity check
(5.2.2), determination of a NMO
calibration response factor (5.2.2),
determination of a CO> calibration
response factor (5.2.3), determination of
a NMO blank value (5.2.4) and a system
check using several gaseous organic
compounds (5.2.5).
9. Section 5.3 NMO Daily Calibration.
This section requires that a daily
calibration of the NMO analyzer be
conducted. The calibration involves one
COj calibration gas and one propane
calibration gas. Response factors are
determined for both Cd and NMO, and
a NMO blank value is measured. This
calibration is conducted with the
oxidation and reduction catalysts in full
operation. The results obtained are
compared to the reference values
obtained during the initial performance
test in order to determine if the analyzer
performance is acceptable. This daily
calibration procedure is greatly
simplified compared to the procedure
previously required which included
bypassing the oxidation and reduction
catalysts and using several different
concentration levels of methane, carbon
dioxide and propane calibration gases.
10. Section 6.2 Noncondensible
Organics. The calculation for the NMO
concentration of the contents of each
collection tank is changed by rewriting
the equation to include the subtraction
of the daily NMO blank value from the .
measured concentration.
11. Section 6.3 Condensible Organics.
The calculation for the NMO
concentration of the contents of each
condensate trap is changed by rewriting
the equation to include the substraction
of the daily condensate recovery and
conditioning system carrier blank value
from the measured COt concentration.
Other Comments
1. One commenter noted that the
drying time was different for ASTM D-
2369 and ASTM D-2697, and that these
procedures were not consistent with
each other. Since ASTM D-2697 has
been deleted, this comment is no longer
applicable.
2. Three commenters recommended
that the direct use of a flame ionization
detection (FID) system or similar
instrumentation systems be allowed
instead of Method 25. The specific
comments made and EPA's responses
are as follows:
a. Direct FID is simpler and more
precise. While the direct use of an FID
system is. simpler than Method 25, it will
not give accurate results in many
situations because the instrument
response varies with different
compounds. Therefore, the FID system
cannot be considered an adequate
reference method, but may be
acceptable as an alternative compliance
procedure on a case-by-case basis as
allowed in 40 CFR 60.8(b).
b. The ability to conduct on-site
analyses and DOT restrictions
associated with shipping organic
samples from a source location to a
laboratory make the FID preferable. The
ability to use the FID system to conduct
on-site analyses is not in itself sufficient
justification to allow the use of direct
flame ionization detection. DOT
regulations regarding shipment of
hazardous materials do require that
great care be taken in shipping the test
samples. The DOT regulations impose
strict packaging requirements on
flammable liquids and compressed
flammable gases. However, exemptions
for the strict packaging requirements are
permitted for most liquids if less than
one quart is shipped (see 49 CFR
172.101). In addition, the gas sample
tanks likely to be shipped from an on-
site location to a laboratory for analyses
do not meet the DOT definition of a
compressed flammable gas because the
sample tanks are not under high
pressure and, therefore, should not pose
a shipping problem (see 49 CFR 173.300).
Miscellaneous
This final 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)).
Dated: September 25,1980.
Douglas M. Costle,
Administrator.
Appendix A of 40 CFR Part 60 is
amended by adding Reference Methods
24 and 25 as follows:
Appendix A—Reference Methods
Method 24—Determination of Volatile Matter
Content, Water Content. Density, Volume
Solids, and Weight Solids of Surface Coatings
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of volatile matter content,
water content, density, volume solids, and
weight solids of paint, varnish, lacquer, or
related surface coatings.
1.2 Principle. Standard methods are used
to determine the volatile matter content
water content, density, volume solids, and
weight solids' of the paint, varnish, lacquer, or
related surface coatings. J
2. Applicable Standard Methods
Use the apparatus, reagents, and
procedures specified in the standard methods
below:
2.1 ASTM D1475-60. Standard Method of
Test for Density of Paint, Lacquer, and
Related Products.
2.2 ASTM D 2369-81. Provisional Method
of Test for Volatile Content of Paints.
2.3 ASTM D 3792-79. Standard Method of
Test for Water in Water Reducible Paint by
Direct Injection into a Gas Chromatograph.
2.4 ASTM Provisional Method of Test for
Water in Paint or Related Coatings by the
Karl Fischer Titration Method.
3. Procedure
3.1 Volatile Matter Content. Use the
procedure in ASTM D 2369-61 to determine
the volatile matter content (may include
water) of the coating. Record the following
information:
Wi=Weight of dish and sample before
heating, g.
Wi=Weight of dish and sample after heating,
8-
W»=Sample weight, g.
Run analyses in pairs (duplicate sets) for
each coating until the criterion In section 4.3
is met. Calculate the weight fraction of the
volatile matter (W,) for each analysis as
follows:
w,
Eq. 24-1
Record the arithmetic average (W,).
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Federal Register / Vol. 45, No. 194 / Friday, October 3, 1980 / Rules and Regulations
32 Water Content For waterbome (water
reducible) coatings only, determine the
weight fraction of water |WV) using either
"Standard Method of Test for Water in Water
Reducible Paint by Direct Infection into a Gas
Chromatograph" or "Provisional Method of
Test for Water in Paint or Related Coatings
by the Karl Fischer Tltratioa Method." A
waterbome coating is any coating which
contains more than 5 percent water by weight
in its volatile fraction. Run duplicate sets of
determinations'until the criterion in section
4.3 is met Record the arithmetic average
(W.).
3.3 Coating Density. Determine the
density (D*, kg/liter) of the surface coating
using the procedure in ASTM D1475-60.
Run duplicate sets of determinations for
each coating until the criterion in section 4.3
is met Record the arithmetic average (D,).
3.4 Solids Content. Determine the volume
fraction (V.) solids of the coating by
calculation using the manufacturer's
formulation.
4. Data Validation Procedure
4.1 Summary. Hie variety of coatings that
may be subject to analysis makes it
necessary to verify the ability of the analyst
and the analytical procedures to obtain
reproducible results for the coatings tested.
This is done by running duplicate analyses on
each sample tested and comparing results
with the within-laboratory precision
statements for each parameter. Because of
the inherent Increased imprecision in the
determination of the VOC content of
waterbome coatings as the weight percent
water increases, measured parameters for
waterbome coatings are modified by the
appropriate confidence limits based on
between-laboratory precision statements.
4.2 Analytical Precision Statements. The
wtttuH-teboretory and between-laboratory
precision statements are given below:
Wittwv
Volatile nutter content, W.. 1.6 pet W. 4.7 pel W..
Water content, W. i» pet W. 7.S pet W..
Density, D« 0.001 Kg/liter... 0.002 Kg/liter.
4.3 Sample Analysis Criteria. For W. and
WOT ran duplicate analyses until the
difference between the two values in a set is
less than or equal to the within-laboratory
precision statement for that parameter. For D,
run duplicate analyses until each value in a
set deviates from the mean of the set by no
more than the within-laboratory precision
statement If after several attempts it is
concluded that the ASTM procedures cannot
be used for the specific coating with the
established within-laboratory precision, the
Administrator will assume responsibility for
providing the necessary procedures for
revising the method or precision statements
upon written request to: Director, Emission
Standards and Engineering Division, (MD-13)
Office of Air Quality Planning and Standards.
U.S. Environmental Protection Agency.
Research Triangle Park. North Carolina
27711.
4.4 Confidence Limit Calculations for
Waterbome Coatings. Based on'the between-
laboratory precision statements, calculate the
confidence limits for waterbome coatings as
follows:
To calculate the lower confidence limit
subtract the appropriate between-laboratory
precision value from the measured mean
value for that parameter. To calculate the
upper confidence limit add the appropirate
between-laboratory precision value to the
measured mean value for that parameter. For
W, and D0 use the lower confidence limits,
and for W., use the upper confidence limit.
Because V, is calculated, there is no
adjustment for the parameter.
5. Calculations
6.1 Nonaqueous Volatile Matter.
5.1.1 Solvent-borne Coatings.
W0=W, Eq. 24-2
Where:
W0=Weight fraction nonaqueous volatile
matter, g/g.
S.I.2 Waterbome Coatings.
W0=W,-W. Eq. 24-3
5.2 Weight fraction solids.
W.=1-W, Eq. 24-4
Where: W.=Weight solids, g/g.
ft Bibliography
6.1 Provisional Method Test for Volatile
Content of Paints. Available from: Chairman,
Committee D-l on Paint and Related
Coatings and Materials, American Society for
Testing and Materials, 1916 Race Street
Philadelphia, Pennsylvania 19103. ASTM
Designation D 2389-ffL
0.2 Standard Method of Test for Density
of Paint Varnish, Laaqoer, and Related
Prodacts. In: 1980 Book of ASTM Standards,
Part 27. Philadelphia, Pennsylvania. ASTM
Designation D1475-60. I960.
6.3 Standard Method of Test for Water tn
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
Street Philadelphia, Pennsylvania 19103.
ASTM Designation D 3792-79.
6.4 Provisional Method of Test 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 Street,
Philadelphia, Pennsylvania 19103.
Method 25—Determination of Total Gaseous
Nonmethane Organic Emissions as Carbon
1. Applicability and Principle
1.1 Applicability. This method applies to
the measurement of volatile organic
compounds (VOC) as total gaseous
nonmethane organics (TGNMO) as carbon in
source emissions. Organic paniculate matter
will interfere with the analysis and therefore,
in some cases, an in-stack particulate filter is
required. This method is not the only method
that applies to the measurement of TGNMO.
Costs, logistics, and other practicalities or
source testing may make other test methods
more desirable for measuring VOC of certain
effluent streams. Proper judgment if lequired
in determining the most applicable VOC test
method. For example, depending upon the
molecular weight of the organics in the
effluent stream, a totally automated semi-
continuous nonmethane organic (NMO)
analyzer interfaced directly to the source
may yield accurate results. This approach has
the advantage of providing emission data
semi-conttnuously over an extended time
period.
Direct measurement of an effluent with a
flame ionization detector (FID) analyzer may
be appropriate with prior characterization of
the gas stream and knowledge that the
detector responds predictably to the organic
compounds in the stream. If present, methane
will, of course, also be measured. In practice,
the FID can be applied to the determination
of the mass concentration of the total
molecular structure of the organic emissions
under the following limited conditions: (1)
Where only one compound is known to exist;
(2) when the organic compounds consist of
only hydrogen and carbon: (3) where the
relative percentage of the compounds in
known or can be determined, and the FID
response to the compounds is known: (4)
where a consistent mixture of compounds
exists before and after emission control and
only the relative concentrations are to be
assessed; or (5) where the FID can be
calibrated against mass standards of the
compounds emitted (solvent emissions, for
example).
Another example of the use of s direct FID
is as a screening method. If there is enough
information available to provide a rough
estimate of the analyzer accuracy, the FID
analyzer can be used to determine the VOC
content of an uncharacterized gas stream.
With a sufficient buffer to account for
possible inaccuracies, the direct FID can be a
useful tool to obtain the desired results
without costly exact determination.
hi situations where a qualitative/
quantitative analysis of an effluent stream is
desired or required, a gas chromatographic
FID system may apply. However, for sources
emitting numerous organics, the time and
expense of this approach will be formidable.
12 Principle. An emission sample is
withdrawn from the stack at a constant rate
through a chilled condensate trap by means
of an evacuated sample tank. TGNMO are
determined by combining the analytical
results obtained from independent analyses
of the condensate trap and sample tank
fractions. After sampling is completed, the
organic contents of the condensate trap are
oxidized to carbon dioxide (COi) which is
quantitatively collected in an evacuated
vessel; then a portion of the CO> is reduced to
methane (CH«) and measured by a FID. The
organic content of the sample fraction
collected in the sampling tank is measured by
injecting a portion into a gas
chromatographic (GC) column to achieve
separation of the nonmethane organics from
carbon monoxide (CO), CO, and CH.; the
nonmethane organics (NMO) are oxidized to
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CO,, reduced to CH., and measured by a FID.
In this manner, the variable response of the
FID associated with different types of
organics is eliminated.
2. Apparatus
The sampling system consists of a
condensate trap, flow control system, and
sample tank (Figure 1). The analytical system
consists of two major sub-systems: an
oxidation system for the recovery and
conditioning of the condensate trap contents
and a NMO analyzer. The NMO analyzer is a
CC with backflush capability for NMO
analysis and is equipped with an oxidation
catalyst, reduction catalyst, and FID. (Figures
2 and 3 are schematics of a typical NMO
analyzer.) The system for the recovery and
conditioning of the organics captured in the
condensate trap consists of a heat source,
oxidation catalyst, nondispersive Infrared
(NDIR) analyzer and an Intermediate
collection vessel (Figure 4 is a schematic of a
typical system.) TGNMO sampling equipment
can be constructed from commercially
available components and components
fabricated in a machine shop. NMO
analyzers are available commercially or can
be constructed from available components by
a qualified instrument laboratory.
2.1 Sampling. The following equipment is
required:
2.1.1 Probe. 3.2-mm OD (W»-in.) stainless
steel tubing.
2.1.2 Condensate Trap. Constructed of 316
stainless steel; construction details of a
suitable trap are shown in Figure 5.
2.1.3 Flow Shut-off Valve. Stainless steel
control valve for starting and stopping
sample flow.
2.1.4 Flow Control System. Any system
capable of maintaining the sampling rate to
within ±10 percent of the selected flow rate
(50 to 100 cc/min range).
2.1.5 Vacuum Gauge. Gauge for
monitoring the vacuum of the sample tank
during leak checks and sampling.
2.1.6 Sample Tank. Stainless steel or
aluminum tank with a volume of 4 to 8 liters,
equipped with a stainless steel female quick
connect for assembly to the sample train and
analytical system.
2.1.7 Mercury Manometer. U-tube
mercury manometer capable of measuring
pressure to within 1 mm Hg in the 0-900 mm
range.
2.1.8 Vacuum Pump. Capable of
evacuating to an absolute pressure of 10 mm
Hg.
2.2 Analysis. The following equipment is
required:
2.2.1 Condensate Recovery and
Conditioning Apparatus. An apparatus for
recovering and catalytically oxidizing the
condensate trap contencs is required. Figure 4
is a schematic of such a system. The analyst
must demonstrate prior to initial use that the
analytical system is capable of proper
oxidation and recovery, as specified in
section 5.1. The condensate recovery and
conditioning apparatus consists of the
following major components.
2.2.1.1 Heat Source. A heat source
sufficient to heat the condensate trap
(including probe) to a temperature where the
trap turns a "dull red" color. A system using
both a propane torch and an electric muffle-
type furnace is recommended.
2.2.1.2 Oxidation Catalyst A catalyst
system capable of meeting the catalyst
efficiency criteria of this method (section
5.1.2). Addendum I of this method lists a
catalyst system found to be acceptable.
2.2.1.3 Water Trap. Any leak-proof
moisture trap capable of removing moisture
from the gas stream.
2.2.1.4 NDIR Detector. A detector capable
of indicating COi concentration in the zero to
1 percent range. This detector is required for
monitoring the progress of combustion of the
organic compounds from the condensate trap.
2.2.1.S Pressure Regulator. Stainless steel
needle valve required to maintain the trap
conditioning system at a near constant
pressure.
2.2.1.6 Intermediate Collection Vessel.
Stainless steel or aluminum collection vessel
equipped with a female quick connect. Tanks
with nominal volumes in the 1 to 4 liter range
are recommended.
2.2.1.7 Mercury Manometer. U-tube
mercury manometer capable of measuring
pressure to within 1 mm Hg in the 0-900 mm
range.
2.2.1.8 Gas Purifiers. Gas purification
systems sufficient to maintain COi and
organic impurities in the carrier gas and
auxiliary oxygen at a level of less than 10
ppm (may not be required depending on
quality of cylinder gases used).
2.2.2 NMO Analyzer. Semi-continuous
CC/FID analyzer capable of: (1) separating
CO, COi, and CH. from nonmethane organic
compounds, (2) reducing the COi to CH< and
quantifying as CH, and (3) oxidizing the
nonmethane organic comounds to CO*
reducing the COi to CH, and quantifying as
CH,. The analyst must demonstrate prior to
initial use that the analyzer is capable of
proper separation, oxidation, reduction, and
measurement (section 5.2). The analyzer
consists of the following major components:
2.2.2.1 Oxidation Catalyst. A catalyst
system capable of meeting the catalyst
efficiency criteria of this method (section
5.2.1). Addendum I of this method lists a
catalyst system found to be acceptable.
2.2.2.2 Reduction Catalyst. A catalyst
system capable of meeting the catalyst
efficiency criteria of this method (section
5.2.3). Addendum I of this method lists a
catalyst system found to be acceptable.
2.2.2.3 Separation Column(s). Gas
chromatographic column(s) capable of
separating CO, CO., and CH, from NMO
compounds as demonstrated according to the
procedures established in this method
(section 5.2.5). Addendum I of this method
lists a column found to be acceptable.
2.2.2.4 Sample Injection System. A GC
sample injection valve fitted with a sample
loop properly sized to interface with the
NMO analyzer (1 cc loop recommended).
2.2.2.5 FID. A FID meeting the following
specifications is required.
2.2.2.5.1 Linearity. A linear response (±
5%) over the operating range as demonstrated
by the procedures established in section 5.2.2.
2.2.2.5.2 Range. Signal attenuators shall
be available to produce a minimum signal
response of 10 percent of full scale for a full
scale range of 10 to 50000 ppm CH,.
2.2.2.6 Data Recording System. Analog
strip chart recorder or digital intergration
system compatible with the FID for
permanently recording the analytical results.
2.2.3 Barometer. Mercury, aneroid, or
other barometer capable of measuring
atmospheric pressure to within 1 mm Hg.
2.2.4 Thermometer. Capable of measuring
the laboratory temperature within 1°C.
2.2.5 Vacuum Pump. Capable of
evacuating to an absolute pressure of 10 mm
Hg.
2.2.6 Syringe (2). 10 pi and 100 pi liquid
injection syringes.
2.2.7 Liquid Sample Injection Unit 316 SS
U-tube fitted with a Teflon injection septum,
see Figure 6.
3. Reagents
3.1 Sampling. Crushed dry ice is required
during sampling.
3.2 Analysis.
3.2.1 NMO Analyzer. The following gases
are needed:
3.2.1.1 Carrier Gas. Zero grade gas
containing less than 1 ppm C. Addendum I of
this method lists a carrier gas found to be
acceptable.
3.2.1.2 Fuel Gas. Pure hydrogen,
containing less than 1 ppm C.
3.2.1.3 Combustion Gas. Zero grade air or
oxygen as required by the detector.
3.2.2 Condensate Recovery and
Conditioning Apparatus.
3.2.2.1 Carrier Gas. Five percent O. in N,,
containing less than 1 ppm C.
3.2.2.2 Auxiliary Oxygen. Zero grade
oxygen containing less than 1 ppm C.
3.2.2.3 Hexane. ACS grade, for liquid
injection.
3.2.2.4 Toluene. ACS grade, for liquid
injection.
3.3 Calibration. For all calibration gases,
the manufacturer must recommend a
maximum shelf life for each cylinder (i.e., the
length of time the gas concentration is not
expected to 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. The following calibration gases are
required.
3.3.1 Oxidation Catalyst Efficiency Check
Calibration Gas. Gas mixture standard with
nominal concentration of 1 percent methane
m air.
3.3.2 Flame lonization Detector Linearity
and Nonmethane Organic Calibration Gases
(3). Gas mixture standards with nominal
propane concentrations of 20 ppm. 200 ppm,
and 3000 ppm, in air.
3.3.3 Carbon Dioxide Calibration Gases
(3). Gas mixture standards with nominal CO.
concentrations of 50 ppm, 500 ppm, and 1
percent, in air. Note: total NMO less than 1
ppm required for 1 percent mixture.
3.3.4 NMO Analyzer System Check
Calibration Gases (4).
3.3.4.1 Propane Mixture. Gas mixture
standard containing (nominal) 50 ppm CO, 50
ppm CH,, 2 percent CO., and 20 ppm CJ-U.
prepared in air.
3.3.4.2 Hexane. Gas mixture standard
containing (nominal) 50 ppm hexane in air.
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3.3.4.3 Toluene. Gas mixture standard
containing (nominal) 20 ppm toluene in air.
3.3.4.4 Methanol. Gas mixture standard
containing (nominal) 100 ppm melbanol in air.
4. Procedure
4.1 Sampling.
4.1.1 ' Sample Tank Evacuation and Leak
Check. Either in the laboratory or in the field.
evacuate the sample tank to 10 mm Hg
absolute pressure or less (measured by a
mercury U-tube manometer) then leak check
the sample tank by isolating the tank from
the vacuum pump and allowing the tank to sit
for 10 minutes. The tank is acceptable if no
change in tank vacuum is noted.
4.1.2 Sample Train Assembly. Just prior to
assembly, measure the tank vaccuum using a
mercury U-tube manometer. Record this
vaccum (Pu), the ambient temperature (Tu),
and the barometric pressure (PbJ at this time.
Assuring that the flow shut-off 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 2.5
or 5 cm of the point where the inlet tube joins
the trap body.
4.1.3. Pretest Leak Check. A pretest leak
check is required. After the sampling train is
assembled, record the tank vacuum as
indicated by the vaccum gauge. Wait a
minimum period of 10 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, assure that the
probe tip is tightly plugged and then open the
sample train flow shut-off valve. Allow the
sample train to sit for a minimum period of 10
minutes. The leak check is acceptable if no
visible change in the tank vacuum gauge
occurs. Record the pretest leak rate (cra/Hg
per 10 minutes). At the completion of the leak
check period, close the sample flow shut-off
valve.
4.1.4. 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. If a probe extension which
will not be analyzed as part of the
condensate trap is being used, assure that at
least a IS cm section of the probe which will
be analyzed with the trap is in the stack
effluent. For stacks having a negative static
pressure, assure that the sample port is
sufficiently sealed to prevent air in-Ieakage
around the probe. Check the dry ice level and
add ice if necessary. Record the clock time
and sample tank gauge vacuum. To begin
campling, open the flow shut-off valve and
adjust (if applicable) the control valve of the
•flow control system used in the sample train;
maintain a constant flow rate (±10 percent)
throughout the duration of the sampling
period. Record the gauge vacuum and
flowmeter setting (if applicable) at 5-minute
intervals. Select e total sample time greater
than or equal to the minimum sampling time
specified in the applicable oubpart of the
regulation; end the sampling when this time
period is reached or when a constant flow
rate can no longer be maintained due to
reduced sample tank vacuum. When the
sampling is completed, close the flow shut-off
valve and record the final sample time and
guag3 vacuum 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 aa
follows: After removing the probe from the
stack, remove the used sample tank from the
sampling train (without disconnecting other
portions of the sampling train) and connect
another sample 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 thai
the tank has been leak-checked (on-site).
After the new tank is attached to the sample
train, proceed with the sampling until the
required minimum sampling time has been
exceeded.
4.1.5 Post Test Leak Check. A leak check
is mandatory at the conclusion of each test
run. After sampling Is completed, remove the
probe from the stack and plug the probe tip.
Open the sample train flow shut-off valve
and monitor the sample tank vacuum gauge
for a period of 10 minutes. The leak check is
acceptable if no visible change in the tank
vacuum gauge occurs. Record the post test
leak rate (cm Hg per 10 minutes). If the
sampling train does not pass the post leak
check, invalidate the run or use a procedure
acceptable to the Administrator to adjust the
data.
4.2 Sample Recovery. After the post test
leak check is completed, disconnect the
condensate trap at the flow metering system
and tightly seal both ends of the condensate
trap. Keep the trap packed in dry ice until the
samples are returned to the laboratory for
analysis. Remove the flow metering system
from the sample tank. Attach the U-tube
manometer to the tank (keep length of
connecting line to a minimum) and record the
final tank vacuum (P,); record the tank
temperature (T,5 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 the sample tank(s).
4.3 Condensate Recovery and
Conditioning. Prepare the condensate
recovery and conditioning apparatus by
setting the carrier gas flow rate and heating
the catalyst to its operating temperature.
Prior to initial use of the condensate recovery
and conditioning apparatus, a system
performance test must be conducted
according to the procedures established in
section 5.1 of this method. After successful
completion of the initial performance test, the
system is routinely used for sample
conditioning according to the following
procedures:
4.3.1 System Blank and Catalyst
Efficiency Check. Prior to and immediately
following the conditioning of each set of
sample traps, or on a daily basis (whichever
occurs first) conduct the carrier gas blank test
and catalyst efficiency test as specified in
sections 5.1.1 and 5.1.2 of this method. Record
the carrier gas initial and final blank values,
Bu and BU, respectively. If the criteria of the
tests cannot be met, make the necessary
repairs to the system before proceeding.
4.3.2 Condensate Trap Carbon Dioxide
Purge and Sample Tank Pressurization. The
first step in analysis is to purge the
eondensate trap of any CCs which it may
contain and to simultaneously pressurize the
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 condensate 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 valves
isolating the collection vessel connection
from the atmospheric vent and the vacuum
pump are closed and then attach the 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. The condensate trap recovery and
conditioning apparatus should now be se> up
as indicated in Figure 8 Monitor the NDIR:
when CO, is no longer being passed thrr'jgh
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 Hg. At this time, isolate
the tank, vent the carrier flow, and record the
sample tank pressure (P,(). barometric
pressure (Pw), and ambient temperature (T«).
Remove the sample tank from the system.
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 completed in
section 4.3.1.2 above, the system should b^
set up so that the carrier flow bypasses the
condensate trap, bypasses the oxidation
catalyst, and is vented to the atmosphere.
Attach an evacuated intermediate collersion
vessel to the system and then switch the
carrier so that it flows through the oxidation
catalyst. Switch the carrier from vent to
collect and open the valve to the collection,
vessel; remove the dry ice from the trap anr)
then switch the carrier flow through the trap.
The system should now be set up to opers:e
as indicated in Figure 9. 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).
Begin heating the condensate trap and probe
with a propane torch. The trap should be
heated to a temperature at which the trap
glows a "dull red" (approximately 500°C).
During the early part of the trap "burn out,"
adjust the carrier and auxiliary oxygen flow
rates so that an excess of oxygen is being fed
to the catalyst system. Gradually increase the
flow of carrier gas through the trap. After ihe
NDIR indicates that most of the organic
matter has been purged, place the trap in a
muffle furnance (500°C). Continue to heat the
probe with a torch or some other procedure
(e.g., electrical resistance heater). Continue
this procedure for at least 5 minutes after the
NDIR has returned to baseline. Remove the
heat from the trap but continue the carrier
flow until the intermediate collection vessel
is pressurized to a gauge pressure of 800 mm
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Hg (nominal). When the vessel is pressurized.
vent the carrier; measure and record the final
intermediate collection vessel pressure (Pt) as
well as the barometric pressure (Pb,), ambient
temperature (TT), and collection vessel
volume (Vv).
4.4 Analysis. Prior to putting the NMO
analyzer into routine operation, an initial
performance test must be conducted. Start
the analyzer and perform all the necessary
functions in order to put the analyzer in
proper working order, then conduct the
performance test according to the procedures
established in section 5.2. Once the
performance test has been successfully
completed and the CO, and NMO calibration
response factors determined, proceed with
sample analysis as follows:
4.4.1 Daily operations and calibration
checks. Prior to and immediately following
the analysis of each set of samples or on a
daily basis (whichever occurs first) conduct a
calibration test according to the procedures
established in section 5.3. If the criteria of the
daily calibration test cannot be met. repeat
the NMO analyzer performance test (section
52) before proceeding.
4.4.2 Analysis of Recovered Condensate
Sample. 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 obtained for the condensible organics
as CO, (CcJ.
4.4.3 Analysis of Sample Tank. 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 sample tank and
record the values obtained for the
nonmethane organics (Clm).
5. Calibration and Operational Checks
Maintain a record of performance of each
item.
5.1 Initial Performance Check of
Condensate Recovery and Conditioning
Apparatus.
5.1.1 Carrier Gas and Auxiliary Oxygen
Blank. Set equal flow rates for both the
carrier gas and auxiliary oxygen. With the
trap switching valves in the bypass position
and the catalyst in-line, fill an evacuated
intermediate collection vessel with carrier
gas. Analyze the collection vessel for CO,;
the carrier blank is acceptable if the COj
concentration is less than 10 ppm.
5.1.2 Catalyst Efficiency Check. 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 valves isolating the
collection system from the atmospheric vent
and vacuum pump are closed and then attach
an evacuated intermediate collection vessel
to the system. Connect the methane standard
gas cyclinder (section 3.3.1) to the system's
Condensate trap connector (probe end. Figure
4). Adjust the system valving so that the
standard gas cylinder acts as the carrier gas
and adjust the flow rate to the rate normally
used during trap sample recovery. Switch off
the auxiliary oxygen flow and then switch
from vent to collect in order to begin
collecting a sample. Continue collecting a
sample in a normal manner until the
intermediate vessel is filled to a nominal
gauge 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.
Analyze the collection vessel for CO,; the
catalyst efficiency is acceptable if the CO,
concentration is within ±5 percent of the
expected value.
5.1.3 System Performance Check.
Construct a liquid sample injection unit
similar in design to the unit shown in Figure
6. Insert this unit into the condensate
recovery and conditioning system in place of
a condensate trap and set the carrier gas and
auxiliary oxygen flow rates to normal
operating levels. Attach an evacuated
intermediate collection vessel to the system
and switch from system vent to collect. With
the carrier gas routed through the injection
unit and the oxidation catalyst, inject a liquid
sample (see. 5.1.3.1 to 5.1.3.4) via the injection
septum. Heat the Injection unit with a torch
while monitoring the oxidation reaction on
the NDIR. Continue the purge until the
reaction is complete. Measure the final
collection vessel pressure and then analyze
the Vessel to determine the COu
concentration. For each injection, calculate
the percent recovery using the equation in
section 6.6.
* The performance test is acceptable if the
average percent recovery is 100 ± 10 percent
with a relative standard deviation (section
6.7) of less than 5 percent for each set of
triplicate injections as follows:
5.1.3.1 100 ul hexane.
5.1.3.2 10 ill hexane.
5.1.3.3 100 ul toluene.
5.1.3.4 10 p.1 toluene.
5.2 Initial NMO Analyzer Performance
Test.
5.2.1 Oxidation Catalyst Efficiency Check.
Turn off or bypass the NMO analyzer
reduction catalyst. Make triplicate injections
of the high level methane standard (section
3.3.1). The oxidation catalyst operation is
acceptable if no FID response is noted.
5.2.2 Analyzer Linearity Check and NMO
Calibration. Operating both the oxidation and
reduction catalysts, conduct a linearity check
of the analyzer using the propane standards
specified in section 3.3. make triplicate
injections of each calibration gas and then
calculate the average response factor (area/
ppm C) for each gas, as well as the overall
mean of the response factor values. The
instrument linearity is acceptable if the
average response factor of each calibration
gas is within ± 5 percent of the overall mean
value and if the relative standard deviation
(section 8.7) for each set of triplicate
injections is less than ± 5 percent Record the
overall mean of the propane response factor
values as the NMO calibration response
factor (RFsKoJ-
5.2.3 Reduction Catalyst Efficiency Check
and CO, Calibration. An exact determination
of the reduction catalyst efficiency is not
required. Instead, proper catalyst operation is
indirectly checked and continuously
monitored by establishing a CO0 response
factor and comparing it to the NMO response
factor. Operating both the oxidation and
reduction catalysts make triplicate injections
of each of the CO, calibration gases (section
3.3.3). Calculate the average response factor
(area/ppm) for each calibration gas, as well
as the overall mean of tha response factor
values. The reduction catalyst operation is
acceptable if the average response factor of
each calibration gas is within ± 5 percent of
the overall mean value and if the relative
standard deviation (section 6.7) for each set
of triplicate injections io less than ± 5
percent. Additionally, the COo overall mean
response factor must be within ± 10 percent
of the NMO calibration response factor
(RFmo) calculated in section 5.Z2. Record the
overall mean of the response factor values BO
the CO, calibration response factor (RFcoo).
5.2.4 NMO System Blank. For the high
level CO, calibration gao (section 3.3.3)
record the NMO value measured during the
CO, calibration conducted in section 5.2.3.
This value io the NMO blank value for the
analyzer (BJ and should be less than 10 ppm.
5.2.5 System Performance Check. Check
the column separation and overall
performance of the analyzer by making
triplicate injections of the calibration gases
listed in section 3.3.4. The analyzer
performance is acceptable if the measured
NMO value for each gas (average of triplicate
injections) is within ± 12 percent of the
expected value.
5.3 NMO Analyzer Daily Calibration.
5.3.1 NMO Blank and CO,. Inject
triplicate samples of the high level CO0
calibration gas (section 3.3.3) and calculate
the average response factor. The system
operation is adequate if the calculated
response factor is within ± 10 percent of the
RFcoo calculated during the initial
performance test (section 5.2.2). Use the daily
response factor (DRFcoa) for analyzer
calibration and the calculation of measured
CO, concentrations in the collection vessel
samples. In addition, record the NMO blank
value (B0); this value should be less than 10
ppm.
5.3.2 NMO Calibration. Inject triplicate
samples of the mixed propane calibration
cylinder (section 3.3.4.1) and calculate the
average NMO response factor. The system
operation is adequate if the calculated
response factor io within ± 10 percent of the
RFtrco calculated during the initial
performance test (section 5.2.1). Use the daily
response factor (DRF^o) for analyzer
calibration and calculation of NMO
concentrations in the sample tanks.
5.4 Sample Tank. The volume of the gas
sampling tanks used must be determined.
Prior to putting each tank in service,
determine the tank volume by weighing the
tanks empty and then filled with deionized
distilled water; weigh to the nearest 5 gm and
record the results. Alternatively, measure tha
volume of water used to fill the tanks to the
nearest 5 mi
5.5 Intermediate Collection Vessel The
volume of the intermediate collection veoeelo
used to collect COa during the analysio of the
condensate traps must ba determined. Prior
to putting each vessel into servico, determine
the volume by weighing the vessel empty and
then filled with deionized distilled water,
weigh to the nearest 5 gm and record the
results. Alternatively, measure the volume of
water used to fill the tanks to the nearest 5
ml.
V-424
-------
to
m
6. Calculations
Note: All equations are written using absolute pressure;
I
absolute pressures are determined by adding the measured barometric
pressure to the measured gauge pressure.
6.1 Sample Volume. For each test run, calculate the gas
volume sampled;
V, • 0.386 V (-1 - Ji)
s \Tt Tt1/
6.2 Noncondenslble Organlcs. For each sample tank, determine
the concentration of nonmethane organics (ppm C):
tf
7
r Jml
6.3 Condenslble Organlcs, For each condensate trap determine
the concentration of organics (ppm C):
0.386
vP
s f
-E
6.4 Total Gaseous Nonmethane Organlcs (TGNMO). To determine
the TGNMO concentration for each test run, use the following
equation:
c - ct + cc
6.5 Total Gaseous Nonmethane Organlcs (TGNMO) Mass
Concentration. To determine the TGNMO mass concentration as
carbon for each test run, use the following equation:
Mr . 0.498 C
6.6 Percent Recovery. To calculate the percent recovery for
the liquid Injections to the condensate recovery and conditioning
system use the following equation:
M v
percent recovery -1.6 £ -*•
6.7 Relative Standard Deviation.
RSD
.M .A <«1 *
IT V n -
n - i
o
Z
p
M
$
a
tu
O
o
o
3"
w
re
CO
CO
O.
X^r
«
O
CO
-------
Federal Register / Vol. 45, No. 194 / Friday. October 3, 1980 / Rules and Regulations
Where:
B. = Measured NMO blank value for NMO
analyzer, ppm C.
B, = Measured CO, b"llk ""» '" •»"•"""« ™»'"»
and conditioning Byitctn carrier cu. ppm CO
C = total gaseous nonmethane organic
(TCNMO) concentration of the effluent.
ppm C equivalent.
Cc = Calculated condensible organic
(condensate trap) concentration of the
effluent, ppm C equivalent.
Ccm = Measured concentration (NMO
analyzer) for the condensate trap
[intermediate collection vessel), ppm
CO,
C, = Calculated noncondensible organic
concentration (sample tank) of the
effluent, ppm C equivalent.
C,m = Measured concentration (NMO
analyzer) for the sample tank, ppm NMO.
L = Volume of liquid injected, microliters.
M = Molecular weight of the liquid injected,
g/g mole.
Mc --total gaseous non-methane organic
( I'GNMO) mass concentration of the
effluent, rng C/dscm.
N = Curbon number of the liquid compound
injected (N = 7 for toluene. N = 6for
hexane).
P, = Final pressure of the intermediate
collection vessel, mm Hg absolute.
Pu=.CuS sample tank pressure prior to
sampling, mm Hg absolute.
P, =GdS sample tank pressure after sampling.
but prior to pressurizing, mm Hg
absolute.
PI, = Final gas sample tank pressure after
pressurizing, :nm Hg absolute.
T, •= Final temperature of intermediate
collection vessel. °K.
Tu = Sample tank temperature prior to
sampling. °K.
T, -Sample tank temperature at completion
of sampling. "K.
Tl( = Sample tank temperature after
pressurizing 'K.
V — Sample tank volume, cm.
Vv = intermediate collection vessel volume.
cm
V,--C",iis volume sampled, dscin.
n = Number of ;lj!a points.
q -Total number of analyzer injections of
intermediate collection vessel during
analysis (where k = injection number. 1
q|.
r -Total number of analyzer injections of
sample tank during analysis (where
I •- injection number. 1 . . . r).
K, = Individual measurements.
X = Mi:an value.
p = Dnnsity of liquid injected, g/cc.
7.1 S.ilu. Albert E.. Samuel Witz. and
Robert D Mad'hfe. Determination of Solvent
Vapor Concentrations by Total Combustion
Analysis A Comparison of Infrared with
Flame lonization Detectors. Paper No. 75-33.2
(Presented a! '.he fiH'.h Annual Meeting of the
Air Pollution Control Association. Boston.
MA. |une 15-20, 1975.) 14 p.
7.2 Srilo, Albert E.. William L. Oaks, and
Robert D. Macl'hee. Measuring the Organic
Carbon Content of Source Emissions for Air
Pollution Control. Paper No. 74-190.
(Presented a; the 67th Annual Meeting of the
Air Pollution Control Association Denver.
CO. (ur.e 9-13. 1974.) 25 p.
Method 25
Addendum I. System Components
In test Method 25 several important system
components are not specified; instead
minimum performance specifications are
provided. The method is written in this
manner to permit individual preference in
choosing components, as well as to
encourage development and use of improved
components. This addendum is added to the
method in order to provide users with some
specific information regarding components
which have been found satisfactory for use
with the method. This listing is given only for
the purpose of providing information and
does not constitute an endorsement of any
product by the Environmental Protection
Agency. This list is not meant to imply that
other components not listed are not
acceptable.
1. Condensate Recovery and Conditioning
System Oxidation Catalyst. %" ODX14"
inconel tubing packed with 8 inches of
hopcalite* oxidizing catalyst and operated at
800'C in a tube furnace. Note: At this
temperature, this catalyst must be purged
with carrier gas at all times to prevent
catalyst damage.
2. NMO Analyzer Oxidation Catalyst. VV
ODx 14" inconel tubing packed with 6 inches
of hopcalite oxidizing catalyst and operated
at 800'C in a tube furnace. (See note above.).
3. NMO Analyzer Reduction Catalyst.
Reduction Catalyst Module: Byron
Instruments. Raleigh. N.C.
4. Gas Chromatographic Separation
Column, '/e inch OD stainless steel packed
with 3 feet of 10 percent methyl silicone. Sp
2100 (or equivalent) on Supelcpport (or
equivalent), 80/100 mesh, followed by 1.5 feet
Porapak Q (or equivalent) 60/80 mesh. The
inlet side is to the silicone. Condition the
column for 24 hours at 200°C with 20 cc/min
N, purge.
During analysis for the nonmethane
organics the separation column is operated as
follows: First, operate the column at — 78°C
(dry ice bath) to elute CO and CH,. After the
CH, peak operate the column at 0°C to elute
CO,. When the CO* 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).
Note.—The dry ice operating condition
may be deleted if separation of CO and CH.
is unimportant.
Note.—Ethane and ethylene may or may
not be measured using thu's column; whether
or not ethane and ethylene are quantified will
depend on the Cd concentration in the gas
sample. When high levels of CO, are present.
.ethane and ethylene will elute under the tail
of the CO, peak.
5. Carrier Gas. Zero grade nitrogen or
helium or zero air.
BILLING CODE 6S6O-01-M
'MSA registered trademark.
V-426
-------
Federal Register / Vol. 45, No. 194 / Friday, October 3,1980 / Rules and Regulations
t
PROBE
EXTENSION
(IF REQUIRED)
FTI
BJ
SI
w
r*
A
Al
P
fc
PROBE
:K
i
VACUUM
GAUGE
FLOW f\\
^-^ RATE \\)
" CONTROLLER y
\
!
.
DRY ICE
AREA
Hki /v\
I lx*sj \£j
-L ON/OFF
r-J* f-OW
VN VALVE QUICK |±J
CONNECTOR COMHEClO
i
V
1
CONDENSATE EVACUATED
TRAP SAMPLE
TANK
Figure 1. Sampling apparatus
V-427
-------
Federal Register / Vol. 45. No. 194 / Friday. October 3.1980 / Rules and Regulations
CARRIER GAS
CALIBRATION STANDARDS,
SAMPLE TANK.
INTERMEDIATE
COLLECTION
VESSEL
(CONDITIONED TRAP SAMPLE)
SAMPLE
INJECTION
LOOP
HYDROGEN
COMBUSTION
AIR
Figure 2. Simplified schematic of non-methane organic (NMO) analyzer.
V-428
-------
ZERO
AIR
OR
5 ptrctnt
02/N2
CATALYST
BYPASS VALVE
*»
to
SEPARATION
COLUMN
NONMETHANE
ORGANIC
(BACKFLUSH)
CO
C02
CH4
COLUMN\V
BACKFLUSK^"
VALVE
SAMPLE
INJECT
VALVE
SAMPLE / CALIBRATION
TANK / CYLINDERS
OXIDATION
CATALYST
HEATED
CHAMBER
*
p
i
Q.
01
o
s*
FLOW
METER
n
a>
a
a
Qu
I
§
Hi
Figure 3. Nonmethane organic (NMO) analyzer.
-------
Federal Register / Vol. 45. No. 194 / Friday. October 3.1980 / Rules and Regulations
VALVE
FLOW
.CONTROL
f VALVES
SWITCHING
VALVES
CONNECTORS
CATALYST
BYPASS
4WAY
VALVES^
SAMPLE
CONOENSATE
TRAP
CARRIER
15 percent
02/N2
OXIDATION
CATALYST
HEATED
' CHAMBER
VENT HEAT
NDIR
ANALYZER
REGULATING
VALVE
FOR MONITORING PROGRESS
OF COMBUSTION ONLY
QUICK
CONNECT
VACUUM**
PUMP
V
H20
TRAP
MERCURY INTERMEDIATE
MANfXER COLL"J!°N
VcSScL
•FOR EVACUATING COLLECTION
VESSELS AND SAMPLE TANKS
(OPTIONAL)
Figure 4. Condensate recovery and conditioning apparatus.
V-430
-------
Federal Register / Vol. 45. No. 194 / Friday. October 3.1960 / Rules and Regulations
CONNECTOR
EXIT TUBE. 6mm Win) 0.0
NO. 40 HOLE
(THRU BOTH WALLS)
PROBE. 3mm (1/8 M O.D.
INLET TUBE. 6mm (K in) 0.0.
CONNECTOR
WELDED JOINTS
CRIMPED AND WELDED GAS TIGHT SEAL
VBARREL 19mm (X in) 0.0. X 140mm W-'i in) LONG.
1.5mm (1/16 in) WALL
BARREL PACKING. 316 SS WOOL PACKED TIGHTLY
AT BOTTOM. LOOSELY AT TOP
HEAT SINK (NUT.PRESS-FIT TO BARRED
WELDED PLUG
MATERIAL: TYPE 316 STAINLESS STEEL
Figure 5 Condensate trai>2.
V-431
-------
Federal Register / Vol. 45. No. 194 / Friday, October 3.1980 / Rules and Regulations
INJECTION
SEPTUM
CONNECTING T
FROM
CARRIER
APPRO X.
15 cm (6 in)
CONNECTING
ELBOW
TO
CATALYST
6 mm (1/4 in)
316 SS TUBING
Figure 6. Liquid sample injection unit.
V-432
-------
Federal Register / Vol. 45. No. 194 / Friday. October 3.1980 / Rules and Regulations
VOLATILE ORGANIC CARBON
FACILITY_
LOCATION.
DATE
SAMPLE LOCATION.
OPERATOR
RUN NUMBER
TANK NUMBER.
.TRAP NUMBER.
.SAMPLE ID NUMBER.
TANK VACUUM.
mm Hg cm Hg
PRETEST (MANOMETER)
POST TEST (MANOMETER)
ir.AUGE)
ir.Aiir.F)
BAROMETRIC
PRESSURE.
mm Hg
AMBIENT
TEMPERATURE.
°C
LEAK RATE
cm Hg / tO mtn
TIME
CLOCK/SAMPLE
PPFTFST
POST TEST
GAUGE VACUUM.
cm Hg
FLOWMETER SETTING
-
COMMENTS
Figure 7. Example Field Data Form.
V-433
-------
Federal Register / Vol. 45. No. 194 / Friday, October 3, 1980 / Rules and Regulations
CD CZH
FLOW
METERS ""
FLOW
CONTROL
VALVES N
(OPEN)
VENT
(OPEN) \
^ <*7 w
NOIR
ANALYZER'
Z_D REGULATING V_D • FOR MONITORING PROGRESS
\ v VALVE £\ V OF COMBUSTION ONLY
(OPEN) T
QUICK r-L|
CONNECT HI
(CLOSED)
VACUUM**
PUMP
H20
TRAP
MERCURY
MANOMETER
INTERMEDIATE
COLLECTION
VESSEL
"FOR EVACUATING COLLECTION
VESSELS AND SAMPLE TANKS
(OPTIONAL)
Figure 8. Condensate recovery and conditioning apparatus, carbon dioxide purge.
V-434
-------
Federal Register / Vol. 45, No. 194 / Friday, October 3,1980 / Rules and Regulations
FLOW
CONTROL
1 VALVES
SAMPLE
ONOENSATE
TRAP
' ^ VAIVES' I
i -U
OXIDATION
CATALYST
j HEATED
' CHAMBER
(OPEN)y
^ t^7 ^
NOIR
ANALYZER*
^— {) REGULATJNG X~D * FOR MONITORING PROGRESS
A VALVE C3 V OF COMBUSTION ONLY
(OPEN) 1
QUICK r^i
CONNECT In'
(CLOSED)
VACUUM*
PUMP
\/
H20
TRAP
MERCURY
MANOMETER
INTERMEDIATE
COLLECTION
VESSEL
••FOR EVACUATING COLLECTION
VESSELS AND SAMPLE TANKS
(OPTIONAL)
Figure 9. Condensate recovery and conditioning apparatus, collection of trap organic*.
V-435
-------
18
Federal Register / Vol. 45. No. 196 / Tuesday. October 7,1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[AD-FRL 1563-3]
Standards of Performance for New
Stationary Sources; Glass
Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: Standards of performance for
glass manufacturing plants were
proposed in the Federal Register on June
15, 1979 (44 FR 34840). This action
finalizes standards of performance for
glass manufacturing plants. These
standards implement the Clean Air Act
and are based on the Administrator's
determination that glass manufacturing
plants cause, or contribute significantly
to, air pollution which may reasonably
be anticipated to endanger public health
or welfare. The intended effect of these
standards is to require all new,
modified, and reconstructed glass
manufacturing plants to use the best
technological system of adequately
demonstrated continuous emission
reduction, taking into consideration
costs, nonair quality health and
en":.ronmental impacts, and energy
requirements.
EFFECTIVE DATE: October 7, 1980.
Under Section 307(b)(l) of the Clean Air
Act, judicial review of these standards
of performance is available only by the
filing of a petition for review in the U.S.
Court of Appeals for the District of
Columbia Circuit within 60 days of
today's publication of this rule. Under
Section 307{b)(2) of the Clean Air Act,
the requirements that are the subject of
today's notice may not be challenged
later in civil or criminal proceedings
brought by EPA to enforce these
requirements.
ADDRESSES: Background Information
Document. The background information
document for the promulgated standards
is contained in the docket and 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 Class
Manufacturing Plants—Background
Information: Promulgated Standards of
Performance EPA-450/3-79-005b).
Docket. Docket No. OAQPS-79-2,
containing all supporting information
used by EPA in developing the
standards, 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,
West Tower Lobby, Gallery 1,
Waterside Mall, 401 M Street SW.,
Washington, D.C. 20460. A reasonable
fee may be charged for copying.
FOR FURTHER INFORMATION CONTACT:
Ms. Susan Wyatt, Standards
Development Branch (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone (919) 541-5477.
SUPPLEMENTARY INFORMATION:
Summary of Standards
Standards of performance for glass
maunufacturing plants were proposed in
the Federal Register (44 FR 34840] on
June 15,1979. The promulgated
standards deal collectively with four
categories of glass manufacturing plants:
container glass, pressed and blown
glass, wool fiberglass, and flat glass.
The promulgated standards apply to
glass melting furnaces within glass
manufacturing plants with three
exceptions: hand glass melting furnaces,
glass melting furnaces designed to
produce 4.55 megagrams or less of glass
per day, and all-electric glass melting
furnaces. No existing glass melting
furnaces are covered unless they
undergo modification or reconstruction
as defined by the Clean Air Act and the
General Provisions of 40 CFR Part 60.
Glass manufacturing plants that change
fuel from natural gas to fuel oil are
exempt from consideration as a
modification. Rebricking of glass melting
furnaces is exempt from consideration
as a reconstruction.
The promulgated standards of
performance, as they apply to gas-fired
glass melting furnaces for each of the
glass manufacturing categories are as
follows:
Promulgated Standards of Performance for
Gas-Fired Glass Melting Furnaces
[g of particulate/kg of glass produced]
Glass category
Standard
Container glass
Pressed and blown glass:
Borostticate
Soda-lime and lead
Other-man borosrlcate. soda-lime, and lead
Wool fiberglass ,
Flat glass
0.1
0.5
0.1
0.25
0.2S
0.225
These standards are based on data
that show the ability of each category of
glass manufacturing furnace to achieve
such a level of control through the use of
systems of continuous emission
reduction. In selecting, these standards,
costs, nonair quality health and
environmental impacts, and energy
requirements were considered.
An increment 30 percent greater than
the promulgated emission limits for
natural gas-fired furnaces is allowed for
fuel-oil fired glass melting furnaces and
a proportionate increment is allowed for
glass melting furnaces simultaneously
firing natural gas and fuel oil. Both
allowances apply to glass melting
furnaces producing other than flat glass.
The flat glass standard is based solely
on emission tests conducted on a liquid-
fired furnace while the other standards
are based on emission tests conducted
almost exclusively on gaseous-fired
furnaces.
Summary of Environmental, Energy, and
Economic Impacts
Environmental Impacts
The promulgated standards will
reduce projected 1984 emissions from
new uncontrolled glass melting furnaces
from about 4,890 megagrams per year
(Mg/yr) to about 570
Mg/yr. This is a reduction of about 89
percent of the uncontrolled emissions.
Meeting a typical State Implementation
Plan (SIP), however, will reduce
emissions from new uncontrolled
furnaces by about 3,150 Mg/yr. The
promulgated standards will exceed the
reduction achieved under a typical SIP
by about 1,200 Mg/yr.
The promulgated standards are based
'on the use of electrostatic precipitators
(ESPs) and fabric filters, which are dry
control techniques; therefore, no water
discharge will be generated and there
will b« no adverse water pollution
impact
The solid waste impact of the
promulgated standards will be minimal.
Less than 2 Mg of particulate will be
collected for every 1,000 Mg of glass
produced. In some cases, this material
can be recycled, or it can be landfilled if
recycling proves 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 is not expected to have
an adverse environmental impact. The
additional solid material collected under
the promulgated standards will not
differ chemically from the material
collected under a typical SIP regulation;
therefore, any adverse impact from
landfilling will be minimal. However,
recycling of the solids has a distinctly
positive environmental impact.
Energy Impacts
For model plants in the glass
manufacturing industry, the energy
consumption that will result from the
promulgated standards including that
required by a typical SIP regulation
ranges from about 0.1 to 2 percent of the
energy consumed to produce glass. The
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energy required in excess of that
required by a typical SIP regulation to
control all new glaso melting furnaces
constructed_by 1634 to the level of the
promulgated standards will be about 9
gigajoules per year in the fifth year. This
energy requirement is not considered
significant in comparison to the energy
used by the new glass melting furnaces.
Thus, the promulgated standards will
have a minimal impact on national
energy consumption.
Economic Impacts
Compliance with the standards will
result in annualized costs in the glass
manufacturing industry of about $8.5
million by 1984. Cumulative capital costs
of complying with the promulgated
standards for the glaso manufacturing
industry as a whole will amount to
about S28 million by 1884. The percent
price increase for products from new
plants necessary to offset costs of
compliance with the promulgated
standards will range from about 0.3
percent in the wool fiberglass category
to about 1.0 percent in the container
glass category. Industry-wide, the
average price increase for products from
new plants will amount to about 0.7
percent. These economic impacts are
reasonable.
On July 20,1977, a notice of intent to
develop a rulemaking pertaining to glass
manufacturing plants was published in
the Federal Register (42 FR 37213). Prior
to proposal of the standards, interested
parties were advised by public notice in
the Fedsnd Register (43 FR 11259. March
17,1978) of a meeting of the National Air
Pollution Control Techniques Advisory
Committee to discuss the glass
manufacturing plant standards.
recommended for proposal. This meeting
occurred on April 5-8,1978. The meeting
was open to the public and each
attendee was given an opportunity to
comment on the standards
recommended for proposal. On June 14,
1979, the Administrator listed glass
manufacturing plants (44 FR 34193)
among the categories of stationary
sources, which in the Administrator's
judgment, cause or contribute
significantly to air pollution, which may
reasonably bs anticipated to endanger
public health or welfare. The proposed
standards wera published in the Federal
Registoi? on June 19,1979 (44 FR 34840).
Public comments were solicited at that
time and, when requested, copies of the
Background Information Document
(BID), Volume I were distributed to
interested parties. Interested parties
were advised by public notice in the
Federal Register of a public hearing to
invite comments on the proposed
standards. The public hearing was open
to the public and each attendee was
given an opportunity to comment on the
proposed standards. The public
comment period was originally
scheduled to continue from June 15 to
August 14,1979, but was extended (44
FR 47778) to September 14,1979,
pursuant to comments made at the
public hearing that delays in receiving
copies of the Background Information
Document, Volume I had been
experienced.
Thirty-three comment letters were
received and eleven interested parties
testified-at the public hearing concerning
issues relative to the proposed
standards of performance for glass
manufacturing plants. These comments
have been carefully considered and,
where determined to be appropriate by
the Administrator, changes have been
made in the standards that were
proposed.
Significant Comments and Changes to
• — - ~ ~n
dls
Comments on the proposed standards
were received from glass manufacturers,
an ad hoc industry group, trade
associations. State and Federal
government offices, and an
environmental group. A detailed
discussion of these comments can be
found in the Background Information
Document, Volume II. The summary of
comments and responses in the
Background Information Document,
Volume n, serves as the basis for the
revisions which have been made to the
standards between proposal and
promulgation. The comments discussed
in this preamble are the major
comments and are summarily
addressed. For complete responses to all
submitted comments, refer to the
Background Information Document,
Volume II. The major comments have
been combined into the following areas:
Need for standards; emission control
technology, modification, reconstruction,
and other considerations; general issues;
environmental impacts; economic
impacts; energy impacts; test methods
and monitoring; and clarifications.
Need for Standards
Several commenters questioned the
need for standards of performance for
the glass manufacturing industry.
Standards of performance are
promulgated under Section 111 of the
Clean Air Act. Section lll(b)(l)(A)
requires that the Administrator establish
standards of performance for categories
of new, modified, or reconstructed
stationary sources which, in the
Administrator's judgment, cause or
contribute significantly to air pollution,
which may reasonably be anticipated to
endanger public health or welfare. The
purpose of standards of performance is
to prevent new air pollution problems
from developing by requiring the
application of the best technological
system of continuous emission
reduction, considering impacts, which
the Administrator determines to be
adequately demonstrated. The 1977
amendments to the Clean Air Act added
the words, "in the Administrator's
judgment," and the words, "may
reasonably be anticipated," to the
statutory test. The legislative history for
these changes stresses two points: (1)
the Act is preventative, and regulatory
action should be taken to prevent harm
before it occurs; and (2) standards
should consider the cumulative impact
of sources and not just the risk from a
single class of sources.
The 1977 amendments to the Clean
Air Act also required that the
Administrator promulgate a priority list
of source categories for which standards
of performance are to be promulgated.
The priority list, 40 CFR 60.16, was
proposed in the Federal Register on
August 31,1978 (43 FR 38872). Glass
manufacturing was ranked thirty-eighth
on that list. On June 14,1979, the
Administrator listed glass
manufacturing (44 FR 34193) among the
categories of stationary sources which,
in the Administrator's judgment, causes
or contributes significantly to air
pollution, which may be reasonably
anticipated to endanger public health or
welfare. Even though glass
manufacturing had been included on the
proposed priority list, it was listed
among the significant stationary sources
because the priority list had not been
finalized. This was done so that the
development of these standards could
proceed without having to wait for the
priority list to be finalized.
Commenters questioned basing the
decision to add glass manufacturing to
the list of significant source categories
on the proposed priority list. The
decision to add glass manufacturing to
the list of significant source categories
was not based on the proposed priority
list. The fact that glass manufacturing
was a source category that was on the
proposed priority list only added weight
to the Administrator's decision to add
glass manufacturing to the list of
significant source categories. The
decision to add glass manufacturing to
the list of significant source categories
was based principally on the judgment
that glass manufacturing plants are
significant contributors of particulate
matter emissions. In addition, factors
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Federal Register / Vol. 45, No. 196 / Tuesday, October 7, 1980 / Rules and Regulations
similar to those considered in
developing the priority list ranking were
considered in adding glass
manufacturing to the list of significant
source categories. These factors
included the mobility and competitive
nature of the industry and the extent to
which such pollutant may reasonably be
anticipated to endanger public health or
welfare. Commenters also questioned
these factors.
In adding glass manufacturing to the
list of stationary source categories, the
Administrator explained that new glass
manufacturing operations could be
located in States which have SIP
particulate regulations less restrictive
than SIP regulations of the State of New
Jersey. Commenters questioned the glass
manufacturing industry's ability to
locate its plants in order to avoid
stringent SIP regulations. Industry
Commenters explained that raw
material, customer, and financial
considerations were much more
important in determining plant location
than the stringency of a particular
State's environmental regulatory
scheme.
All of these factors need to be
considered in deciding where to
construct a new facility. What was
meant to be emphasized was the
relative flexibility that a glass
manufacturer has in locating a new
plant. Manufacturers who have the
freedom to locate a new plant with only
minor restrictions caused by raw
material suppliers and product market
are considered mobile. Glass
manufacturing plants are not restricted
to locating in a particular region of the
country as would a coal mine or a stone
quarry. For this industry, raw materials
and glass products can be and are
shipped across the country.
The glass industry, in its ability to be
relatively mobile, could readily relocate
in States with less stringent standards
or compliance deadlines. This has in
fact occurred in at least one State
where, at a public hearing, a glass
industry representative specifically
suggested that his company would
relocate and construct new plants in
another State to avoid having to "spend
multi-million dollars for air pollution
control equipment." This was shown to
be somewhat of a trend by the State
involved when it was found that in the
past five years in excess of 10 percent of
the State's glass furnaces have been
shutdown and no new ones constructed
(docket entry OAQPS-77/1-IV-A-2).
This is especially significant when one
looks at the glass industry's nationwide
production increases in the past several
years. One purpose of these standards is
to avoid situations in which industries
could be lured to one State from another
just by virtue of there being a less
stringent regulation in effect.
Commenters suggested that
particulate emissions from glass
manufacturing plants do not contribute
significantly to air pollution. These
Commenters explained that the
estimated 1,473 Mg/yr of particulate
emissions from glass manufacturing
plants presented in the preamble for the
proposed standards is small in
comparison to the total quantity of
nationwide particulate emissions.
Almost any industry by itself accounts
for a small portion of the Nation's total
emission. The 1,473 Mg/yr estimate of
emissions reduced by the proposed
standards was the quantity attributable
to the proposed standards and neglected
the emission reduction attributable to
SIP regulations. The total emissions
from new glass manufacturing plants
reduced by controlling the particulates
•from these plants to the promulgated
standards, including the emissions
reduced by SIP regulation, is about 4,363
Mg/yr. The annual particulate emissions
for the glass manufacturing industry in
1976 are estimated to be approximately
18,000 Mg. A comparison of the 1,473
Mg/yr estimate and the 4,363 Mg/yr
estimate to the total quantity of
nationwide particulate emissions is
inappropriate. The suggested
comparison is between emission
reduction estimates and emission rate
estimates. The reduction in emission
rate for the promulgated standards
represents approximately an 89 percent
reduction in emission rate and is not
atypical of emission reductions
associated with other standards of
performance established under Section
111.
The 1,473 Mg/yr estimate of emissions
was not the only factor upon which it
was decided to develop these standards.
Other factors such as the areas in which
the affected plants are to be located and
the effects these plants will pose to the
public health and welfare were taken
into account. With regard to the public's
health and welfare, the submicron size
of most glass furnace-generated
particulates, among other factors, is
particularly important. Of special
concern is the capability of these
submicron particles to by-pass the
body's respiratory filters and penetrate
deeply into the lungs. In excess of 30
percent of the particles less than 1
micrometer in size that penetrate the
pulmonary system are deposited there.
These particulates also have fairly long
lives in the atmosphere and can absorb
toxic gases, thus leading to potentially
severe synergistic effects when inhaled.
The decision to regulate these emissions!
is based on interrelated factors that
when considered collectively led the
Administrator to list glass
manufacturing plants as a significant
source of air pollution.
Commenters suggested that
particulate emissions from glass .
manufacturing plants do not contribute
significantly to air pollution because
Class I Prevention of Significant
Deterioration (PSD) increments would
not be exceeded. The fact that emissions
from a single plant would be less than
the Class I PSD increment does not
show that the category should not be
listed. First, the test is whether the
category, not an individual plant,
contributes significantly. Second,
although a single plant might not exceed
a Class I increment, it could contribute
significantly to the total level of
emissions in excess of the increment.
Most importantly, the major purpose of
Section 111 is to "prevent new air
pollution problems" [National Asphalt
Pavement Association v. Train, 539 F.2d
775, 783, (D.C. Circ., 1976)]. That is,
standards established under Section 111
should prevent PSD increments from
being threatened by requiring control of
new sources. It is therefore, not
necessary to show that individual
sources in the category would violate an
increment.
Based on the judgment that
particulate air pollutants from glass
melting furnaces contribute significantly
to air pollution, which may be -
reasonably anticipated to endanger
public health or welfare, the
Administrator listed glass
manufacturing plants as a category of
sources for control. Comments, as
discussed above, have not led the
Administrator to change this decision.
Emission Control Technology
During the development of the
proposed standards of performance for
the glass manufacturing industry,
information was received concerning the
use of process modifications as a
method of reducing particulate emission
from the glass melting furnace.
Commenters stated that during the
development of the BID, Volume I, EPA
did not perform a thorough investigation
into the use of process modifications as
a continuous emission reduction
technique. These commenters were also
of the opinion that process
modifications are an effective method of
emission control, and, therefore, should
be considered as an alternative to add-
on control devices which are the basis
for these standards of performance.
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The discussion of process
modifications in the BID, Volume I,
along with the materials used to develop
that section indicates that the use of
process modifications in the glass
manufacturing industry was taken into
consideration during the development of
the proposed standards of performance.
From the information received, it was
apparent that process modifications are
used rather extensively throughout the
glass manufacturing industry. The types
of process changes employed by
industry, along with the possible
benefits and potential problems
associated with these techniques, were
presented in the BID. It is clearly
evident that many issues concerning
these methods were left unresolved.
However, the lack of resolution of
these issues was not due to EPA's
failure to investigate this area of
emission control but rather due to the
fact that the information that was
available indicated that emission
reduction by process modifications is
uncertain with respect to the
effectiveness of the techniques. It is
because of this uncertainty that the
Administrator decided to base these
standards of performance on add-on
control devices of known and proven
effectiveness.
Since the proposal of the standards of
performance for the glass manufacturing
industry, additional information has
been made available concerning the use
of process modifications. This
information has indicated that progress
is being made by several glass
manufacturers in reducing emissions by
the use of certain process modification
techniques. However, these comments
have not resolved the uncertainty in
considering process modification.
Process modifications constitute a
variety of techniques that some glass
manufacturers use to increase
production, to improve energy utilization
and, in some cases, to reduce particulate
emissions. However, the Administrator
has found that particulate emission
reduction by process modifications is
uncertain; data indicate a range from no
emission reduction to about 50 percent
emission reduction and, in certain cases,
greater than 50 percent emission
reduction. In addition, the consequences
of using process modifications are not
fully understood. For example, process
modifications can affect the quality of
the glass product and may reduce the
operating life of the glass melting
furnace. Process modifications may be
applied intermittently and, therefore,
may result in non-continuous emission
reduction. Thus, the Administrator has
concluded that process modifications, as
presently used by glass manufacturers,
are not adequately demonstrated means
of continuous emission reduction. The
recommended standards would not
preclude the use of process
modifications by those glass
manufacturers who develop this
capability.
It should be pointed out that Section
lll(j) of the Clean Air Act provides a
means by which an industry source
subject to new source performance
standards can request the Administrator
for one or more waivers from the
requirements of Section 111 with respect
to any pollutant to encourage the use of
an innovative technological system of
continuous emission reduction. The
purpose of this Section of the Act is to
allow and encourage industry to develop
new means of control, such as process
modifications, subject to certain
restrictions. Until such time that process
modifications can be shown to be an
effective means of continuous emission
reduction able to achieve the limitations
imposed by these standards, industry
has at its disposal on an individual
basis, and subject to the terms of
Section lll(j), a means for developing
and perfecting these methods of control.
A commenter suggested that EPA, in
promulgating the standards as proposed,
will not allow industry to choose its
method of compliance from a wide
range of methods available to it. The
proposed standards of performance
were based on the criteria set forth in
Section 111 of the Clean Air Act for the
best continuous method of emission
reduction, considering impacts, which
have been adequately demonstrated. -
The promulgated standards are based
on emission limitations that are
achievable and are not meant to exclude
any one method of control. Many forms
of control have been investigated in the
development of these standards.
However, not all forms of control are
capable of achieving the degree of
control necessary to comply with the
standards. This is not to say that
methods of control, not presently able to
meet the standards, cannot be adapted
to effectively control glass plant
particulate emissions to the imposed
limits.
Commenters suggested that a linearly
related production rate mass standard is
unfair to those furnaces operating at low
production rates due to such things as
non-production incidents and holidays.
A related comment raised by several
commenters suggested that the proposed
standards would prove to be unfair to
those furnaces operating at other than
"normal" levels of production.
Specifically of concern to these
comraenters was the inability of glass
furnaces to achieve a zero emission rate
at times when the production rate
approaches zero. It was emphasized by
the commenters that even when the
production rate of a glass melting
furnace is zero there would be
associated emissions due to the
maintenance of the molten glass at the
proper temperature.
In an attempt to resolve this issue it
was suggested by a commenter that a
lowest level emission limit be set at
either 227 g/hr or 454 g/hr. This
commenter explained that, based on the
industry-wide estimation that emission
levels at zero production rate are
roughly 20 percent of those at normal
production rates, a lowest level
emission limit would have to be
incorporated in the standards in order
for furnaces operating at the lower end
of their operational ranges to be able to
comply with the standards. Due to the
concerns expressed by these
commenters, the method for the
calculation of the furnace emission rate
was changed in order to correct for the
fact that emissions are generated at zero
production rate.
Correction factors were developed
after reviewing comments on this issue.
Only one commenter offered a solution
to this issue. This commenter suggested
that a lowest level emission limit be set
at either 227 g/hr or 454 g/hr. In
comparing these figures with the
controlled emission rates using the 20
percent figure it was determined that a
correction of 227 g/hr should be applied
to the container, pressed and blown
(soda-lime and lead], and pressed and
blown (other-than borosilicate, soda-
lime, and lead) glass categories and
subcategories; and an adjustment of 454
g/hr should be applied to the pressed
and blown (borosilicate], wool
fiberglass, and flat glass categories and
subcategory.
The mechanism for providing the
correction factors is to subtract this
predetermined amount (g/hr] from the
particulate emission rate (g/hr]
determined in the procedure using EPA's
Method 5. That amount is consequently
applied to the rate of glass production
(kg/hr) which is ultimately used to
determine the furnace emission rate (g/
kg]. By using these correction factors,
the calculated furnace emission rate will
approach zero as the production rate
approaches zero, thereby making the
standards slightly easier to achieve.
Although the standards will be
slightly easier to achieve, the impacts of
the standards will not be substantially
affected. This correction factor should
not lead to the design of control devices
any less efficient than those considered
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appropriately designed to achieve the
standards. This is due to the fact that as
the production rate increases from zero,
the particulate emission increases and
outweighs the zero production rate
correction factors. Thus, emission
reduction and cost impacts will not be
substantially changed.
Several commenters also suggested
that there be more specific categories
provided in the standards so as to more
accurately reflect the industry
production categories. It was felt that
the pollutant contributions and the
ability to control the emissions from the
melting of all the different types of glass
could not be adequately represented by
only four categories. In considering this
comment, it was decided to retain the
division of the glass manufacturing
industry into four major categories;
however, one of the categories (pressed
and blown glass) was changed. Due to a
reanalysis of source test results that
substantiate industry's claims of
uniqueness of the pressed and blown
category, it was decided to divide this
category into three subcategories:
borosilicate; soda-lime and lead; and
other-than borosilicate, soda-lime, and
lead rather than the two proposed
subcategories: soda-lime and other-than
soda-lime.
The decision to regulate the glass
manufacturing industry as four
categories of production was made
based on technological information—in
particular, the potential for particulate
emission control, as well as the desire
for regulatory simplification, as
mandated by Executive Order 12044. In
assessing the entire glass manufacturing
industry it was found that the affected
facility, the glass melting furnace, varied
technologically in principally four areas
of production (container glass, pressed
and blown glass, fiberglass, and flat
glass). Therefore, four readily
identifiable categories were selected
that were unique based on technological
information and did not complicate the
regulation. In the process of selecting
the major categories of glass production
it was found that the pressed and blown
glass category had within itself areas of
production that were individually
unique as to their potential for
particulate emission control. However,
such individually unique areas were not
found for the other categories. As a
result, only the pressed and blown
category was further divided into three
subcategories: borosilicate; soda-lime
and lead; and other-than borosilicate,
soda-lime, and lead.
The decision to subdivide the pressed
and blown glass category into three
subcategories was based on test data
and information gathered throughout the
development of these standards. In
studying the data and information it was
found that emissions from the melting of
borosilicate-type glass were uniformly
the most difficult to control, while
emissions from the melting of soda-lime
and lead glass could be controlled to a
greater extent. With these two extremes
in potential for particulate emission
control, the balance of the pressed and
blown glass formulations (othern-than
borosilicate, soda-lime, and lead) were
found to be controlled, at least, at a
relatively median level of control.
It was not practically possible to test
glass manufacturing plants melting all
types of batch formulations. The
Standard Industrial Classification
Manual lists in excess of 80 final glass
products. Each of these glass products is
liable to have several glass formulations
depending upon the final use of the
product, the color of the final product, or
the manufacturer of the product. Despite
the numerous formulations utilized
throughout the industry it was found
after a review of information received
that the four major categories and the
three subcategories for pressed and
blown glass selected for these standards
will adequately represent the emission
reduction levels achievable for the
melting of all glass formulations. There
is ample reason to believe that any glass
melting furnace will be able to comply
with the appropriate regulatory
limitation. The standards represent
levels of control achievable by glass
manufacturers.
In response to comments submitted by
industry, the Administrator has
reevaluated all of the proposed
standards of performance. In performing
these analyses, it was determined that
some of the standards required
adjustment to truly reflect the industry's
ability to achieve the standards.
The promulgated container glass
category emission limitation remains the
same as that proposed (0.1 g/kg). The
pressed and blown category, as
previously discussed, was split into
three subcategories, rather than the two
subcategories that were in the proposed
standards. The proposed numerical
limitations (0.1 g/kg for soda-lime and
0.25 g/kg for other-than soda-lime) have
been changed to reflect the ability of the
particulate emissions from this category
to be controlled. Borosilicate glass
furnaces, which were included in the
proposed other-than soda-lime
subcategory have a standard applicable
solely to borosilicate glass furnaces (0.5
g/kg); soda-lime glass furnaces have the
same limitation (0.1 g/kg); lead glass
furnaces, which were included in the
proposed other-than soda-lime
subcategory, are required to comply
with the proposed soda-lime limitation
(0.1 g/kg); the balance of the glass
melting furnaces that produce pressed
and blown glass are grouped in the
other-than borosilicate, soda-lime, and
lead glass subcategory and are required
to meet a standard of 0.25 g/kg. The
proposed wool fiberglass category
emission limitation was changed from
0.2 g/kg to a promulgated limitation of
0.25 g/kg. The proposed flat glass
category emission limitation was
changed from 0.15 g/kg to a promulgated
limitation of 0.225 g/kg.
One commenter suggested that the
numerical emission limits imposed by
the standards of performance invite
borderline compliance status in all of
the four major categories of glass
manufacturing plants. This commenter's
opinion was that this sort of practice,
not providing a sufficient regulatory
cushion to operate within, does not
follow in the intended spirit of the
development of these standards.
These standards of performance are
based on test results conducted in
accordance with EPA Method 5 and the
Los Angles Air Pollution Control District
(LAAPCD) method, as discussed in the
preamble to the proposed standards.
Upon reviewing old and recently
submitted data, some of the standards
were changed to more accurately reflect
the emission control abilities of the four
categories of glass products. The
promulgated standards reflect for each
individual category of glass
manufacturing plant the degree of .
continuous emission reduction, which
the Administrator had determined to be
adequately demonstrated taking into
consideration the costs, and nonair
quality health and environmental, and
energy impacts associated with their
attainment. The standards are based on
emission data and the exercise of good
engineering judgment and do not invite
borderline compliance, as suggested by
the commente?.
Several commenters complained that
the standards applicable to their
industry were incorrectly based on
technology transfer. These commenters
suggested that technical differences in
the manufacture of their types of glass
make it more difficult to control their
emissions as opposed to the generalized
categories investigated in the
Background Information Document,
Volume I.
The differences suggested by the
commenters would only be important if
the achievability of the standards were
in question. However, data collected
from plants in all of the categories
clearly demonstrate the achievability of
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the standards. After reviewing those
data and considering the factors
relevant to achieving compliance, the
Administrator has concluded that the
standards are achievable for all types of
glass manufacturing plants. This is not
to say that the use of technology
transfer is not justified in certain
circumstances. On the contrary,
technology transfer as a means of
setting standards is an appropriate
method upon which to base limitations
such as these.
The standards were generally based
on tests conducted on glass
manufacturing plants firing natural gas.
In order to take into account the
difference in emission contribution of
the two fuels used in glass melting
(natural gas and fuel oil) an additional
increment has been allowed for those
glass melting furnaces firing fuel oil. As
a result of comments received and an
analysis of submitted data the
allowance for fuel oil firing was
increased from the proposed amount of
IS percent to 30 percent The increment
will be available to all glass melting
furnaces, except flat glass melting
furnaces. The flat glass standard was
based solely on tests conducted at an
oil-fired flat glass plant.
Modification, Reconstruction, and Other
Considerations
The major comments submitted for
this area of consideration dealt with the
rebricking, fuel conversion, all-electric
melter, and small glass furnace
exemptions from tide limitations
provided for in the proposed standards.
Almost all of the comments received
supported the granting of these
exemptions as being vital to the future
development of the glass manufacturing
industry. Based on the analyses
performed in response to comments
received relative to these exemptions, it
was decided to retain them and add one
more. The rebricking exemption was not
questioned due to the regularity and
necessity of this operation in this
industry.
The all-electric melter exemption was
retained despite comments suggesting
that the secondary participate emissions
associated with the generation of the
additional electricity would more than
negate the benefits of the reduced
particulate emissions from these
furnaces.
It should be noted that this estimate
was based on the mistaken assumption
that all affected glass melting furnaces
will utilize electric power as their sole
source of heat. It is generally known
throughout the industry that this will not
be the case due to the inherent
constraints realized by the use of
electric power. Presently, only a fraction
of the container, pressed and blown, and
wool fiberglass industries can employ
all-electric furnaces.
These secondary particulate
emissions were addressed in the
Background Information Document,
Volume I, in Chapter 7. On page 7-19 of
that document, the annual secondary
impact associated with these standards
was estimated to range from
approximately 9,300 kg to 25,000 kg. The
commenter estimated the secondary
impact to be approximately 50,000 tons
of particulate emissions per year.
Using EPA's AP-42 Document for
uncontrolled coal-fired utility boilers as
a basis for calculating secondary
particulate emissions, the emissions
from new all-electric melters result in an
emission reduction of approximately 37
percent, compared to an uncontrolled
glass melting furnace. However, as of
1971 new coal-fired utility boilers have
had to comply with a new source
performance standard. Using that
standard as a basis for calculating
secondary impacts, an 82 percent
emission reduction will be realized.
Additionally, using the latest standard
to be promulgated for coal-fired power
plants (1979) as a basis for calculating
secondary impacts, an 87 percent
reduction in emissions will be realized.
Thus, the use of all-electric melters
rather than conventional glass melting
furnaces results, generally, in an
emission reduction. Based on an annual
estimated impact and the benefits
expected to accrue from the use of all-
electric melters, the all-electric melter
exemption was retained.
The only exemption to be modified
was the proposed provision exempting
small glass melting furnaces, i.e.,
designed to produce a maximum of 1.82
megagrams of glass per day, from
compliance with the standards. This
exemption was expanded to include
glass melting furnaces designed to
produce up to 4.55 megagrams of glass
per day. It was found that this size
furnace more nearly represents the
production limit beyond which
continuous melting furnaces are
generally operated.
This exemption was limited to the 4.55
megagrams per day production rate
despite a comment received suggesting
an exemption for hand glass melting
furnaces as large as 13.65 megagrams
per day. This decision was based on an
analysis in the initial development of
these standards including glass melting
furnaces with design production rates
ranging from 13.65 to 18.2 megagrams
per day. It was concluded, as a result of
the initial economic analysis, that
furnaces with design production rates
within the aforementioned range as well
as above it are continuous melting
furnaces capable technologically and
economically of meeting the limitations
presented in the standards.
All hand glass melting furnaces,
however, were exempted from
compliance with the standards. This
decision was based on a further
analysis of the industry, as suggested by
commenters, who claimed that the
industry would not survive the cost of
this regulation. As indicated in the
preamble to the proposed standards.
these types of furnaces would not likely
survive the associated economic
impacts. Thus, hand glass melting
furnaces have been exempted from
compliance with these standards of
performance.
General Issues
Several commenters felt that the State
Implementation Plan (SIP) used as a
baseline from which to compare the
impacts of the proposed standards was
not typical for the industry and was
arbitrarily selected. It was industry's
position that by using the SIP selected,
the projected environmental, energy,
and economic impacts of the proposed
standards were not accurately
represented.
The selection of the baseline was
based on several factors. Not only was
the overall restrictiveness of the State
standards compared, but also the
relative share of the industry in each of
the.States was considered. After
performing an analysis prior to the
proposal of these standards, it was
concluded that the baseline used in the
development of the proposed standards
could be considered typical for the
industry. After reviewing comments on
this issue and the analysis performed,
the baseline is still considered typical
for this industry.
There were also suggestions that the
standards be concentration standards
rather than mass standards. These
suggestions were made based on the
smaller amount of data that would be
required to determine a furnace's
compliance with concentration
standards as opposed to mass
standards.
Concentration standards would
penalize energy-efficient furnaces
because 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
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content in the gas stream, this penalizing
effect of the concentration standard
would not be overcome.
Therefore, even though concentration
standards involve lower resource
requirements for testing than mass
standards, mass standards are more
suitable for the regulation of particulate
emissions from glass melting furnaces
because of their flexibility to
accommodate process improvements
and their direct relationship to the
quantity of particulate emitted to the
atmosphere. These advantages outweigh
the drawbacks associated with creating
and manipulating a data base.
Consequently, mass standards are
selected as the format for expressing
standards of performance for glass
melting furnaces.
Various commenters stated that the
uncontrolled emission rates used to
compare the emission reductions
attributable to the standards for
container glass, flat glass, and wool
fiberglass were inaccurate. It was
suggested that the uncontrolled emission
rate for container glass should be
changed from 1.25 g/kg to about 0.5 g/
kg; the uncontrolled emission rate for
flat glass should be changed from 1.5 g/
kg to about 0.5 g/kg; and the
uncontrolled emission rate for wool
fiberglass should be changed from 5 g/
kg to from 11 to 15 g/kg.
An analysis of these comments and
additional test reports was made. It was
determined that the uncontrolled
emission rates for the container and flat
glass categories would be more
accurately represented by the rates 0.75
g/kg and 1.0 g/kg, respectively;
however, the uncontrolled emission rate
used for wool fiberglass category was
found to be representative. The impacts
of these changes are reflected in the
Environmental, Economic, and Energy
Impact sections of this preamble.
Environmental Impact
A few commenters questioned the
ability of the industry to effectively
recycle collected particulate and
product waste. The preamble to the
proposal stated that the particulate
dusts can generally be recycled, or they
can be landfilled if recycling proves to
be unattractive.
Depending on the category of glass
being produced, collected particulate
may be recycled as a raw material.
Some glasses, such as flat glass, require
that the batch formulation not contain
certain contaminants, but others are not
as critical as flat glass. These other
glasses are able to tolerate additional
elements, such as alumina, contained in
ihe furnaces' checkerworks, that are
introduced into the exhaust stream.
In developing the impacts of these
standards it was assumed that all
affected facilities will landfill their
collected particulate. However, this
environmental impact will not be
significant, whether the collected
particulate is landfilled or recycled.
Thus, the comment does not question
the impact of the standard.
Another issue raised questioned the
landfilling of the collected particulate. It
was suggested that the landfilling of
these particulates, particularly those
collected from the production of glass
where fluoride, boron, and lead are
present in the batch formulations, may
endanger the public health or welfare.
There is no indication that landfilling,
the commonly practiced method of solid
waste disposal in this industry, will
create such a problem. As landfill
operations are subject to state
regulation and possibly the Resource
Conservation and Recovery Act (42
U.S.C. §§ 6901. etseq.) and the
particulates collected as a result of the
promulgation of these standards do not
differ chemically from the material
collected under a typical SIP regulation,
there is minimal adverse impact on the
environment. Therefore, current
practices in landfilling are expected to
continue throughout the industry and the
waste impact of these standards is
considered to be minimal.
The Environmental Impact portion of
the Summary of Environmental, Energy,
and Economic Impacts section of this
preamble details the estimated impacts
resulting from^the promulgation of these .
standards.
Economic Impact
Several commenters were of the
opinion that the cost effectiveness of the
standards should prevent the standards
from being promulgated. Tjey
contended that standards should not be
based on add-on controls because the
cost-effectiveness is unreasonable and
the cost of removing the particulate
exceeds the benefits derived from its
removal.
The cost and benefit to public health
and welfare associated with the
reduction of air pollutant emissions is
difficult, if not impossible, to quantify. In
general, it is much easier to quantify the
cost of an emission reduction than to
quantify its benefit even though recent
studies have shown substantial benefits
from the reduction of air pollution. Thus,
the cost is usually the subject of much
discussion whereas the benefit is not
Given the inability to quantify both the
cost and the benefit, it is not possible to
determine whether the cost of control
exceeds the benefits associated with
control. Thus, the Administrator
considers it inappropriate to make a
regulatory decision based on a cost-
benefit analysis.
Cost-effectiveness calculations are
certainly useful in regulatory analyses
for choosing among competing
regulatory alternatives which achieve
the same level of control. On the other
hand, cost-effectiveness has too many
limitations to be used as the major
decision-making factor in setting
standards of performance under Section
111. It is not practical to identify a
numerical criterion which represents an
upper limit in cost per unit of pollutant
removed. Technological differences
among industries cause control costs for
any given pollutant to vary
considerably. In the case of glass
manufacturing, this is illustrated by the
fact that among several segments there
are considerable differences in cost per
unit pollutant removed. There are also
segments where little difference in costs
between SIPs and NSPS is evident,
while in other segments there are
distinct differences. Third, the economic
impact analysis employed in this
instance used the most costly controls to
determine worst-case effects. The other
less costly alternatives that achieve
equivalent control levels are also
available to the source. In reaching the
conclusion that the promulgated
standards would have no significant
economic impact on the glass
manufacturing industry, other factors
besides cost-effectiveness, were taken
into consideration. The costs associated
with the achievement of these
promulgated standards were considered
in the context of the cost structure of the
industry by means of an economic
analysis including, where necessary, a
discounted cash flow model. Upon
considering these factors, the economic
impacts of the proposed standards were
determined to be reasonable. These
impacts are still considered reasonable
for the promulgated standards of
performance.
The Economic Impact portion of the
Summary of Environmental, Energy, and
Economic Impacts section of this
preamble details the average percent
price increase, the cumulative capital
costs, and the annualized costs
associated with the promulgation of
these standards.
Commenters claimed that the cost of
particulate control should be totally
attributed to the standards of
performance. The cost of the standards
of performance are analyzed based on
the assumption that SIP regulations
require control where uncontrolled
emissions are greater than SIP allowed
emissions. Aa discussed in the General
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Issues section of this preamble, a SIP
typical of what glass manufacturing
plants have been required to comply
with was chosen. This SIP requires, in
most cases, emission reduction through
add-on control technology. It would be
unrealistic not to delete the cost that a
new plant would incur without the
establishment of standards of
performance. Therefore, it is realistic to
estimate the added or incremental cost
that would be incurred if a standard of
performance control level greater than
that required by SIP is established. In
addition, the emission reduction
attributed to the standards of
performance is that attributable to the
standards after SIP regulations have
been applied.
These commenters argued that
uncontrolled emission rates and SIP
regulations do not necessitate the use of
add-on controls as indicated in the
economic analysis. However, typical
glass melting furnaces, with the
exception of the 50 tons/day pressed
and blown glass furnaces, require add-
on controls. This conclusion is
supported by the fact that many glass
melting furnaces have been required,
and are still required, to install add-on
controls.
It was also suggested by a commenter
that the Administrator should not
analyze the effect of the standards on a
number of new plants constructed in a
specified time period by simply
estimating a rate of return expected
from a typical plant, under price and
•cost assumptions like the ones used in
the Background Information Document,
Volume I.
Regulatory impact analyses using
typical or model plant parameters are by
far the most prevalent techniques in all
economic impact studies involving new
source performance standards (and
other regulations) performed by or for
EPA, and are widely accepted by
various industrial segments previously
affected by EPA regulations. Model
plant analysis is the only technique
which reasonably addresses regulatory
impact on projected new plants which
typically face financial parameters,
including costs, which are different from
those faced by existing plants.
It was alleged by a commenter that
certain erroneous tax assumptions were
made in the calculation of the economic
impacts associated with these
standards. It was additionally alleged
that when corrected, these assumptions
resulted in figures showing that new
container glass plants subject to the
standards would not profitably repay
the original investment necessary to
build them.
In the development of the economic
impacts in the BID, Volume I, interest
was treated as a deduction, not a tax
credit. It was deducted as an expense in
computing profits in the discounted flow
analyses and then added back to cash
flow. The reason for the add-back is to
avoid the double counting of interest
since the discount rate includes a cost of
money and interest had been deducted
as an expense.
There was, however, a mistake in the
treatment of the investment tax credit. It
was incorrectly used in full in the first
year calculation of the discounted cash
flow. As a result, the net present value
of the tax credit is less than it could
have been if used fully in the first year.
The resultant correction of the
discounted cash flow amount is 0.1
percent. This 0.1 percent change in the
discounted cash flow would not affect
the conclusion that the economic impact
on a new container glass plant is
reasonable.
It was also commented that small
firms and competition from substitute
products had not been adequately taken
into consideration in developing these
standards.
Analyses were made of small glass
manufacturing plants. The size of these
plants were selected after reviewing
information submitted by the glass
manufacturing industry before the
proposal of these standards. These
analyses led the Administrator to
exempt small tanks, i.e., glass melting
furnaces designed to produce 4.55
megagrams of glass per day or less, from
the standards. Tanks designed to
produce 4.55 megagrams or less of glass
per day are non-continuous tanks, and
non-continuous tanks cannot afford the
cost of the standards.
Small firms generally operate small
plants that are typically deprived of
economies of scale that are available to
large plants. Therefore, an analysis of
small plants tends to state the costs
faced by the industry more
conservatively than would have been
the case had a larger-sized plant been
used in the analyses. Thus, small firms
were, in part, considered in the
development of these standards.
Competition from substitute products
was also taken into account. Part of the
economic analysis included a case with
an assumption that there would be no
price increase. In this case the product's
current competitive position relative to
substitute products would be unaffected
by the establishment of these standards.
The conclusion of this part of the
economic analysis indicated that the
cost of the standards would not
adversely affect the decision to
construct a new glass melting furnace
based on the minimum rate of return for
those categories with highly competitive
positions.
Energy Impact
One commenter suggested that one of
the benefits of implementing process
modifications is the conservation of
energy. Although this may be true in
certain instances, the Administrator has
determined that this technique is not
adequately demonstrated and cannot
presently be the basis upon which these
standards are promulgated. However,
the application of process modifications
should not conflict with the achievement
of the standards, thereby facilitating the
possible energy conservation benefits
attributable to process modifications.
A detailed energy analysis was
performed for inclusion in the
development of the BID, Volume 1. That
analysis took into account all of the
known adequately demonstrated
effective methods of continuous
emission control for the glass
manufacturing industry. The evaluation
yielded results that showed that the
energy consumption attributable to the
attainment of these standards of
performance is reasonable.
The Energy Impact portion of the
Summary of Environmental, Energy, and
Economic Impacts section of this
preamble details the percent of the new .
plants' total energy consumption that
will be attributable to both the SIPs and
the standards as well as the total energy
consumption beyond SIP that will be
attributable to the standards.
Although it may be true that for some
forms of process modifications the
energy required to melt the glass may
remain unchanged, other methods will
increase the energy consumption of a
glass manufacturing plant. This point
was made by several commenters
especially with respect to the use of
electric boosting.
Test Methods and Monitoring
Some commenters stated that EPA
Method 5, "Determination of Particulate
Emissions from Stationary Sources"
contains several sources of error when
used to sample emissions from soda-
lime glass melting furnaces. They stated
that misclassification of particulate and
gaseous species and inflated particulate
emission values are errors which can be
caused by the use of filter temperatures
below the sulfur trioxide (SO3) dew
point.
When particulate matter is filtered at
about 120°C, a significant amount of
sulfuric acid, if present, can condense on
the filter. The measurement of this
sulfuric acid by Method 5 does not
constitute an error in the method
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because sulfuric acid is normally
considered to be participate matter.
However, the variability of the sulfuric
acid content in the stack gas was not
considered in developing the standards.
As a result, the decision was made not
to include sulfuric acid as part of these
standards. Therefore, the method was
modified to allow operation of the filter
and the probe at up to 177°C, which is*
above the acid dew point and would
prevent sulfuric acid mist from being
collected by the filter.
Commenters remarked that sulfur
dioxide (SO,) and sulfur trioxide (SO:.)
can react with the alkali in the Method 5
filter and cause higher than true
particulate emission values.
An EPA report indicates that SO» and
SOa react with some glass fiber filters,
resulting in a significant weight gain in
certain applications. The report also
shows that this potential weight gain
can be avoided by choosing a source of
filter material demonstrated to be
nonreactive to SO0 and SOa. The degree
to which this reaction occurs is
apparently related to the final rinse step
of filter production which varies
according to the supplier. In addition,
this weight gain is not significant when
SO? or SO, is not present in the sampled
gas stream. Therefore, EPA is revising
Method 5 to require the use of
nonreactive filters in testing sources
whose gas streams contain SO2 or SO9.
Commenters also suggested that the
test method should allow a smaller
minimum sample volume. This minimum
sample requirement was modified to
allow the option of lower sampling
volumes, provided that a minimum of 50
milligrams of sample is collected. This
was done to allow shorter sampling
times for those plants which have higher
particulate concentrations to collect an
adequate amount of particulate to
weigh, but still requires plants with low
particulate concentration to sample long
enough to collect an adequate amount of
particulate to weigh.
Clarifications
Commenters expressed concern with
the possible confusion of whether an
entire glass manufacturing plant might
be considered to be an affected facility
if one of its glass melting furnace was to
be modified or reconstructed and,
thereby, subject itself as well as the
entire plant to these new source
performance standards. This confusion
was remedied by redrafting the
description of the affected facility.
Also suggested by a commenter was a
provision to specifically exclude the
float bath used in the flat glass category
from being regulated as a part of the
glass melting furnact (affected facility).
The float bath is considered to be part of
the forming process, not the melting
process, and is, therefore, not regulated
by these new source performance
standards. To remedy this possible area
of confusion, the regulation has been
rewritten, as suggested.
The term "glass manufacturing plant"
was removed from Section 60.291,
Definitions, of the regulation as it was
not needed.
The recipe definitions were also
changed where appropriate to describe
the specialized batch formulations found
in the pressed and blown glass category.
Detailed recipes for borosilicate, soda-
lime and lead, and other than
borosilicate, soda-lime, and lead were
included in Section 60.291, Definitions,
of the regulation.
Docket
The docket is an organized and
complete file of all the information
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 standards 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)].
Miscellaneous
The effective date of these standards
is the date of promulgation. Section
lll(b)(l)(B) of the Clean Air Act
provides that standards of performance
or revisions thereof become effective
upon promulgation and apply to affected
facilities, construction or modification of
which was commenced after the date of
proposal, June 15,1979, in this case.
As prescribed by Section 111 of the
Act, the promulgation of these standards
has been preceded by the
Administrator's determination that
emissions from glass manufacturing
plants contribute to the endangerment of
public health or welfare (36 FR 5931)
and by the publication of this
determination in the June 14,1979, issue
of the Federal Register (44 FR 34193). In
accordance with Section 117 of the Act.
publication of these promulgated
standards 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 Ssctioa 111 of tfis
Clean Air Act reflect
. . . application of tho beet technological
system of continuous) emission reduction
which (taking into consideration the cost of
achieving ouch emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated. [Section lll(aHl)]-
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 due to costs associated
with its use. Accordingly, these
standards of performance should not be
viewed as the ultimate in achievable
emissions 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 is in violation of the 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 other costs into
account. In no event may the application
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Federal Regist®? / Vol. 45, No. 196 / Tuesday October 7, 1980 / Rules and Regulations
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by an applicable
standard established pursuant to
Section 111 {or 112) of the Act.
In all events, SIPs 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 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 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,
improvements in emission control
technology, and reporting requirements.
The need for reporting requirements in
this regulation will be reviewed as
required under EPA's sunset policy for
reporting requirements in regulations.
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 this regulation and for
other regulatory alternatives. All
aspects of the assessment were
considered in the formulation of the
standards to insure that the standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the Background Information
Document, Volume I.
Dated: October 1,1980.
Douglas M. Costle,
Administrator.
40 CFR Part 60 is amended as follows:
1. By adding Subpart CC as follows:
Subpart CC—Standards of Performance for
Glass Manufacturing Plants
Sec.
60.290 Applicability and designation of
affected facility.
60.2!)] Definitions.
Sec.
60.292 Standards for particulnle matter.
60.293-60.295 [Reserved)
60.296 Test methods and procedures.
Authority: Sects. Ill and 301(a). Clean Air
Act, as amended. (42 U.S.C. 7411. 7601(a)j,
and additional authority as noted below.
Subpart CC=-Standard3 of
Performance
Plants
§ SO.aeO Applicability and designation of
offocted facility.
(a) Each glass melting furnace is an
affected facility to which the provisions
of this subpart apply.
(b) Any facility under paragraph (a) of
this section that commences
construction or modification after June
15,1979, is subject to the requirements
of this subpart.
(c) This subpart does not apply to
hand glass melting furnaces, glass
melting furnaces designed to produce
less than 4,550 kilograms of glass per
day and all-electric melters.
§ 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
of this part, unless otherwise required
by the contest.
"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 only.
"Borosilicate Recipe" means raw
material formulation of the following
approximately weight proportions: 72
percent silica; 7 percent nepheline
syenite; 13 percent anhydrous borax; 8
percent boric acid; and 0.1 percent
misellaneous materials.
"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 Standard Industrial
Classification 3221 (SIC 3221).
"Flat glass" means glass made of
soda-lime recipe and produced into
continuous flat sheets and other
products listed in SIC 3211.
"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. The
forming apparatuses, including the float
bath used in flat glass manufacturing.
are not considered part of the glass
melting furnace.
"Glass produced" means the weight of
the glass pulled from the glass molting
furnace.
"Hand glass melting furnace" moans ;i
glass melting furnace where the molten
glass is removed from the furnace by a
glassworker using a blowpipe or a
pontil.
"Lead recipe" means raw material
formulation of the following
approximate weight proportions: 56
percent silica; 8 percent potassium
carbonate; and 36 percent red lead.
"Pressed and blown glass" means
glass which is pressed, blown, or both.
including textile fiberglass,
noncontinuous flat glass, noncontainnr
glass, and other products listed in SIC
3229. It is separated into:
(1) Glass of borosilicate recipe.
(2) Glass of soda-lime and lead
recipes.
(3) Glass of opal, fluoride, and other
recipes.
"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 vessel; replacement
of refractory work in the heat
exchanger; replacment of refractory
portions of the glass conditioning and
distribution system.
"Soda-lime recipe" means raw
material formulation of the following
approximate weight proportions: 72
percent silica; 15 percent nda; 10
percent lime and magnesia; 2 percent
alumina; and 1 percent miscellaneous
materials (including sodium sulfutc).
"Wool fiberglass" means fibrous gl.iss
of random texture, including fi!>urgl;iss
insulation, and other products lister) in
SIC 3296.
§ 60.292 Standards for paniculate 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 of a glass melting
furnace subject to the provisions of this
subpart shall cause to be discharged
into the atmosphere—
(1) From any glass melting furnace
fired exclusively with either a gaseous
fuel or a liquid fuel, particulate matter at
emission rates exceeding those specified
in Table CC-1, Column 2 and Column 3.
respectively, or
(2) From any glass melting furnace.
fired simultaneously with gaseous and
liquid fuels, particulate matter at
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Federal Register / Vol. 45. No. 196 / Tuesday, October 7, 1980 / Rules and Regulations
emission rates exceeding STD as
specified by the following equation:
STD=X[l.3(Y)+(Z)J
Where:
STD = Participate matter emission limit, g of
particulate/kg of glass produced.
X = Emission rate specified in Table CC-1 for
Furnaces fired with gaseous fuel (Column
2).
Y = Decimal percent of liquid fuel heating
value to total (gaseous and liquid) fuel
heating value fired in the glass melting
furnaces as determined in § 80.296(f).
(joules/joules).
Z = (1-Y).
(b) Conversion of a glass melting
furnace to the use of liquid fuel is not
considered a modification for the
purposes of § 60.14.
(c) Rebricking and the cost of
rebricking is not considered a
reconstruction for the purposes of
§ 60.15.
Table CC-11.—Emission Pates
(g of particulate/kg of glass produced]
Col. 1 —Glass manufacturing plant
industry segment
Pressed and blown glass
(b) Soda-Ume and Lead Recipes
(c) Other-Than Borosilicate. Soda-
Lime, and Lead Recipes (includ-
ing opal, fluonde. and other rec-
Col.
2—
Fur-
nace
gas-
eous
fuel
0 1
05
0.1
025
025
0225
Cot.
3—
Fur-
nace
fired
with
liquid
fuel
0 13
065
0.13
0325
0325
0225
§§ 60.293-60.295 [Reserved]
§ 60.296 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 1 shall be used for sample
and velocity traverses, and
(2) Method 2 shall be used to
determine velocity and volumetric flow
rate.
{3} Method 3 shall be used for gas
analysis.
(4) Method 5 shall be used to
determine the concentration of
particulate matter and the associated
moisture content.
(b) For Method 5, the probe and filter
holder heating systen in the sampling
train shall be set to provide a gas
temperature no greater than 177° C. The
sampling time for each run shall be at
least 60 minutes and the collected
particulate shall weigh at least 50 mg.
(c) The particulate emission rate, E,
shall be computed as follows:
E=QxC
Where:
(1) E is the particulate emission rate (g/hr)
(2) Q is the average volumetric flow rate
(dscm/hr) as found from Method 2
(3) C is the average concentration (g/dscm) of
particulate matter as found from .the
modified Method 5
(d) The rate of glass produced, 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) For the purposes of these
standards the furnace emission rate
shall be computed as follows:
R=E-A-=-P
Where:
(1) R is the furnace emission rate (g/kg)
(2) E is the particulate emission rate (g/hr)
from (c) above
(3) A is the zero production rate correction;
A is 227 g/hr for container glass, pressed
and blown (soda-lime and lead) glass,
and pressed and blown (other-than
borosilicate, soda-lime, and lead) glass
A is 454 g/hr for pressed and blown
(borosilicate) glass, wool fiberglass, and
flat glass
(4) P is the rate of glass production (kg/hr)
from (d) above
(f) When gaseous and liquid fuels are
fired simultaneously in a glass melting
furnace, the heat input of each fuel,
expressed in joules, is determined
during each testing period by
multiplying the gross calorific value of
each fuel fired (in joules/kilogram) by
the rate of each fuel fired (in kilograms/
second) to the glass melting furnaces.
The decimal percent of liquid fuel
heating value to total fuel heating value
is determined by dividing the heat input-
of the liquid fuels by the sum of the heat
input for the liquid fuels and the gaseous
fuels. Gross calorific values are
determined in accordance with
American Society of Testing and
Materials (A.S.T.M.) Method D 240-
64(73) (liquid fuels) and D 1826-64(7)
(gaseous fuels), as applicable. The
owner or operator shall determine the
rate of fuels burned during each testing
period by suitable methods and shall
confirm the rate by a material balance
over the glass melting system. [Section
114 of Clean Air Act, as amended (42
U.S.C. 7414).]
2. By adding a second paragraph in
Section 3.1.1 of Reference Method 5 of
Appendix A. as follows:
Appendix A—Reference Methods
Method 5—Determination of Particulate
Emissions From Stationary Sources
*****
3.1.1 Filters. *•* *
In sources containing SO, or SO,, the filter
material must be of a type that is unreactive '
to SO, or SO]. Citation 10 in Section 7 may be
used to select the appropriate filter.
*****
[Section 114 of Clean Air Act, as amended (42
U.S.C. 7414))
Appendix A [Amended]
3. By adding Citation 10 at the end of
Section 7 of Reference Method 5 of
Appendix A, as follows:
*****
Method 5—Determination of Particulate
Emissions From Stationary Sources
*****
7. Bibliography. * * *
10. Felix, L. G., G. I. Clinard, G. E. Lacey.
and J. D. McCain. Inertia! Cascade Impactor
Substrate Media for Flue Gas Sampling. U.S.
Environmental Protection Agency. Research
Triangle Park, N.C. 27711, Publication No.
EPA-600/7-77-060. June 1977. 83 p.
*****
[Section 114 of Clean Air Act, as amended (42
U.S.C. 7414))
|FR Doc. 80-31163 Filed 10-6-80: 8:45 am)
BILLING CODE 6560-01-M
V-446
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19
Federal Register / Vol. 45, No. 220 / Wednesday. November 12, 1980 / Rules and Regulations
ENVIRONMENTAL PROYECTDON
AGENCY
40 CFF3 Part 60
[AD-FRL 1623-4]
Standards of Performance (or New
Stationary Sources; Ammonium
Sulfat@ Manufacture
AGEM6V: Environmental Protection
Agency (EPA).
&CTIOM: Final rule. _ •
SUMMARY: Standards of performance for
ammonium sulfate manufacturing plants
were proposed in the Federal Register
on February 4, 1980 (45 FR 7758). This
action finalizes standards of
performance for ammonium sulfate
manufacturing plants. These standards
implement Section 111 of the Clean Air
Act and are based on the
Administrator's determination that
ammonium sulfate manufacturing plants
cause, or contribute significantly to, air
pollution which may reasonably be
anticipated to endanger public health or
welfare. The intended effect of these
standards is to require all 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 and energy impacts.
EFFECTIVE DATE: November 12, I960.
Under Section 307(b)(l) of the Clean
Air Act, judicial review of this new
source performance standard is
available only by the filing of a petition
for review in the United States Court of
Appeals for the District of Columbia
circuit within 60 days of today's
publication of this rule. Under Section
307(b)(2) of the Clean Air Act, the
requirements that are the subject of
today's notice may not be challenged
later in civil nr criminal proceedings
by EPA to enforce these
requirements.
ADDRESSES: Background Information
Document. The background information
document (BID) for the promulgated
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 Promulgated Emission Standards,"
EPA-450/3-79-0346b.
Docket. A docket, number A-79-31,
containing information used by EPA in
development of the promulgated
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 (A-130), West
Tower Lobby, Gallery 1, 401 M Street,
S.W.. Washington. D.C. 20460.
FOB FURTHER INFOHKJflTIOKI COWVA6T:
Mr. Gene W. Smith, Standards
Development Branch, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5421.
SUPPLEMENTARY INFORMATION:
The Standards
The promulgated standards will limit
atmospheric participate 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 promulgated
standards 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 promulgated
and limits emissions from the affected
facility to no more than 15 percent.
The promulgated standards 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 are also required at those plants
not equipped with product weigh scales.
Summary of Environmental, Energy, and
Economic Impacts
The promulgated standards will
reduce projected 1985 particulate
emissions from new ammonium sulfate
dryers from about 670 megagrams (737
tons) per year, the level of emissions
that would occur under a typical State
Implementation Plan, to about 131
megagrams (144 tons) per year. This will
be an SO percent reduction of particulate
emissions under a typical State
Implementation Plan and will bring the
overall collection efficiency to nearly 93
percent of the uncontrolled emissions.
This reduction in emissions will result in
reduction of ambient air concentrations
of particulate matter in the vicinity of
new, modified, and reconstructed
ammonium sulfate plants. The
promulgated standards are based on the
use of medium energy wet scrubbing to
control particulate matter. All captured
particulate matter will be reclaimed;
therefore, the promulgated standards
will have no adverse impact on water
quality or solid waste.
The promulgated standards will not
significantly increase energy
consumption at ammonium sulfate
plants and will have a minimal impact
on national energy consumption. The
incremental energy needed to operate
control equipment to meet the standards
will 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 sulfate plant.
Economic analysis indicates that the
impact of the promulgated standards
will be reasonable. Cumulative capital
costs of complying with the promulgated
standards for the ammonium sulfate
industry as a whole will be about $1.0
million by 1985. Annualized cost to the
industry in the fifth year of the
promulgated standards will be about
$0.5 million. The industry-wide price
increase necessary to offset the cost of
compliance will amount to less than 0.01.
percent of the wholesale price of
ammonium sulfate. Costs of emission
control required by the promulgated
standards are not expected to prevent or
hinder expansion or continued
production in the ammonium sulfate
industry.
Public Participation
Prior to proposal of the standards,
interested parties were advised by
public notice in the Federal Register (44
FR 45242, August 1,1979) of a meeting of
the National Air Pollution Control
Techniques Advisory Committee to
discuss the ammonium sulfate
manufacturing plant standards
recommended for proposal. This meeting
occurred on August 28,1979. The
meeting was open to the public and each
attendee was given an opportunity to
comment on the standards
recommended for proposal.
The standards were proposed in the
Federal Register on February 4,1980 (45
FR 7758). Public comments were
solicited at that time and. when
requested, copies of the Background
Information Document (BID) were
distributed to interested parties.
To provide interested persons the
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards, a public hearing
was held on March 6,1980, at Research
Triangle Park, North Carolina. The
hearing was open to the public and each
attendee was given an opportunity to
comment on the proposed standards.
The public comment period was from
February
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Federal Register / Vol. 45, No. 220 / Wednesday. November 12, 1980 / Rules and Regulations
ammonium sulfate manufacturing
plants. The comments have been
carefully considered and, where
determined to be appropriate by the
Administrator, changes have been made
in the standards that were proposed.
Significant Comments and Changes to
the Proposed Standards
Comments on the proposed standards
were received from ammonium sulfate
manufacturers and State air pollution
control agencies. Most of the comment
letters contained multiple comments. >
The comments have been divided into
the following areas: General; Emission
Control Technology; Test Methods and
Monitoring: and Other Considerations.
General
One commenter thought that new
source performance standards (NSPS)
should be applied to any new
ammonium sulfate dryer regardless of
the manufacturing process used. The
commenter referred to one plant which
recovers ammonium sulfate from a
scrubber controlling the emissions from
a sulfuric acid unit at a phosphate
fertilizer plant.
The standards regulate new, modified,
and reconstructed dryers at three types
of ammonium sulfate manufacturing
plants: synthetic, caprolactam by-
product, and coke oven by-product.
Over 90 percent of ammonium sulfate is
generated from these types of plants.
During the development of the
standards, EPA determined that the
impact of regulation and potential for
emission reduction with new source
performance standards is significant
only within these industry sectors.
These types of plants are the major
sources of ammonium sulfate emissions.
Only two plants in the U.S. are known to
produce ammonium sulfate as a by-
product of sulfuric acid manufacture
using the Cominco-Swenson process; the
trend In the industry is toward using the
dual absorption process of
manufacturing sulfuric acid which
eliminates the output of ammonium
sulfate. Since there does not appear to
be any growth or replacement potential
for plants using the Cominco-Swenson
process (this segment is in fact
contracting), there is no justification to
include this process in the standards.
Ammonium sulfate is also a by-
product of the manufacture of nickel
from ore concentrates and the
manufacture of methyl methacrylate at
one existing facility. However, no new
plants of either type are expected to be
built. Furthermore, new technology for
the manufacture of methyl methacrylate
now being put in use at existing plants
eliminates the production of ammonium
sulfate altogether.
It was recommended by one
commenter that an emission limit be
established for sulfur dioxide and
ammonia through specification of a
modified Method 5 test procedure.
Study of the ammonium sulfate
industry has shown that ammonium
sulfate particulate matter is the principal
pollutant emitted to the atmosphere
from ammonium sulfate plants. Sulfur
dioxide and ammonia are not emitted
from ammonium sulfate plants in
amounts significant enough to warrant
regulation. EPA Method 5 provides
detailed procedures, equipment criteria,
and other considerations necessary to
obtain accurate and representative
particulate emission data and is the
appropriate test procedure to measure
ammonium sulfate particulate
emissions. EPA Method 5 was used to
gather the data which is the basis for the
promulgated standards and is therefore
specified as the method to be used for
compliance testing.
Emission Control Technology
Specification of Control Equipment
One commenter suggested that the
proposed standard be "equipment
specific" requiring the use of venturi
scrubbers. However, Section lll(h) of
the Clean Air Act establishes a
presumption against design, equipment,
work practice, and operational
standards. Such standards cannot be
promulgated if a standard of
performance is feasible. Performance
standards for control of ammonium
sulfate particulate emissions have been
determined as practical and feasible;
therefore, design, equipment, work
practice, or operational standards are
nbt considered as regulatory options.
Use of Fabric Filters to Meet Proposed
Standards
Two comments were received which
questioned the feasibility of utilizing
fabric filters for the collection of
particulate emissions at ammonium
sulfate plants. Both commentere noted
the fact that frequent and serious
operational problems can occur with the
use of fabric filter systems at ammonium
sulfate plants. One commenter. a
synthetic ammonium sulfate producer,
pointed out that his company's efforts to
utilize a baghouse were totally
unsuccessful. The plant discontinued
use of the fabric filter system because
excessive blinding of the fabric and
caking of the collected dust in the
baghouse, bins, and discharge chutes
occurred which required frequent plant
shutdown (an operating pattern
considered entirely unacceptable at
large scale, continuous process
ammonium sulfate plants).
The condensation which causes the
blinding and caking results from failure
to maintain the temperature of the dryer
exhaust and/or baghouse surfaces
sufficiently above the dew point at all
times. The commenter noted that the
presence of even low level sulfuric acid
(or hydrocarbon) vapor effectively
results in a gaseous mixture that has a
dew point considerably higher than
would be predicted solely on the basis
of the moisture content.
This is considered a reasonable
comment. EPA contended in the
preamble to the proposed regulation that
fabric filters had the potential to meet
the proposed emission limits. However,
it was felt that none of the facilities
coming on-line would elect to install
fabric filter systems due to the relative
advantages of wet scrubbers. The new
information provided regarding the
character of the ammonium sulfate dryer
exhaust gas, coupled with the
operational experience of those plants
which have tried fabric filtration as a
control technique, leads to the
conclusion that fabric filtration is not a
viable control alternative applicable to
particulate collection at ammonium
sulfate plants. This conclusion, however,
does not affect the numerical emission
limits proposed for ammonium sulfate
dryer new source performance
standards. The emission limits as well
as the estimated environmental,
economic, and energy impacts are based
on the use of a medium energy wet
scrubber. These limits represent the
most stringent control level that can be
met by all segments of the industry.
Therefore, no change has been made in
the numerical emission limits from
proposal to promulgation.
Volatile Organic Compound Emissions
At Caprolactam By-Product Plant:;
•• Two commenters were concerned
with the effect of using fabric filters on
volatile organic compound (VOC)
emissions at caprolactam by-product
ammonium sulfate plants. Both
contended that although the use of
fabric filters would reduce particulate
emissions, VOC emissions would
increase because a fabric filter would
capture very little, if any. of the VOC
which would be captured by a wet
collection method.
Caprolactam is introduced into the
ammonium sulfate process from those
streams which, in the caprolactum
formation reactions, produce ammonium
sulfate as a by-product. Caprolactam
has a melting point of 60°C and a boiling
point of 140°C. This means that the
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Register / Vol. 45, No. 220 / Wednesday, November 12, 1980 / Rules and Regulations
majority of caprolactam present in the
ammonium sulfate dryer at the operating
temperature involved (about 85°C) is in
the liquid phase. The liquid caprolactam
in the dryer adheres to the ammonium
sulfate crystals and passes through the
drying and classifying process. This
residual caprolactam is a solid at
ambient storage conditions. Any volatile
caprolactam present in the ammonium
sulfate dryer (and exit gas) results from
the vapor pressure of caprolactam at the
operating temperature of the dryer. EPA
test data indicate that uncontrolled
volatilized caprolactam emissions are
relatively low level (about 60 ppm). In
addition, wet collection currently in use
as particulate control has demonstrated
nearly 90 percent removal efficiency of
the uncontrolled caprolactam emissions.
This results in a controlled emission rate
of about 7 ppm which is not considered
to contribute significantly to air
pollution.
As pointed out in the previous
comment concerning fabric filters, there
is now adequate evidence to conclude
that wet scrubbing will be selected to
control particulate emissions from
ammonium sulfate plants. Since fabric
filters will not be used there is no
potential for increase in VOC emission.
Control Equipment Efficiency and
Process Variations
One commenter stated it is doubtful
that either the venturi scrubber or fabric
filter will be able to sustain 99.9 percent
efficiency during all variations
associated with normal operating
conditions at ammonium sulfate plants.
The commenter went on to say that EPA
has repeatedly failed to consider
variations associated with processes,
control devices, testing equipment, and
laboratory procedures and that EPA has
failed to recognize the wide variations
obtained from the same plant and
pollution control system, as measured
by EPA methods, during representative
operating conditions.
The new source performance
standards for this industry are not based
on percent removal efficiency but on the
performance level of the best system of
continuous emission reduction
considering cost and other factors. The
percent efficiencies were provided for
information purposes only. EPA
determined the performance level
through direct emission testing at
ammonium sulfate plants representative
of the full range of operating conditions
in the industry. Several plants were
selected by EPA for emission testing in
order to adequately consider all
commonly occurring process and
emission control variations found in the
industry. The plants tested used the
various drying techniques and gas-to-
product ratios found in the industry and
likely to be used in the future. FOP
instance, both fluidized bed and rotary
drum dryers were tested utilizing both
direct-fired and steam heated air as the
drying medium. Each emission test
consisted of three separate test runs
conducted during normal or
representative operating conditions
utilizing EPA Method 5. Results of the
test runs were averaged (as would be
the case in determining source
compliance) to provide for any minor
variations in process and test conditions
during the plant test. In the future,
performance tests for determination of
source compliance will be conducted
using procedures identical to those used
in development of the promulgated
standards. Emission test results from
these different drying techniques
indicate that the performance levels
selected for the standards can be met by
all segments of the ammonium sulfate
industry.
Test Methods and Monitoring
One commenter suggested that
§ 60.423(a) of the proposed standards,
Monitoring of Operations, be changed to
provide consistency with § 60.424(d)
which states that production rate may
be determined by use of product weigh
scales, or by material balance
calculations. As proposed, § 60.423(a) of
the regulation would have required
installation of process feed stream flow
meters, even if weigh scales were used
to measure production rate.
This is a reasonable comment. The
emission limit of the regulation is
expressed in allowable emissions per
unit mass of product. Therefore,
production rate must be determinable.
Flow meters were required in an effort
to provide a means to accurately
determine the production rate at those
facilities electing not to install weigh
scales. It is not EPA's intention that
owners or operators of affected facilities
who elect to install weigh scales should
also be required to install process
stream flow monitors. The regulation
has therefore been changed to note that
if a plant uses weigh scales of the same
accuracy as the flow monitoring devices,
then flow monitors are not required.
One commenter requested that
instead of continuous monitoring of
pressure drop, periodic monitoring of
pressure drop across the control system
for any affected facility be allowed. It
was suggested that the pressure drop
across the control system should be
taken by operating personnel at a
frequency no greater than once every 2
hours and entered in an operator log. It
was contended that the reliability of
venturi scrubbers is such that more
frequent measurements or continuous
pressure drop monitors could not be
justified and would be a waste of both
capital and energy. It was stated that
imposing more costly or time-consuming
monitoring requirements than is
necessary to adequately demonstrate
emission compliance will, in the long
run, be counterproductive.
In EPA's experience, continuous"
pressure drop monitoring provides a
more accurate indication of emission
control equipment operation and
maintenance than periodic or
intermittent readings and thereby
facilities enforcement activities. It has
also been determined that the costs of
continuous pressure drop monitoring at
ammonium sulfate plants are
reasonable, and that there are no
technical or process reasons to monitor
periodically. Therefore, no change in the
pressure drop monitoring requirements
of the proposed regulation was made.
One commenter noted that for
caprolactam by-product plants the
ammonium sulfate feed streams which
require flow monitoring devices for
determination of mass product flow are,
in some cases, inappropriate. It was
pointed out that not all ammonium
sulfate solution produced is taken to the
solid form; some is sold as solution.
Therefore, the total combined feed
streams to the ammonium sulfate
crystallizer, prior to any recycle
streams, would be the most accurate
place to measure process input feed.
This is considered a reasonable
comment. For those caprolactam by-
product ammonium sulfate plants not
equipped with product weigh scales, the
proposed standards would have
required that the oximation ammonium
sulfate stream to the ammonium sulfate
plant and the oleum stream to the
caprolactam rearrangement reactor must
be monitored separately as a means of
determining the ammonium sulfate
production rate. It did not specify that
the total combined feed stream leading
directly to the crystallizer stage can also
be monitored.
Therefore, in response to this
comment, § 60.424{d) has been changed
to specify monitoring of the total or
combined feed streams leading directly
to the crystallizer stage for caprolactam
by-product plants. A new equation has
been developed for § 60.424(d) to allow
calculation of ammonium sulfate
production rate from the flow rate of the
total feed stream.
Another commenter contended that
visual opacity measurement is
unscientific, inaccurate, and. at best.
arbitrary. It was suggested that the
proposed opacity standard is
V-449
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Federal Register / Vol. 45. No. 220 / Wednesday. November 12, 1980 / Rules and Regulations
unnecessary to adequately monitor
ammonium sulfate manufacturing
emissions; and since there is no reliable
method for its measurement, the opacity
standard should be deleted.
An opacity standard of 15 percent
was proposed for all affected facilities
to ensure proper operation and
maintenance of control systems on a
day-to-day basis. The proposed method
for opacity monitoring is EPA Method 9.
The reliability of opacity standards and
the reference test method has been
rigorously tested in the field and in the
courts. In the case of Portland Cement
Association v. Train, 513 F.2d 506 (D.C.
Cir. 1975). the court ruled that plume
opacity was not too unreliable to be
used either as a measure of pollution or
as an aid in controlling emissions. As a
basis for the standard, ammonium
sulfate dryers were observed to have no
opacity readings greater than 15 percent
opacity during observation periods
totaling more than 19 hours. For these
reasons no change was made in the
opacity standard.
Other Considerations
One commenter could not find
justification for proposing a standard for
modified and new sources that is more
stringent than the baseline emission
level of existing SIP. It was contended
that since there was no medical
evidence presented showing any harm
being created by the ammonium sulfate
dryer emissions allowed under existing
State regulations, there is no
justification for standards requiring
additional investment and energy.
On August 21,1979, ammonium sulfate
manufacturing was listed under Section
lll(f) of the Clean Air Act as a
stationary source category for which
standards should be promulgated (44 FR
49222). This listing represents the
Administrator's determination that
ammonium sulfate manufacturing
causes, or contributes significantly to,
air pollution which may reasonably be
anticipated to endanger public health or
welfare. The commenter did not submit
any arguments that suggested the
Administrator should reconsider this
determination.
Under Section lll(a), standards which
are promulgated for a category must
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, and
non-air quality health, and
environmental and energy impacts) has
been adequately demonstrated. Based
on a thorough study on control
alternatives, including no additional
regulatory action, EPA has determined
that the promulgated emission limits
best satisfy these criteria for ammonium
sulfate manufacture.
Furthermore, participate matter, the
principal pollutant emitted to the
atmosphere from ammonium sulfate
plants, is a criteria pollutant (listed as
such under Section 108 of the Clean Air
Act) for which national ambient air
quality standards have been
established. Specific information
regarding the health and welfare effects
of particulate matter in the atmosphere
was provided in association with the
listing of particulate matter as a criteria
pollutant.
Docket
The docket is an organized and
complete file of all the information
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 standards and EPA
responses to significant comments, the
contents of the docket will serve as the
record in case of judicial review
[Section 307(d)(7)(A)].
Miscellaneous
The effective date of this regulation is
November 12,1980. 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 (February 4,1980).
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, and 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 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 tehnnology" (BACT) 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 an applicable
standard established pursuant to
Section 111 (or 112) of the Act.
In any event, 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 limits than those established
under Section 111 or those necessary to
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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 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,
improvements in emission control
technology, and reporting requirements.
The reporting requirements in this
regulation will be reviewed as required
under EPA's sunset policy for reporting
requirements in regulations.
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 promulgated
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the promulgated
standards to insure that the standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the Background Information
Document.
Dated: November 4. 1980.
Douglas M. Costle.
Administrator.
PERFORMANCE POK K1IW
STAT1ONARV SOURCES
40 CFR Part 60 is amended by adding
a new subpart as follows:
Subpati PP—SJandairdo &1 Portomtanco ley
Ammonium Sulfate Manu«ac«uro
Sec.
60.420 Applicability and designation of
affected facility.
60.421 Definitions.
60.422 Standards for particulate matter.
60.423 Monitoring of operations.
60.424 Test methods and procedures.
Authority: Section 111. 301(a) of the Clean
Air Act as amended, [42 U.S.C. 7411. 7e01(a)|.
and additional authority aa noted below.
§ 30.420 Applicability and dcoignaSton 08
aKocted facility.
(a) The affected facility to which the
provisions of this subpart apply is each
ammonium sulfate dryer within an
ammonium sulfate manufacturing plant
in the caprolactam by-product,
synthetic, and coke oven by-product
sectors of the ammonium sulfate
industry.
(b) Any facility under paragraph [a] of
this section that commences
construction or modification after
February 4,1980, is subject to the
requirements of this subpart.
§ 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.
"Ammonium sulfate dryer" means a
unit or vessel into which ammonium
sulfate is charged for the purpose of
reducing the moisture content of the
product using a heated gas stream. The
unit includes foundations,
superstructure, material charger
systems, exhaust systems, and integral
control systems and instrumentation.
"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 total or combined
feed streams (the oximation ammonium
sulfate stream and the rearrangement
reaction ammonium sulfate stream) to
the crystallizer stage, prior to any
recycle streams.
"Ammonium sulfate manufacturing
plant" means any plant which produces
ammonium sulfate.
"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.
"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.
"Synthetic ammonium sulfate
manufacturing plant" means any plant
which produces ammonium sulfate by
direct combination of ammonia and
sulfuric acid.
§ 50.022 Standards) ior partlculato matte?.
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 an emission rate 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 greater than 15-
percent opacity.
§ S0.423 Monitoring ol 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 ± S percent over its range.
However, if the plant uses weigh scales
of the same accuracy to directly
measure production rate of ammonium
sulfate, the use of flow monitoring
devices is not required.
(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.
(Section 114 of the Clean Air Act as amended
(42 U.S.C 7414))
§ 80.420 Test metfrodo 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=QwlxC0-=-lCOO
(1) E is the particulate emission rate
(kg/h).
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Federal Register / Vol. 45. No. 220 / Wednesday. November 12, 1980 / Rules and Regulations
(2) QKI is the average volumetric flow
rate (dscm/h) 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/h),
shall be determined by direct
measurement using product weigh
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=AxBxCx0.0808
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(6.0xlO-*)
where:
P=Production rate of caprolactam by-
product ammonium sulfate in megagrams
per hour.
D = Total combined feed stream flow rale to
the ammonium sulfate crystallizer before
the point where any recycle streams
enter the stream, in liters per minute
averaged over the time period taken to
conduct the test run.
E = Density of the process stream solution in
grams per liter.
F = Percent mass of ammonium sulfate in the
process solution in decimal form.
6.0 X10~5= 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 (ky/h)
from"[c) above; and
(3) P is the rate of ammonium sulfate
production (Mg/h) from (d) above.
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 7414))
|FR Doc. 80-35210 Filed 11-10-80: 8:45 am)
BILLING CODE 656O-26-M
V-452
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120
40 CFR Part 60
[A-7-FRL 1669-8]
New Source Performance Standards;
Delegation of Authority to the State of
Iowa and Change of Address
AOENCY: Environmental Protection
Agency (EPA).
ACTION: Final rulemaking.
SUMMARY: The EPA is today amending
40 CFR 60.4(b)(Q) to reflect a change of
address of the Iowa Department of
Environmental Quality (IDEQ), because
the Department moved to another office.
EFFECTIVE DATE: November 17,1980.
FOR FURTHER INFORMATION CONTACT:
Daniel Rodriguez, Air Support Branch,
U.S. Environmental Protection Agency,
Region VII, 324 E. llth Street, Kansas
City, Missouri 64106, (816) 374-6525; FTS
758-6525.
SUPPLEMENTARY INFORMATION: The
IDEQ has been delegated authority to
implement and enforce the federal New
Source Performance Standards (NSPS)
regulations for 26 stationary source
categories. A first delegation affecting 11
source categories was published in the
Federal Register on December 30,1976
(41 FR 56889). A second delegation.
affecting these source categories and 15
additional source categories, is
published today elsewhere in the
Federal Register. The amended 40 CFR
60.4(b)(Q) corrects the address of the
IDEQ to which all reports, requests,
applications, submittals, and
communications to the Administrator, as
required by 40 CFR Part 60, must also be
addressed.
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
burdens are imposed upon the parties
affected.
The delegation which influenced this
Administrative amendment was
effective on Auust 25,1980, and it serves
no purpose to delay the technical
change of this address in 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.
§ 7412.
Dated: November 5,1980.
Kathleen Q. Canin.
Regional 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 (Q) to read as
follows:
§60.4 Address.
*****
(b) * * *
(Q) State of Iowa, Iowa Department of
Environmental Quality, Henry A. Wallace
Building, 900 East Grand, Des Moines, Iowa
50316.
(FR Doc. 80-05759 Filed 11-14-80: 8:45 am|
121
40 CFR Part 60
|AD-FRL-163a-91
Standards of Performance for New
Stationary Sources Petroleum
Refineries; Clarifying Amendment
AOENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action clarifies which
gaseous fuels used at petroleum
refineries are covered by the existing
standards of performance for petroleum
refineries (40 CFR 60. Subpart J) and is
implemented under the authority of
Section 111 of the Clean Air Act. This
action does not change the
environmental, energy, and economic
impacts of the existing standards.
EFFECTIVE DATE: December 1.1980.
ADDRESSES: Docket No. A-79-56.
containing all supporting information
V-453
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Federal Register / Vol. 45. No. 232 / Monday. December 1. 1980 / Rules and Regulations
used by EPA in supporting this action, 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, West Tower
Lobby, Gallery 1, Waterside Mall, 401 M
Street, S.W., Washington, D.C. 20460. A
reasonable fee may be charged for
copying.
FOR FURTHER INFORMATION CONTACT:
Ms. 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:
Summary of Amendment
The amendment as promulgated
defines fuel gas as any gas which is
generated at a refinery and which is
combusted. It also includes natural gas
when it is combined and combusted
with a gas generated at a refinery.
Gases generated by catalytic cracking
unit catalyst regenerators and fluid
coking burners are excluded from the
definition of fuel gas.
The final amendment contains a
minor wording change, but does not
substantively differ from the proposed
amendment. This action does not have
any impact on the coverage of the
existing standard and does not affect
the economic, energy or environmental
impacts of the present standard.
Summary of Comments and Changes to
the Proposed Amendment
On March 3,1980, EPA proposed in
the Federal Register (45 FR 13991) an
amendment intended to clarify the
definition of fuel gas which is included
in 40 CFR 60.101. The amendment
proposed on March 3,1980, defined fuel
gas as "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." It excluded gases generated by
catalytic cracking unit catalyst
regenerators and fluid coking burners.
The previous definition of fuel gas has
been "natural gas or any gas generated
by a petroleum refinery process unit
which is combusted separately or in any
combination." The purpose of the
proposed amendment of March 3,1980,
was to clarify that natural gas produced
outside of a refinery is not covered by
the definition of fuel gas, unless the
natural gas is combined with gases
produced at a refinery. The purpose of
the standard in 40 CFR 60, Subpart J is
to prevent emissions of sulfur dioxide
resulting from the burning of gaseous
fuels containing hydrogen sulfide. If
commercial natural gas is combusted,
there is essentially no potential for
sulfur dioxide emissions since this gas
has to be relatively free of hydrogen
sulfide in order to meet pipeline
specifications.
Another purpose of the amendment
proposed on March 3.1980, was to
clarify that any gas with the
composition of natural gas which is
generated at the refinery where it is
combusted is covered by the definition
of fuel gas. There are a number of gases
generated on-site at a refinery, such as
propane, butane, by-product gas
resulting from catalytic cracking and
reforming/hydrating processes, and
occasionally, methane and ethane. Since
these gases do not have to be treated to
meet pipeline specifications, combustion
of these gases can be a significant
source of sulfur dioxide emissions.
Interested persons were given an
opportunity to comment on the proposed
change during a 60-day comment period
which ended on May 2,1980. Three
comment letters were received, two
from oil industry representatives and a
third from a State environmental
agency. All commenters agreed, in
principle, with the definition of fuel gas
included in the proposed action.
However, the commenters expressed
concern over the specific wording of the
definition. One commenter said the
wording used was generally confusing.
The other two commenters specifically
expressed concern over the phrase
"natural gas generated at a petroleum
refinery", since they argued natural gas
is not conventionally thought of as being
generated at a petroleum refinery.
EPA agrees that gases generated at a
refinery which have the same
composition as natural gas are not
commonly referred to as natural gas.
Furthermore, defining fuel gas as "any
gas which is generated at a petroleum
refinery" includes any gas which has the
composition of natural gas. Therefore,
the amendment which is being
promulgated has been changed to
remove the terminology "natural gas
generated at a refinery." However, the
intent and substance of the promulgated
amendment is the same as the proposed
amendment.
Docket
Docket No. A-79-56, 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, West Tower
Lobby, Gallery 1 (see Addresses 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
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)J.
Miscellaneous
The effective date of this amendment
is (date of promulgation). It applies to
any affected facilities covered by
Subpart J of 40 CFR Part 60.
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. These other
regulations are labeled "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: November 24,1980.
Douglas M. Costle,
Administrator.
Part 60 of chapter 1, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.101 is amended by
revising paragraph (d) as follows:
§60.101 Definitions.
*****
(d) "Fuel gas" means any gas which is
generated at a petroleum refinery and
which is combusted. Fuel gas also
includes natural gas when the natural
gas is combined and combusted in any
proportion with a gas generated at a
refinery. Fuel gas does not include gases
generated by catalytic cracking unit
catalyst regenerators and fluid coking
burners.
*****
(Sees. Ill and 301 (a) of the Clean Air Act is
amended (42 U.S.C. Sections 7411 and
7601(a))).
|FR Doc. 80-37246 Filed 11-28-80; 8:45 am|
V-454
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Federal Register /• Vol. 45. No. 245 / Thursday. December 18. 1980 / Rules and Regulations
I22
40 CFR Part 60
IAD-FRL 1690-3]
Standards of Performance for New
Stationary Sources; Petroleum Liquid
Storage Vessels: Correction
AGENCY: Environmental Protection
Agency.
ACTION: Correction of final rule.
SUMMARY: This action amends the
standards of performance for petroleum
liquid storage vessels by adding gap
criteria for secondary seals used in
combination with primary vapor-
mounted seals on external floating roofs.
This amendment is necessary because
these criteria were inadvertently
omitted from the standards promulgated
on April 4,1980 (45 FR 23373). The intent
of this amendment is to correct the
. standards to reflect the original intent as
expressed in the'proposed standards
and in the preamble to the final
standards.
EFFECTIVE DATE: December 18,1980.
ADDRESSES: Docket No. OAQI'S-78-2
conlnining all supporting inform;ition
used by EPA in developing Ihc
standards, 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.
West Tower Lobby. Gallery 1.
Waterside Mall. 401 M Street. SW..
Washington. D.G. 20460. A reasonable
fee may be charged for copying.
FOR FURTHER INFORMATION CONTACT:
Mr. Gene Smith. Standards
Development Branch, Emission
Standards and Engineering Division
(MD-13). U.S. Environmental Protection
Agency, Research Triangle Park. North
Carolina 27711. telephone number (919)
541-5421.
SUPPLEMENTARY INFORMATION:
Standards of performance for new
petroleum liquid storage vessels were
promulgated on April 4,1980 (45 FR
23373). The standards are in terms of
equipment specifications and
maintenance requirements. One of the
requirements is for storage vessels with
external floating roofs to be equipped
with two seals, a primary and a
secondary, for which minimum
allowable gaps are specified. The gap
requirements in the final standards were
intended to be approximately equivalent
to those in the proposed standards. The
preamble states. "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
... will result."
The proposed standards specified
gaps for two types of primary seals, a
metallic shoe seal and a non-metallic
resilient seal (vapor-mounted seal), and
for the secondary seals used with them.
For secondary seals used with metallic
shoe primary seals, the proposed
standards would have allowed gaps as
wide as 0.32 cm (Vs inch) for 95 percent
of the tank circumference and gaps as
wide as 1.3 cm (Vi inch) for the
remaining 5 percent of the tank
circumference. For secondary seals used
with vapor-mounted primary seals, the
proposed standards were more
restrictive, requiring that gaps be no
wider than 0.32 cm (Vg inch) for 100
percent of the tank circumference.
In the final standards, the gap
requirements were expressed in terms of
total gap area rather than as maximum
allowable gap widths to provide a more
effective and uniform compliance
procedure. The final standards specify
that only gaps greater than 0.32 cm (Vs
inch) are to be measured for purposes of
determining total gap area (40 CFR
60.113a(a)(l)(ii)(B)]. This, in effect,
allows a 0.32 cm ('/* inch) gap around
the entire circumference of the tank for
each seal. Therefore, in converting the
proposed gap requirements to the final
total gap area, only gaps greater than
0.32 cm C/H inch) were included in the
calculations. The proposed allowance of
gaps 1.3 cm ('/a inch) wide for 5 percent
of the tank circumference for secondary
seals used with metallic shoe seals was
correctly expressed as a total gap area
of 21.2 cm2 per meter of tank diameter
(1.0 in2 per ft. of tank diameter) in the
final standards. The proposed
requirement that there be no gaps wider
than 0.32 cm (Vs inch) for 100 percent of
the tank circumference for secondary
seals used with vapor-mounted primary
seals should have been expressed as a
requirement for no gaps. However, this
requirement was inadvertently omitted
from the final standards, thus
unintentionally allowing these seals to
have the larger gaps specified for
secondary seals used with metallic shoe
seals. The standards are, therefore.
being corrected to reflect the original
intent of allowing no gaps for secondary
seals used with vapor-mounted primary
seals. As provided by Section lll(a)(2)
of the Clean Air Act, the standards as
corrected by today's action apply to
storage vessels for which construction
began after May 18,1978, the date on .
which the standards were proposed.
The Administrator believes that this
correction to the standards of
performance will not have any adverse
impacts on owners or operators of
petroleum liquid storage vessels. Since
secondary seals are designed to fit very
tightly against the tank wall, any new
seal installed on a new storage vessel
since the April 4,1980, promulgation
date would easily be able to meet the
intended no gap criterion. Therefore,
this correction is applicable to any
storage vessel for which construction or
modification began after May 18,1978.
The Administrator finds that good
cause exists under 5 U.S.C. 553(b)(B) for
omitting prior notice and public
comment on this amendment because it
simply corrects a technical error in the
promulgated standards so that the
standards reflect the intent expressed in
the preamble and in the proposed
standards.
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. Since
the costs associated with the
amendment would have a negligible
impact on consumer costs, the
Administrator has determined that the
amendment is not substantial and does
V-455
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not require preparation of an economic
impact assessment.
Dated: December 12. 1980.
Douglas M. Coslle.
Administrator.
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations is amended
by revising § 60.112(a)(l)(ii)(B) to read
as follows:
§ 60.112a Standard for volatile organic
compounds (VOC).
(a)' ' '
(I)''*
(»}' ' '
(B) The accumulated area of grips
between the tank wall and the
secondary seal used in combination
with a metallic shoe or liquid-mounted
primary seal shall not exceed 21.2 cm-
per meter of tank diameter (1.0 in2 per ft.
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm ('/2 in.). There shall be no gaps
between the tank wall and the
secondary seal used in combination
with a vapor-mounted primary seal.
• * « 4 *
(Sec. 111. 301(e) of the Clean Air Act us
amended |42 U.S.C. 7411. 7601(a)|)
|FR Doc. 80-39326 Tiled 12-17-60: 8:45 ami
123
40 CFR Part 60
[AD-FRL 1710-21
Standards of Performance for New
Stationary Sources; Revised
Reference Methods 13A and 138;
Corrections
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule: corrections.
SUMMARY: When the final revisions to
Appendix A Methods 13(a) and 13(b)
were published in the June 20,1980
Federal Register (45 FR 41852). certain
inadvertent and typographical errors
were made. The purpose of this action is
to correct these errors.
EFFECTIVE DATE: December 24,1980.
FOR FURTHER INFORMATION CONTACT:
Mr. Roger Shigehara, Emission
Measurement Branch (MD-19), Emission
Standards and Engineering Division,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-2237.
SUPPLEMENTARY INFORMATION: The
following corrections to Appendix A
should be made in the Federal Register
document 80-18658, Friday, June 20,
1980, appearing on pages 41855, 41857,
and 41858:
1. Page 41855: a. First column,
paragraph 6.1.1.2, third line: Add a
comma after "paper," as * * * "(e.g.,
paper, organic membrane). * * *"
b. Second column, paragraph 7.1, third
line: Change "text" to "test."
c. Second column, paragraph 7.2,
thirteenth line: Add "s" to "backward."
2. Page 41857: a. Second column, in
paragraph 9.1 ninth line from top:
Change the word "collected" in the
definition of Vd to "as diluted." The
definition of Vd should read, "Volume of
distillate as diluted, ml."
b. Third column, in paragraph 9.1
footnote at bottom: Add "U.S." before
"Environmental Protection Agency."
3. Page 41858: a. First column, in
paragraph 7.2.1 sixth line from bottom:
Change "termperature" to
"temperature."
b. Second column, in paragraph 7.2.1
sixth line from top: Add "deionized"
after "with".
c. Second column, in paragraph 7.2.1
Equation 13B-1: Change "T," to "V,".
d. Third column, paragraph 9.2, fourth
line: Change Fluroide" to "Fluoride."
Dated: December 16,1980.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation.
|KR Doc. 60-39770 Filed 12-23-60: 8:45 am]
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Federal Register / Vol. 45, No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[AD-FRL 1627-8]
Standards of Performance for New
Stationary Sources; Automobile and
Light-Duty Truck Surface Coating
Operations
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance to limit
emissions of volatile organic compounds
(VOC) from new, modified, and
reconstructed automobile and light-duty
truck surface coating operations within
assembly plants. The standards were
proposed and published in the Federal
Register on October 5,1979.
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 which may reasonably be
anticipated to endanger public health or
welfare. 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.
EFFECTIVE DATE: December 24,1980.
Under Section 307(b)(l) of the Clean
Air Act, judicial review of this new
source performance standard is
available only by the filing of a petition
for review in the United States Court of
Appeals for the District of Columbia
Circuit within 60 days of today's
publication of this rule. Under Section
307(b)(2) of the Clean Air Act. the
requirements that are the subject of
today's notice may not be challenged
later in civil or criminal proceedings
brought by EPA to enforce these
requirements.
ADDRESSES: Background Information
Document. The Background Information
Document (BID) for the final 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
-Surfaca Coating Operations—
Background Information for
Promulgated Standards" (EPA-450/3-
79-030b).
Docket. The Docket, number A-79-05,
containing supporting information used
in developing the promulgated
standards is available for public
inspection and copying between 8:00
a.m. and 4:00 p.m., Monday through
Friday at the EPA's Central Docket
Section, West Tower, Lobby Gallery 1,
Waterside Mall. 401 M Street SW.,
Washington, D.C. 20460. A reasonable
fee may be charged for copying.
FOR FURTHER INFORMATION CONTACT:
Mr. Gene Smith, Chief, Standards
Preparation Section (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5421.
SUPPLEMENTARY INFORMATION:
The Standards
The promulgated standards apply to
new, modified, or reconstructed
automobile and light-duty truck surface
coating operations for which
construction is commenced after
October 5,1979. The standards apply to
each prime coat operation, each guide
coat operation, and each topcoat
operation within an assembly plant
where components of an automobile or
light-duty truck body are coated.
Operations used to coat plastic body
parts and all-plastic bodies on separate
coating lines are not covered. However,
operations which coat all-metal bodies
or metal bodies with plastic body parts
attached before coating are covered by
the standards. Emissions of VOC from
affected facilities are limited as follows:
0.16 kilograms of VOC per liter of
applied coating solids from prime coat
operations, 1.40 kilograms of VOC per
liter of applied coating solids from guide
coat operations, 1.47 kilograms of VOC
per liter of applied coating solids from
topcoat operations.
Although the emission limits are
based on the use of waterborne coating
materials in each coating operation, they
can also be met with solvent-borne
coating materials through the use of
other control techniques such as
incineration.
Annual model changeovers or
switches to larger cars and changes in
the application of coatings to increase
film thickness are not covered as
modifications under § 60.14.
The owner or operator is required to
conduct a performance test each
calendar month and report the results to
EPA within ten days of the end of any
month in which the affected facility is
not in compliance with the standards.
The calculation of the volume weighted
average mass of VOC per volume of
applied coating solids during each
calendar month constitutes a
performance test. While Method 24 is
the reference method for use in this
performance test to determine data used
in the calculation of the volatile content
of coatings, provisions have been made
to allow the use of coatings
manufacturers' formulation data to
determine the volume fraction of solids.
In addition to the non-compliance
report, the owner or operator of an
affected facility who utilizes
incineration to comply with the
standards must submit reports quarterly
on incinerator performance.
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 standards
and those for one complying with the
emission standards in a typical State
Implementation Plan (SIP). 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
SIPs. Revisions to most SIPs 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 SIPs for these
areas and are expected to include
revised emission limitations for
automobile and light-duty truck surface
coating operations in their new SIPs. In
revising their SIPs, 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-
008 [CTG]).
Since control technique guidelines are
not binding. States may establish
emission limits which differ from the
guidelines. To the extent States adopt
the emission limits recommended in the
control techniques guideline document
as the basis for their revised SIPs, the
promulgated standards will have little
environmental, energy, or economic
impacts. The actual incremental impacts
of the promulgated standards will be
determined by the final emission
limitations adopted by the States in
their revised SIPs. For the purpose of
this rulemaking. however, the
environmental, energy, and economic
impacts of the standards have been
V-457
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Federal Register / Vol. 45. No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
estimated based on emission limits
contained in existing SIPs at the end of
1978 when development of background
information for the standards began.
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 a
case-by-case determination of best
available control technology (BACT) for
operations located in attainment areas
and lowest achievable emission rates
(LAER) for operations located in
nonattainment areas by providing a
reference document for use in these
determinations. The reason is that the
process for developing standards of
performance 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 the standards of performance.
The regulatory alternatives and the
environmental, energy, and economic
impacts of the standards of performance
were originally presented in
"Automobile and Light-Duty Truck
Surface Coating Operations—
Background Information for Proposed
Standards" (EPA-450/3-79-030) and
remain unchanged since proposal.
The standards of performance will
reduce emissions of VOC from new,
modified, or reconstructed automobile
and light-duty truck surface coating
operations by about 80 percent,
compared to operations controlled to
levels contained in SIPs existing at the
end of 1978. National emissions of VOC
will be reduced by about 4,800
megagrams per year by 1983 based on
the projection that four new assembly
plants are planned by that year.
Water pollution impacts of the
standards will be relatively small
compared to the volume and quality of
the wastewater discharged from plants
meeting 1978 SIP levels. The standards
are based on the use of waterborne
coating materials. These materials will
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-borne surface coating
materials.
The solid waste impact of the
promulgated standards will be negligible
compared to the amount of solid waste
generated by existing assembly plants.
The solid waste generated by
waterborne coatings, however, is very
sticky and equipment cleanup is more
time-consuming than for solvent-borne
coatings. Solid wastes from waterborne
coatings will not present any special
disposal problems since they can be
disposed of by conventional landfill
procedures.
National energy consumption will be
increased by the use of waterborne
coatings to comply with the standards.
The equivalent of an additional 18,000
barrels of fuel oil will be consumed per
year at a typical assembly plant. This is
an increase of about 25 percent in the
energy consumption of a typical
automobile surface coating operation.
National energy consumption will 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 impacts presented
here are based on the use of waterborne
coatings which will require extensive air
conditioning in the affected facilities to
meet temperature and humidity
requirements. High solids coatings,
while promising, are not yet adequately
demonstrated to be used as the basis of
the standards. However, to the extent
new facilities comply with the standards
through the use of higher solids content
coatings, improved transfer efficiencies,
and the use of incineration, with heat
recovery, the energy impacts will be less
than presented here.
The standards will 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
assembly plants planned by 1983 will be
increased by approximately $19 million
as a result of the standards. These
incremental costs represent about 0.2
percent of the $10 billion planned for all
capital expenditures. The corresponding
annualized costs will be increased by
approximately $9 million in 1983. The
price of an automobile or light-duty
truck will be increased by less than 0.1
percent when spread over the
manufacturer's entire production. The
Administrator considers this increase a
reasonable control cost.
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 September 27 and
28,1977. 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 in the
Federal Register on October 5,1979.
Public comments were solicited at that
time and copies of the Background
Information Document (BID) were •
distributed to interested parties. The
public comment period extended from
October 5,1979, to December 14,1979.
with a public hearing on November 9,
1979.
In addition to five presentations at the
public hearing, seventeen comment
letters were received on the proposed
standards of performance and on the
two proposed reference methods,
Methods 24 and 25, which were
promulgated on October 3,1980 (45 FR
65956). These comments have been
carefully considered and, where
determined to be appropriate, changes
have been made.
Significant Comments and Changes to
the Proposed Standards
Comments on the proposed standards
were received from automobile and
light-duty truck manufacturers, coatings
manufacturers, trade and professional
associations, State air pollution control
agencies, and Federal agencies. While a
number of changes were made in the
standards since proposal, the affected
facilities, control techniques on which
the standards are based, and the
impacts remain as presented in the BID
for the proposed standards. Detailed
discussions of these comments can be
found in the BID for the promulgated
standards. The major comments have
been combined into the following areas:
General, Emission Control Technology,
Economic Impacts, Legal
Considerations, and Reference Methods
and Monitoring.
General
The proposed standards exempted
certain specific changes which may
occur in an existing facility from being
considered a modification. One
commenter requested that "Engineering
Design Changes" be added to the list of
exemptions to provide for those minor
changes made during the model year to
improve quality or performance of the
finished product.
No changes were made in the
standards as a result of this comment.
While requested, data were not received
defining the term "Engineering Design
Changes." EPA, therefore, re-examined
the available, data. Under § 60.397,
changes in the application of coatings to
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Federal Register / Vol. 45, No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
increase coating film thickness are
already exempted. In addition, minor
operational changes which could
include design changes are allowed as
long as emissions are not increased.
Therefore, EPA has concluded that
sufficient relief is already provided in
the standards and "engineering design
changes" will not specifically be
exempted.
Similarly, changes made to comply
with SIP requirements were requested
by one commenter to be added to the
list of exemptions.
Changes to an existing facility made
to comply with a SIP should reduce
emissions rather than increase them.
Therefore, it also would not be
considered a modification. If a SIP-
required change is significant enough to
be considered as a reconstruction in
accordance with provisions of § 60.15,
the standards would apply only if it is
determined to be technically and
economically feasible.
One commenter stated that the
transfer efficiency for waterborne air
atomized spray was measured to be 36
percent instead of 40 percent at a new
plant and that this value should be used
as the basis for the standards.
At the time the standards were
proposed, the volume of coating material
required for line purging during color
changes in a topcoat operation was not
considered to have a significant impact
on transfer efficiency. Recent tests
conducted by the commenter and
submitted in support of his position have
indicated that line purging does have an
impact. However, the same tests also
indicated the technology is available to
control this source of VOC emission by
collecting the purge material or by
incorporating design and operational
changes to the spray system, thereby
increasing transfer efficiency. After
evaluating and discussing these data
with the commenter, EPA agrees that
changes to the proposed standards
should be made. The baseline transfer
efficiency for air atomized spray
systems for waterborne coatings without
purge after each vehicle on which the
emission limits for guide coat operations
were established has been changed from
40 percent to 39 percent. The
corresponding baseline transfer
efficiency for air atomized spray
systems for waterborne coatings with
partial purge and partial purge capture
on which the emission limits for topcoat
operations were established has been
changed from 40 to 37 percent. As a
result, the emission limits have been
changed to 1.40 kilograms of VOC per
liter of applied coating solids from guide
coat operations, and 1.47 kilograms of
VOC per liter of applied coating solids
from topcoat operations.
In addition to the changes in the
emission limitations, changes were
made to the table of transfer efficiencies
in § 60.393. Separate transfer efficiencies
have been established for waterborne
and solvent-borne air atomized spray
systems since data indicate that higher
transfer efficiencies can be realized with
solvent-borne coatings. Also, because of
the significance of line purging, separate
tables of transfer efficiencies are now
established for systems which collect
100 percent of the purge material and for
systems which purge after each vehicle
and do not collect any of the purge
material. Provisions have also been
made to allow the use of appropriate
transfer efficiencies for systems which
employ partial purge capture.
A number of commenters requested
that the standards allow an exemption
for special paints and colors which may
be used in relatively small volumes
because an arithmetic average of all
coatings as required in the proposed
standards could result in values greatly
different than a volume weighted
average.
The proposed standards required that
an arithmetic average VOC content of
all topcoat materials be used in
determining emissions. This form of
averaging was originally believed to
provide a simple and reasonably
accurate approximation of the volume
weighted average VOC content of the
coating materials actually used.
However, for many of the new paint
systems, a small percentage of the
colors accounts for a large percentage of
the paint used. Therefore, the arithmetic
average can be significantly different
from the weighted average. The
promulgated standards require that
compliance be demonstrated by a
performance test which involves the
calculation of the volume weighted
average mass of VOC per volume of
applied coating solids for each calendar
month. While this does not exempt
special paints and colors, it does allow
their use in small volumes with an
equitable impact on the overall average,
and therefore the concerns of the
commenters have been addressed.
Comments were received which
requested that the coating of plastic car
bodies and plastic components used on
metal car bodies be excluded from the
standards. Data provided by the
commenter indicated significant
problems associated with the use of
surface coatings designed for sheet
metal on plastic bodies or plastic body
components. These include the
increased incidence of ruptures and
delaminations in the plastic substrate
with the increased temperatures
required to cure waterborne coatings.
Similarly, the increased temperatures
associated with waterborne coatings
may cause defects in the materials used
to join plastic body components.
The objections raised by the
commenter were judged reasonable.
Since current industry practice is to coat
temperature sensitive plastic bodies and
body components on separate lines, the
standards have been changed to exclude
those operations. However, plastic body
components that are attached to the
metal body before it is coated do not
cause the coating operation of that body
to be excluded.
Emission Control Technology
Two commenters objected to the
weighted average method of determining
the VOC content of prime coat material
because of problems they anticipate
with "flow control" additives. Flow
control additives are added to an
electrodeposition (EDP) tank to maintain
or improve the application process and
are added on a periodic basis. The
commenters claim that flow control
additives should not be included when
determining the mass of VOC per
volume of applied coating solids
because flow control additives are not
added on a continuous basis. The
commenters contended that
determinations of VOC when flow
control additives are added will differ
greatly from periods when flow control
additives are not added.
The prime coat emission limit is based
on a volume of solids weighted average
VOC content of all makeup material
including flow control additives, added
to an EDP tank during one calendar
month. Flow control additives are high
in VOC content but are added only
periodically as stated by the commenter.
If a short time period (such as daily)
were used to calculate VOC emissions,
the effect of flow control additions could
be significant, causing wide daily
fluctuations. A longer averaging period
dampens these fluctuations. Information
supplied to EPA during the development
of these standards indicates that
makeup material including flow control
additives is available to meet an
emission limit of 0.16 kilograms of VOC
per liter of applied coating solids when
averaged over a calendar month.
Therefore, a monthly averaging period
and the proposed value, including flow
control additives, are appropriate.
Several commenters objected to the
prime coat emission limit, which is
equivalent to 1.2 pounds of VOC per
gallon of coating minus water, claiming
that such prime coat material is not
available.
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Federal Register / Vol. 45. No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
As indicated above, data from one
automobile manufacturer indicates that
prime coat material including flow
control additives is available and
operating experience demonstrates that
the emission limit established for prime
coat operations is achievable. Therefore,
the emission limit will not be changed.
Economic Impacts
Two commenters recommended that
separate standards be established for
modified or reconstructed plants due to
the differences in economic impacts.
If a physical or operational change
were made to an existing facility at an
automobile or light-duty truck plant
which would potentially increase VOC
emissions, the owner or operator could
implement changes necessary to hold
VOC emissions at or below the previous
level so as not to be subject to the
promulgated standards. This course of
action would be less costly to the plant
than implementing control strategies to
meet the promulgated new source
performance standards. This reduction
in emissions could be accomplished by
switching to a lower VOC content
coating or by incineration of a portion of
the VOC emission stream. Both of these
options are available to all plants and
are reasonable.
Although it is unlikely to happen, if an
existing facility is modified and is
required to meet the limits of the NSPS,
the cost of implementing control
strategies to meet the standards would
be more costly but would still be
affordable. Some existing plants may
not be able to use the full range of
control options because of physical
constraints. For example, an existing
enamel plant may not have enough room
in its existing spray booths to use
waterborne coatings. The enamel booths
are shorter than the ones required for
waterborne coatings. Nevertheless, the
enamel plant has other options such as
use of higher solids enamels and
incineration which would be available
to all such plants.
Control options that are affordable
are available to all existing plants to
reduce emissions to pre-modification
levels or to meet the levels of the
promulgated standards; therefore, the
development of separate standards for
modifications is not justified.
Under } 60.15 if physical or
operational changes were made to an
existing plant and 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, and it is
technologically and economically
feasible to meet the standards, the
changes would qualify as a
reconstruction. During development of
the standards, EPA found that the
capital cost of a new coating facility is
approximately $30,000,000 (average of
solvent-borne enamel and lacquer
systems) and that the capital cost of
implementing the standards is
approximately $750.000 for that facility.
In the extreme situation under
reconstruction where the cost of a
reconstructed facility would be
$15,000,000, or 50 percent of the cost of a
new facility, the cost of implementing
the standards would still be $750,000 or
0..5 percent of the capital cost of the
facility. The Administrator believes that
this cost is not unreasonable and that
relief is provided for a source in unusual
financial stiuations through § 60.15
which requires that it be economically
feasible for a reconstructed source to
meet the applicable standards.
Therefore, separate standards for
reconstructed plants are not justified.
The promulgated standards will apply to
modified and reconstructed facilities as
well as new facilities.
Legal Considerations
One commenter suggested that EPA
should develop criteria to identify
innovative control technologies for
which "innovative waivers" may be
granted.
On October 31,1979, the White House
issued a fact sheet on the President's
Industrial Innovation Initiatives.
Included in this fact sheet is a directive
for the EPA Administrator to develop
and publicize a clear implementation
policy and set of criteria for the award
of "innovative waivers" and to "assess
the need for further regulatory
authority." EPA is committed to carrying
out this directive, and therefore the
Administrator has requested that the
Office of Enforcement initiate an
implementation policy regarding the
award of innovative technology
waivers.
EPA will consider, but is not
committed to, the commenter's request
for specific innovative control
technology criteria or procedures for
issuing waivers for automobile and
light-duty truck surface coating
operations; EPA's decision will, in part,
depend upon the outcome of the
development of general criteria for
innovative technology waivers.
Until the innovative control
technology criteria! are issued, EPA will
continue to handle Section lll(j) waiver
requests on a case-by-case basis.
Reference Methods and Monitoring
The two reference methods, Methods
24 and 25, were proposed along with the
proposed standards for automobile and
light-duty truck surface coating
operations. Subsequently, these methods
have been promulgated separately from
these standards on Oct. 3,1980 (45 FR
65956).
A revised version of the proposed
Method 24 (Candidate 2) has been
promulgated as the method to determine
data used in the calculation of the VOC
content of coatings. Procedures have
been added to Method 24 to ensure that
analytical data fall within established
precision limits. In addition, the
laboratory procedure for determining
volume fraction of solids has been
eliminated. Method 24 now requires
volume fraction of solids be calculated
from the coatings manufacturers'
formulation data.
Changes to Method 25 include the
new requirement of a performance test
prior to use of analytical equipment. In
addition, routine daily calibrations have
been modified to be less time-
consuming. Finally, minimum
performance specifications for
components of analytical equipment
have been specified.
The detailed comments and responses
regarding Methods 24 and 25 are
presented in "Reference Methods 24 and
25—Background Information for
Promulgated Test Methods" (EPA-450/
3-79-030c).
In addition, one commenter
recommended that Method 2 should not
be specifically required and that a
manifold system should be permitted for
mixing and collecting a combined
sample for multiple stacks in lieu of
sampling each stack separately.
Method 2 requires that the volumetric
flow rate be measured at the traverse
points specified by Method 1. For new
sources, provisions can be made during
the design stage to allow for the proper
location of the sampling ports which
would be required. For reconstructed or
modified sources where the standards
may be applicable, the owner or
operator can install stack extensions or
use an increased number of traverse
points as specified in Method 1.
Therefore, the requirement to use
Method 2 to measure the volumetric
flow rate is reasonable and will not be
changed.
In principle, a manifold system is
acceptable. However, since many
details are involved in designing an
acceptable manifold system, approval of
such a sampling technique will be made
if the owner or operator can show to the
Administrator's satisfaction that the use
of a manifold system yields results
comparable to those obtained by testing
all stacks.
Several commenters stated opposition
to the requirement dealing with the
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Federal Register / Vol. 45, No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
monitoring of incinerators which are
used to control VOC emissions. These
commenters stated that the required
accuracy of the temperature monitoring
device (±2°C or ±3.5°F) was too
restrictive.
Data solicited by EPA from
incinerator and temperature monitor
vendors confirm that at the high
temperatures 760-820°C (1400-1500T) at
which these incinerators operate, the
required accuracy was too restrictive.
As a result, it has been changed to the
greater of ±0.75 percent of the
temperature being measured expressed
in degrees Celsius or ±2.5°C (±4°F).
Reports Impact Analysis
A reports impact analysis for the
automobile and light-duty truck surface
coating operations standards was
prepared in implementation of Executive
Order 12044 (44 FR 30988, May 29,1979).
The purpose of the analysis is to
estimate the economic impact of the
reporting and recordkeeping
requirements that would be imposed by
the promulgated standards and by those
appearing in the General Provisions of
430 CFR Part 60. The standards would
require the preparation of three types of
reports. First, the General Provisions
(Subpart A of 40 CFR 60) would require
notification reports which inform the
Agency of facilities subject to new
source performance standards (NSPS).
These reports include notification of
construction, anticipated start-up, actual
start-up, and physical or operational
changes. Second, reports of the results
of the performance test performed each
calendar month would be required for
those months when the affected facility
is not in compliance with the standards.
Third, quarterly reports from the owner
or operator of a facility using
incineration devices to comply with the
standard would be required for periods
when incinerator temperature falls
below that measured during the
incinerator's most recent performance
test. These reports will show whether
these devices are being properly
operated and maintained.
The respondent group to the reporting
requirements of the standards would be
the automobile and light-duty truck
manufacturing industry. It is estimated
that through the fifth year of standards
applicability, approximately four new,
modified, or reconstructed assembly
plants will have been established which
would have to comply with the reporting
requirements of the standards. To
implement the reporting requirements of
the standards through the first five years
of applicability the automobile and light-
duty truck manufacturing industry
would incur a manpower demand of
about six man-years.
A copy of the Reports Impact
Analysis is included in subcategory IV-J
of the automobile and light-duty truck
surface coating operations docket A-79-
05.
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
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 comments, the
contents of the docket will serve as the
record in case of judicial review.
[Section 307 (d)(a)|.
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. Comments
were requested specifically on Method
24 (Candidate 1 and Candidate 2) and
on 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)ll)|.
Although emission control technology
may be available that can reduce
emission 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" (LAER) 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, SIPs 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, SIPs 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
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Federal Register / Vol. 45. No. 249 / Wednesday. December 24. 1960 / Rules and Regulations
aware of this possibility in planning for
such facilities.
This regulation will be reviewed 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,
improvements in emission control
technology, and reporting requirements.
The reporting requirements in this
regulation will be reviewed as required
under EPA's sunset policy for reporting
requirements in regulations.
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 standards
and for other regulatory alternatives. All
aspects of the assessment were
considered in the formulation of the
standards to ensure that the
promulgated standards would represent
the best system of emission reduction
considering costs. The economic impact
assessment is included in the BID for the
proposed standards.
Dated: December 17,1980.
Douglas M. Costle,
Administrator
40 CFR Part 60 is amended as follows:
1. By adding 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 which is
measured by a reference method, an
equivalent method, an alternative
method, or which is determined by
procedures specified under any subpart.
2. By adding 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 Performance test and compliance
provisions.
60.394 Monitoring of emissions and
operations.
60.395 Reporting and recordkeeping
requirements.
60.396 Reference methods and procedures.
60.397 Modifications.
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.
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
assembly plant: each prime coat
operation, each guide coat operation,
and each topcoat operation.
(b) Exempted from the provisions of
this subpart are operations used to coat
plastic body components or all-plastic
automobile or light-duty truck bodies on
separate coating lines. The attachment
of plastic body parts to a metal body
before the body is coated does not cause
the metal body coating operation to be
exempted.
(c) The provisions of this subpart
apply to any affected facility identified
in paragraph (a) of this section that
begins construction, reconstruction, or
modification after October 5,1979.
§ 60.391 Definitions.
(a) 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.
"Applied coating solids" means the
volume of dried or cured coating solids
which is deposited and remains on the
surface of the automobile or light-duty
truck body.
"Automobile" means a motor vehicle
capable of carrying no more than 12
passengers.
"Automobile and light-duty truck
body" means the exterior surface of an
automobile or light-duty truck including
hoods, fenders, cargo boxes, doors, and
grill opening panels.
"Bake oven" means a device that uses
heat to dry or cure coatings.
"Electrodeposition (EDP)" means a
method of applying a prime coat by
which the automobile or light-duty truck
body is submerged in a tank filled with
coating material and an electrical field
is used to effect the deposition of the
coating material on the body.
"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.
"Flash-off area" means the structure
on automobile and light-duty truck
assembly lines between the coating
application system (dip tank or spray
booth) and the bake oven.
"Guide coat operation" means the
guide coat spray booth, flash-off area
and bake oven(s) which are used to
apply and dry or cure a surface coating
between the prime coat and topcoat
operation on the components of
automobile and light-duty truck bodies.
"Light-duty truck" means any motor
vehicle rated at 3,850 kilograms gross
vehicle weight or less, designed mainly
to transport property.
"Plastic body" means an automobile
or light-duty truck body constructed of
synthetic organic material.
"Plastic body component" means any
component of an automobile or light-
duty truck exterior surface constructed
of synthetic organic material.
"Prime coat operation" means the
prime coat spray booth or dip tank,
flash-off area, and bake oven(s) which
are used to apply and dry or cure the
initial coating on components of
automobile or light-duty truck bodies.
"Purge" or "line purge" means the
coating material expelled from the spray
system when clearing it.
"Solvent-borne" means a coating
which contains five percent or less
water by weight in its volatile fraction.
"Spray application" means a method
of applying coatings by atomizing the
coating material and directing the
atomized material toward the part to be
coated. Spray applications can be used
for prime coat, guide coat, and topcoat
operations.
"Spray booth" means a structure
housing automatic or manual spray
application equipment where prime
coat, guide coat, or topcoat is applied to
components of automobile or light-duty
truck bodies.
"Surface coating operation" means
any prime coat, guide coat, or topcoat
operation on an automobile or light-duty
truck surface coating line.
"Topcoat operation" means the
topcoat spray booth, flash-off area, and
bake oven(s) which are used to apply
and dry or cure the final coating(s) on
components of automobile and light-
duty truck bodies.
"Transfer efficiency" means the ratio
of the amount of coating solids
transferred onto the surface of a part or
product to the total amount of coating
solids used.
"VOC content" means all volatile
organic compounds that are in a coating
expressed as kilograms of VOC per liter
of coating solids.
"Waterborne" or "water reducible"
means a coating which contains more
than five weight percent water in its
volatile fraction.
(b) The nomenclature used in this
subpart has the following meanings:
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Federal Register / Vol. 45, No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
C,u = concentration of VOC (as carbon) in the
effluent gas flowing through stack (j)
leaving the control device (parts per million
by volume).
CM = concentration of VOC (as carbon) in the
effluent gas flowing through stack (i)
entering the control device (parts per
million by volume),
Cm = concentration of VOC (as carbon) in the
effluent gas flowing through exhaust stack
(k) not entering the control device (parts
per million by volume).
Dcl = density of each coating (i) as received
(kilograms per liter).
Djj = density of each type VOC dilution
solvent (j) added to the coatings, as
received (kilograms per liter),
Dr = density of VOC recovered from an
affected facility (kilograms per liter).
E = VOC destruction efficiency of the control
device,
F = fraction of total VOC which is emitted by
an affected facility that enters the control
device.
G = volume weighted average mass of VOC
per volume of applied solids (kilograms per
liter).
LC, = volume of each coating (i) consumed, as
received (liters),
Lci'/= volume of each coating (i) consumed by
each application method (1), as received
liters),
1-4, = volume of each type VOC dilution
solvent (j) added to the coatings, as
received (liters),
L, = volume of VOC recovered from an
affected facility (liters),
U = volume of solids in coatings consumed
(liters).
M
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Federal Register / Vol. 45, No. 249 / Wednesday, December 24. 1980 / Rules and Regulations
(c) Select the appropriate transfer
efficiency (T) from the following tables
for each surface coating operation:
Application Method
Transfer
efhciencv
Air Atomized Spray (walertaorne coating)
Air Atomized Spray (sorvenl-borne costing)..
Manual Electrostatic Spray
Automatic Electrostatic Spray
Etectrodeposrtion
0.39
0.50
0.75
0.95
1.00
The values in the table above represent
an overall system efficiency which
includes a total capture of purge. If a
spray system uses line purging after
each vehicle and does not collect any of
the purge material, the following table
shall be used:
Application Method
Transfer
otftdoncy
Air Atomized Spray (watertwrne coating)
Air Atomized Spray (sotvent-bome coating)..
Manual Electrostatic Spray
Automatic Electrostatic Spray
0.30
0.40
0.62
0.75
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.
(1) When more than one application
method (/) is used on an individual
surface coating operation, the owner or
operator shall perform an analysis to
determine an average transfer efficiency
by the following equation where "n" is
the total number of coatings used and
"p" is the total number of application
methods:
T =
n
1=1
Vsi Lcu
(D) Calculate the volume weighted
average mass of VOC per volume of
applied coating solids (C) during each
calendar month for each affected facility
by the following equation:
G =
LsT
(ii) If the volume weighted average
mass of VOC per volume of applied
coating solids (C), calculated on a
calendar month basis, is less than or
equal to the applicable emission limit
specified in § 60.392. the affected facility
is in compliance. Each monthly
calculation is a performance test for the
purpose of this subparl.
(2) The owner or operator shall use
the following procedures for each
affected facility which uses a capture
system and a control device that
destroys VOC (e.g., incinerator) to
comply with the applicable emission
limit specified under § 60.392.
(i) Calculate the volume weighted
average mass of VOC per volume of
applied coating solids (C) during each
calendar month for each affected facility
as described under § 60.393(c)(l)(i).
(ii) Calculate the volume weighted
average mass of VOC per volume of
applied solids emitted after the control
device, by the following equation:
N = G[1-FE]
(A) Determine the fraction of total
VOC which is emitted by an affected
facility that enters the control device by
using the following equation where "n"
is the total number of stacks entering the
control device and "p" is the total
number of stacks not connected to the
control device:
F =
'bl
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Federal Register / Vol. 45, No. 249 / Wednesday, December 24, 1980 / Rules and Regulations
(ii) Calculate the total volume of
coating solids (Ls) used in each calendar
month for each affected facility as
described under § 60.393(c)(l)(i).
(iii) Calculate the mass of VOC
recovered (Mr) each calendar month for
each affected facility by the following
equation: Mr=LrDr
(iv) Calculate the volume weighted
average mass of VOC per volume of
applied coating solids emitted after the
control device during a calendar month
by the following equation:
LsT
(v) If the volume weighted average
mass of VOC per volume of applied
solids emitted after the control device
(N) calculated on a calendar month
basis is less than or equal to the
applicable emission limit specified in
§ 60.392, the affected facility is in
compliance. Each monthly calculation is
a performance test for the purposes of
this subpart.
§ 60.394 Monitoring of omloolons and
operations.
The owner or operator of an affected
facility which uses an incinerator to
comply with the emission limits
specified under § 60.392 shall install,
calibrate, maintain, and operate
temperature measurement devices as
prescribed below:
(a) Where thermal incineration is
used, a temperature measurement
device shall be installed in the firebox.
Where catalytic incineration is used, a
temperature measurement device shall
be installed in the gas stream
immediately before and after the
catalyst bed.
(b) Each temperature measurement
device shall be installed, calibrated, and
maintained according to accepted
practice and the manufacturer's
specifications. The device shall have an
accuracy of the greater of ±0.75 percent
of the temperature being measured
expressed in degrees Celsius or ±2.5° C.
jf] Each temperature measurement
device shall be equipped with a
recording device so that a permanent
record is produced.
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 74140))
§ 60.395 Reporting and recordtteeping
requirementc.
(a) Each owner or operator of an
affected facility shall include the data
outlined in subparagraphs (1) and (2) in
the initial compliance report required by
§60.8.
(1) The owner or operator shall report
the volume weighted average mass of
VOC per volume of applied coating
solids for each affected facility.
(2) Where compliance is achieved
through the use of incineration, the
owner or operator shall include the
following additional data in the control
device initial performance test requried
by § 60.8(a) or subsequent performance
tests at which destruction efficiency is
determined: the combustion temperature
(or the gas temperature upstream and
downstream of the catalyst bed), the
total mass of VOC per volume of
applied coating solids before and after
the incinerator, capture efficiency, the
destruction efficiency of the incinerator
used to attain compliance with the
applicable emission limit specified in
§ 60.392 and a description of the method
used to establish the fraction of VOC
captured and sent to the control device.
(b) Following the initial report, each
owner or operator shall report the
volume weighted average mass of VOC
per volume of applied coating solids for
each affected facility during each
calendar month in which the affected
facility is not in compliance with the
applicable emission limit specified in
§ 60.392. This report shall be
postmarked not later than ten days after
the end of the calendar month that the
affected facility is not in compliance.
Where compliance is achieved through
the use of a capture system and control
device, the volume weighted average
after the control device should be
reported.
(c) Where compliance with § 60.392 is
achieved through the use of incineration,
the owner or operator shall continuously
record the incinerator combustion
temperature during coating operations
for thermal incineration or the gas
temperature upstream and downstream
of the incinerator catalyst bed during
coating operations for catalytic
incineration. The owner or operator
shall report quarterly as defined below.
(1) For thermal incinerators, every
three-hour period shall be reported
during which the average temperature
measured is more than 28°C less than
the average temperature during the most
recent control device performance test
at which the destruction efficiency was
determined as specified under § 60.393.
(2) For catalytic incinerators, every
three-hour period shall be reported
during which the average temperature
immediately before the catalyst bed,
when the coating system is operational,
is more than 28° C less than the average
temperature immediately before the
catalyst bed during the most recent
control device performance test at
which destruction efficiency was
determined as specified under § 60.393.
In addition, every three-hour period
shall be reported each quarter during
which the average temperature
difference across the catalyst bed when
the coating system is operational is less
than 80 percent of the average
temperature difference of the device
during the most recent control device
performance test at which destruction
efficiency was determined as specified
under § 60.393.
(3) For thermal and catalytic
incinerators, if no such periods occur,
the owner or operator shall submit a
negative report.
(d) The owner or operator shall notify
the Administrator 30 days in advance of
any test by Reference Method 25.
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 7414))
§ 60.396 Reference methods and
procedures.
(a) The reference methods in
Appendix A to this part, except as
provided in § 60.8 shall be used to
conduct performance tests.
(1) Reference Method 24 or an
equivalent or alternative method
approved by the Administrator shall be
used for the determination of the data
used in the calculation of the VOC
content of the coatings used for each
affected facility. Manufacturers'
formulation data is approved by the
Administrator as an alternative method
to Method 24. In the event of dispute,
Reference Method 24 shall be the referee
method.
(2) Reference Method 25 or an
equivalent or alternative method
approved by the Administrator shall be
used for the determination of the VOC
concentration in the effluent gas
entering and leaving the emission
control device for each stack equipped
with an emission control device and in
the effluent gas leaving each stack not
equipped with a control device.
(3) The following methods shall be
used to determine the volumetric flow
rate in the effluent gas in a stack:
(i) Method 1 for sample and velocity
traverses,
(ii) Method 2 for velocity and
volumetric flow rate, .
(iii) Method 3 for gas analysis, and
(iv) Method 4 for stack gas moisture.
(b) For Reference Method 24, the - -
coating sample must be a 1-liter sample
taken in a 1-liter container.
V-465
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(c) For Reference Method 25, the
sampling time for each of three runs
must be at least one hour. The minimum
sample volume must be 0.003 dscm
except that shorter sampling times or
smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator. The
Administrator will approve the sampling
of representative stacks on a case-by-
case basis if the owner or operator can
demonstrate to the satisfaction of the
Administrator that the testing of
representative stacks would yield
results comparable to those that would
be obtained by testing all stacks.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
§ 60.397 Modifications.
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 coating film
thickness.
|FR Doc. 80-40146 Filed 12-23-80: 8:45 am|
125 40 CFR Part 60
IAD-FRL-1623-5]
Review of Standards of Performance
for New Stationary Sources: Coal
Preparation Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for coal
preparation plants (41 PR 2232). 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 June 15,1981.
ADDRESS: Comments. Send comments to
the Central Docket Section. (A-130). U.S.
Environmental Protection Agency, 401M
Street. S.W., Washington, D.C. 20460,
Attention: Docket No. A-80-26.
Background Information Document.
The document "A Review of Standards
of Performance for New Stationary
Sources—Coal Preparation Plants" (EPA
report number EPA-450/3-80-022] is
available upon request from the U.S.
EPA Library (MD-35), Research Triangle
Park, N.C. 27711, telephone (919) 541-
2777.
Docket. Docket No. A-80-26,
containing supporting information used
in reviewing the standards, 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, West Tower Lobby, Gallery 1,
Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460. A reasonable
fee may be charged for copying.
FOR FURTHER INFORMATION CONTACT:
Mr Stanley T. Cuffe (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, N.C. 277711;
telephone (919) 541-5595.
SUPPLEMENTARY INFORMATION:
Background
As prescribed by Section 111.
proposal of standards of performance
for coal preparation plants was
preceded by the Administrator's
determination that these plants
contribute significantly to air pollution
which causes or contributes to the
endangerment of public health or
welfare and by his publication of this
determination in the Federal Register.
Coal preparation plants were selected
for the development of standards based
primarily on the expectation of
increased demand for coal and the
beneficial impact which would result
from the application of best technology
for air pollution control. Coal
preparation plants were recommended
for consideration for standards in the
"Report of the Committee on Public
Works," U.S. Senate, September 17.
1970, and named as a major source of air
pollution in 40 CFR Part 52, "Prevention
of Significant Air Quality Deterioration,"
as proposed in the Federal Register,
August 27,1974, (39 FR 31000). The
recent emphasis on coal as a long-term
source of fossil fuel energy will lend
additional impetus to the growth of the
coal preparation industry.
On October 24.1974 (39 FR 37922),
under Section 111 of trie Clean Air Act,
as amended, the Administrator
proposed standards of performance for
the following affected facilities within
the coal preparation industry: thermal
dryers, pneumatic coal cleaning
equipment (air tables), coal processing
and conveying equipment (including
breakers and crushers), screening
(classifying) equipment, coal storage
and coal transfer points, and coal
loading facilities.
The regulation, promulgated on
January 15,1976, (41 FR 2232), covers
sources handling more than 200 tons per
day, and applies the following
participate concentration limits and
opacities: thermal dryers, 0.070 g/dscm
(0.031 gr/dscf) and less than 20 percent
opacity; pneumatic coal cleaning
equipment, 0.040 g/dscm (0.018 gr/dscf)
and less than 10 percent opacity. The
regulation also limits to less than 20
percent the opacities of emissions from
coal processing and conveying
equipment, coal storage systems, and
coal transfer and loading systems.
The Clean Air Act Amendments of
1977 require that the Adminstrator 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)]. This
notice announces that EPA has
completed a review of the standards of
performance for coal preparation plants
and invites comment on the results of
this review.
Under Executive Order 12291. EPA is
required to judge whether a regulation is
a "major rule" and therefore subject to
certain requirements of the Order. The
Agency has determined that this
regulation would result in none of the
adverse economic effects set forth in
Section 1 of the Order as grounds for
finding a regulation to be a "major rule".
In fact, this action would impose no
additional regulatory requirements
because the Agency has decided not to
undertake revision of the standards for
coal preparation plants at this time. This
V-466
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Federal Register / Vol. 46. No. 71 / Tuesday. April 14, 1981 / Rules and Regulations
decision is based upon the fact that
there has been no change in the type
and performance of control systems for
this industry since promulgation of new
source performance standards.
Findings
Industry Growth Rate
In 1974, there were approximately 390
coal preparation plants operating in the
United States. In 1979, there were about
490 such plants. By 1985, it is estimated
that about 40 new or modified facilities
will have been added.
In spite of the growth in the coal
cleaning industry, the number of thermal
dryers in the United States has declined
from 184 in 1972 to 114 in 1977. Many
hew plants use centrifugal-type
mechanical dryers which require no fuel
and are therefore less expensive than
thermal dryers. Seventeen thermal
dryers (only about 35 percent of the
number that EPA projected in 1974) have
been constructed since the standards of
performance became effective.
The use of air tables (pneumatic coal
cleaning) was projected to decline in
1974, but the standard was set because
they were still available from equipment
vendors and could have been installed
without participate control in the
absence of a performance standard.
Although three such facilities have been
constructed since the standards of
performance became effective, there has
been a net decline in total number of
facilities within the s.. me time period.
Emissions and Control Technology
Current Particulate, Control Technology
The best available control technology
for thermal dryers is still a centrifugal
(cyclone) collector followed by a high
efficiency venturi aqueous scrubber. The
best control for pneumatic coal cleaning
equipment is the centrifugal collector
followed by fabric filtration. No
improvements on these control
techniques have been demonstrated.
Fugitive emissions from coal
processing and conveying equipment,
coal storage systems, and coal transfer
and loading systems, are controlled by
wetting and by enclosing sources of
potential fugitive participate emissions.
Sulfur Dioxide Emissions
The use of venturi scrubbers to collect
particulate matter has the additional
benefit of removing most of the sulfur
dioxide. Limited source test data
indicate sulfur dioxide emissions of less
than 10 percent of theoretical. Sulfur
dioxide emissions from the venturi
scrubbers do not appear to be
significant.
Emerging Control Technology
No promising new particulate control
techniques have been demonstrated
since promulgation of the standards of
performance for coal preparation plants.
Standards of performance for coal
cleaning do not apply to lignite and sub-
bituminous coals prevalent in the West
These fuel seams are relatively low in
gross impurities, and preparation has
historically been limited to crushing
sufficiently to allow handling.
Coals contain varying amounts of
sulfur in the form of pyrites and
chemically-bound sulfur. Coal cleaning
removes some pyrites, but little or no
chemical sulfur. The removal of
chemical sulfur from coal is being
investigated, but no practical process is
yet demonstrated.
Results Achievable With Demonstrated
Control Technology
Three pneumatic coal cleaning
, systems have been constructed and
tested under the new source
performance standards. All were in
compliance, with particulate emissions
ranging from 0.011 to 0.022 g/dscm (0.005
to 0.010 gr/dscf.)
The thermal dryers which have
achieved compliance have had
particulate emissions ranging from 0.010
to 0.070 g/dscm (0.007 to 0.031 gr/dscf).
There has been general compliance
with the fugitive emission opacity limits
from coal processing and conveying
equipment, coal storage systems, and
coal transfer and loading systems.
Conclusions
Based upon this review of the
standards of performance for coal
cleaning, the following conclusions were
reached:
1. Existing standards of performance
for pneumatic coal cleaning and thermal
drying systems are based on fabric
filters and high-pressure-drop aqueous
venturi scrubbers, respectively. Because
there has been no change in the type
and performance of control systems for
these sources since promulgation, the
existing standards are still appropriate.
2. Emission tests of thermal dryers
fired by sulfur-containing coals show
that only minor quantities of SOa escape
the water scrubbers that were installed
to control particulate emissions.
Therefore, added regulations to limit
SO. emissions are not necessary.
3. The existing standards of
performance do not apply to coal
unloading stations. EPA plans to
investigate the need and the technology
to regulate these sources of potential
fugitive emissions.
Dated: April 8,1981.
Walter C. Barber,
Acting Administrator.
| FR Do,:. 81 - II274 Filed 4-1 J-«l: MS an)
126
40 CFR Parts 60 and 61
[A-7-FRL-1830-2]
New Source Performance Standards;
Delegation of Authority to the State of
Missouri and Addition of Address
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rulemaking.
SUMMARY: The Missouri Department of
Natural Resources (MDNR) has been
delegated authority to implement and
enforce the federal New Source
Performance Standards (NSPS)
regulations for 30 stationary source
categories and national emission
standards for five hazardous air
pollutants. Notification of this
delegation is published today elsewhere
in the Federal Register. This document
adds the address of the MDNR to which
all reports, requests, applications,
submittals, and communications to the
Administrator, as required by 40 CFR
Part 60 and 40 CFR Part 61, must also be
addressed.
EFFECTIVE DATE: May 19,1981.
FOR FURTHER INFORMATION CONTACT
Mr. Charles W. Whitmore, Air, Noise
and Radiation Branch. U.S.
Environmental Protection Agency,
Region VII, 324 E. llth Street, Kansas
City, Missouri 64106, (816) 374-6525; FTS
758-6525.
SUPPLEMENTARY INFORMATION: The
MDNR has been delegated authority to
implement and enforce the federal New
Source Performance Standards (NSPS)
regulations for 30 stationary source
categories and national emission
standards for five hazardous air
pollutants. Notification of this
delegation is published today elsewhere
in the Federal Register. The amended 40
CFR 60.4(b)(AA), and 40 CFR
61.04(b)(AA) adds the address of the
MDNR to which all reports, requests,
applications, submittals, and
communications to the Administrator, as
required by 40 CFR Part 60 and 40 CFR
Part 61. must also be addressed.
V-467
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Federal Register / Vol. 46. No. 101 / Wednesday. May 27. 1981 / Rules and Regulations
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
burdens are imposed upon the parties
affected.
The delegation which influenced this
Administrative amendment was
effective on December 16,1980, and it
serves no purpose to delay the technical
change of this address in 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.
§ 7412.
Dated: May 4,1981.
William W. Rice
Acting Regional Administrator. Region VII.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
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 (AA) to read
as follows:
§60.4 Address.
*****
(b) * * *
(AA) Missouri Department of Natural
Resources, Post Office Box 1366.
Jefferson City, Missouri 65101.
127
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[A-3-FRL 1823-1]
Standards of Performance for New
Stationary Sources; Delegation of
Authority to the State of Delaware
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends EPA'e
regulations (40 CFR 60.4) to reflect
delegation of authority to the State of
Delaware to implement and enforce
certain standards of performance for
new stationary sources. This delegation
is based on a request from the State of
Delaware that it be given this
enforcement authority.
IFFECTIVE DATE May 27,1981.
FOR FURTHER INFORMATION CONTACT:
Ben Mykijewycz, Environmental
Engineer, Air Enforcement Branch,
Environmental Protection Agency,
Region III, 6th and Walnut Streets,
Philadelphia, Pennsylvania 1910S.
Telephone (215) 597-9367.
SUPPLEMENTARY INFORMATION:
I. Background
On December 23.1980, the State of
Delaware requested delegation of
authority to implement and enforce
certain standards of performance for
new stationary sources for electric
utility steam generating units for which
construction is commenced after
September 18,1978. The request was
reviewed and on April 27,1981 a letter
was sent to John E. Wilson III.
Secretary, Department of Natural
Resources and Environmental Control,
approving the delegation and outlining
its conditions. The approval letter
specified that if 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 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 in today's
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, as set forth below.
III. General
The Administrator finds good cause
for forgoing 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 May 11.
1981, 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.
Under Executive Order 12291, EPA
must judge whether a regulation is
"Major" and therefore subject to the
requirement of a Regulatory Impact
Analysis. This regulation is an
administrative change and is not a
major rule because it is not likely to
result in:
An annual effect on the economy of
$100 million or more;
A major increase in costs or prices for
consumers, individual industries,
Federal, State, or local government
agencies, or geographic regions; or
Significant adverse effects on
competition, employment, investment.
productivity, innovation, or on the
ability of United States-based
enterprises to compete with foreign-
based enterprises in domestic or export
markets.
This regulation was submitted to the
Office of Management and Budget for
review as required by Executive Order
12291.
(42 U.S.C. 7411)
Dated: April 27.1981.
Thomas C. Voltaggio.
Acting Director. Enforcement Division.
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In j 60.4. paragraph (b) is amended
by revising subparagraph (I) to read as
follows:
§ 60.4 Address.
« • * * •
o>r • •
(I) State of Delaware (for fossil fuel-
fired steam.generators; incinerators:
nitric acid plants: asphalt concrete
plants: storage vessels for petroleum
liquids; sulfuric acid plants; sewage
treatment plants; and electric utility
steam generating units). Delaware
Department of Natural Resources and
Environmental Control, Edward Tatnall
Building. Dover, Delaware 19901.
|FR Our. B1-15B13 Filed S-26-«1: &4S im|
MU.INO COM eMO-a»4i
V-468
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128
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 60 and 61
tA-4-Fm.-IUO-a]
Air Pollution; New Source Review;
Delegation of Authority to the State of
Tennessee
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The amendments below
institute certain address changes for
reports and applications required from
operators of certain sources subject to
Federal regulations. EPA has delegated
to the State of Tennessee authority to
review new and modified sources. The
delegated authority includes the review
under 40 CFR Part 60 for the standards
of performance for new stationary
sources and review under 40 CFR Part
61 for national emission standards for
hazardous air pollutants. A notice
announcing the delegation of authority
is published in the Notices section of
this issue of the Federal Register. These
amendments provide that all reports,
requests, applications, submittals, and
communications previously required for
the delegated reviews will now be sent
to the Division of Air Pollution Control,
Tennessee Department of Public Health,
256 Capitol Hill Building, Nashville,
Tennessee 37219.
EFFECTIVE DATE: April 11,1980.
POM FURTHER INFORMATION CONTACT:
Mr. Raymond S. Gregory, Air Programs
Branch. Environmental Protection
Agency, Region IV, 345 Courtland Street
N.E.. Atlanta, Georgia 30366, phone 404/
881-3286.
SUPPLEMENTARY INFORMATION: The
Regional Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
Immediately in that it is an
admlnstrative 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 April 11,
1980, and it serves no purpose to delay
the technical change of this addition of
the state address to the Code of Federal
Regulations.
The Office of Management and Budget
has exempted this regulation from the
OMB review requirements of Executive
Order 12291 pursuant to Section 8(b) of
that order.
(Sec*. 101.110. 111. 112. 301. Clean Air Act. as
amended. (42 U.S.C. 7401.7410. 7411.7412.
7801))
Dated: May 8, 1981.
Acting Regional Administrator.
PART 60— STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter I, Title 40, Code of
Federal Regulations, Is amended as
follows:
In 8 60.4, paragraph (b) (RR) is added
as follows:
|60.4 Address.
* * * « *
(b) * * •
(RR) Division of Air Pollution Control.
Tennessee Department of Public Health,
256 Capitol Hill Building. Nashville,
Tennessee 37219
V-469
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ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60 and 61
(A-7-FRL 1888-1]
New Source Performance Standards
and National Emission Standards for
Hazardous Pollutants; Delegation of
Authority to the State of Nebraska and
Change of Address
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rulemaking.
SUMMARY: The EPA is today amending
its regulations on standards of
performance for new stationary sources
of air pollution and National Emission
Standards for Hazardous Air Pollutants
(NESHAPS) to reflect a change of
address of the Nebraska Department of
Environmental Control (DEC) and the
Region VII office of the EPA, and to
reflect a delegation to the DEC of
NESHAPS.
EFFECTIVE DATE: July 31, 1981.
FOR FURTHER INFORMATION CONTACT:
Steve A. Kovac, Air, Noise and
Radiation Branch, U.S. Environmental
Protection Agency, Region VII, 324 East
llth Street, Kansas City, Missouri 64106;
816/374-6525; FTS 758-6525.
SUPPLEMENTARY INFORMATION: The DEC
has been delegated authority to
implement and enforce the federal New
Source Performance Standards (NSPS)
regulations for 25 stationary source
categories and national emission
standards for four hazardous air
pollutants. An original delegation of 12
source categories was published in the
Federal Register on December 30,1976.
A second delegation, affecting 13
additional source categories and four
hazardous air pollutants, is published
today elsewhere in the Federal Register.
The amended § 60.4(a) and § 61.04(a)
correct the address of the Region VII
office of the EPA. The amended § 60.4(b)
corrects the address of the DEC to
which all reports, requests, applications.
submittals, and communications to the
Administrator, as required by 40 CFR
Part 60, must also be submitted. The
amended 9 61.04(b) adds the address of
the DEC to which information to the
Administrator, as required by 40 CFR
Part 61, must also be submitted.
The Regional 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
burdens are imposed upon the parties
affected.
The delegation which influenced this
Administrative amendment was
effective on July 22,1981, and it serves
no purpose to delay the technical
change of this address in 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.
7412.
Under Executive Order 12291. EPA
must judge whether a rule is "major"
and, therefore, subject to the
requirements of a Regulatory Impact
Analysis. This rule is not a "major" rule,
because it only corrects and
supplements addresses to which sources
are required to submit reports under
existing requirements. Thus, it is
unlikely to have an annual effect on the
economy of $100 million or more or to
have other significant adverse impacts
on the national economy.
This rule was submitted to the Office
of Management and Budget (OMB) for
review as required by Executive Order
12291.
Dated: June 7,1981.
William W. Rice,
Acting Regional Administrator, Region VII.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
1. In § 60.4, paragraph (a) the address
for Region VII is revised:
960.4 Address.
(a) * * *
Region VII (Iowa, Kansas. Missouri,
Nebraska). 324 East llth Street, Kansas
City, Missouri 64106.
*****
2. In 9 60.4, paragraph (b) is amended
by revising paragraph (CC) to read as
follows:
960.4 Address.
* * * * ' *
(b)*"
(CC) State of Nebraska, Nebraska
Department of Environmental Control,
P.O. Box 94877, State House Station,
Lincoln, Nebraska 68509.
V-470
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Federal Register / Vol. 46. No. 195 / Thursday, October & 1981 / Rules and Regulations
130
40 CFR Parts 60 and 61
(A-ft-FRL-1875-2]
Standards of Performance for New
Stationary Sources (NSPS) and
National Emission Standards for
Hazardous Air Pollutants (NESHAPS);
Delegation of Authority to State of
California
AGENCY: Environmental Protection
Agency.
ACTION: Notice of final rulemaking.
SUMMARY: The Environmental Protection
Agency is amending its regulations on
Standards of Performance for New
Stationary Sources (NSPS) and the
National Emission Standards for
Hazardous Air Pollutants (NESHAPS).
The rules delegate authority to
implement and enforce the NSPS and
NESHAPS programs to 19 state and
local air pollution control agencies in
California. These delegations are being
issued under the Clean Air Act which
requires the Administrator to delegate
this type of authority to any State or
local agency that submits adequate
procedures for implementation and
enforcement.
DATES: The amendments to the list of
addresses of Air Pollution Control
Districts in 40 CFR 60.4(b)(F) and
61.04(b)(F) are effective October 8.1981.
Delegation of pollutant categories to
each Air Pollution Control District is
effective as of the date of delegation
shown in the table in J§60.4(b)(F)(l)
and61.04(F)(l).
POR FURTHER INFORMATION CONTACT:
David Solomon, Permits Branch,
Environmental Protection Agency,
Region 9, 215 Fremont Street, San
Francisco, CA 94105; Attn: E-4-2 (415)
556-8005.
SUPPLEMENTARY INFORMATION: Sections
lll(c) (NSPS) and 112(d) (NESHAPS) of
the Clean Air Act require the
Administrator of EPA to delegate
authority to implement and enforce
NSPS and NESHAPS to any state or
local agency that submits adequate
procedures. Pursuant to Sections lll(c)
and 112(d), EPA, Region 9, has delegated
authority to implement and enforce the
NSPS and NESHAPS programs to
various state and local agencies in
California.
The NSPS and NESHAPS programs
are delegated by each category of
pollutant, not by the total program. A
request for delegation of authority for
each pollutant category is submitted by
a state or local agency to EPA where it
is reviewed and delegated if it meets the
proper standards.
Pursuant to the Administrative
Procedure Act, 5 U.S.C. 553(b), EPA has,
in the past, in addition to informing the
state or local agency, published notices
of delegation in the Federal Register.
However, these notices did not specify
which particular pollutant category bad
been delegated. .
The primary purpose of this action is
to rectify any ambiguities that might
exist concerning which agencies have
previously been delegated the authority
to administer a particular pollutant
category and to rectify any omissions
EPA has made in publishing past notices
of delegation in the Federal Register.
This notice lists, in tabular form, only
Air Pollution Control Districts that are
affected by this notice. The table lists
the specific category or categories of
pollutant that the District has been
delegated authority over. In addition, a
list of addresses which revises and adds
new addresses of Air Pollution Control
Districts to the list found in 40 CFR
60.4(b)(F) and 61.04(b)(F).
Pursuant to NSPS and NESHAPS
regulations, sources are required to
submit all required reports to the state
or local agency that has jurisdiction over
the source, and to EPA.
The Administrator finds good cause to
forego prior public notice and to make
this rulemaking effective immediately. It
is an administrative change, not one of
substantive content, and imposes no
additional burdens on the parties
affected.
The delegation actions reflected in
this administrative amendment were
effective on the dates of delegation,
which appear in the table. No useful
purpose would be served by delaying
the technical changes included herein.
Regulatory Impact: Pursuant to
Executive Order 12291, EPA must
determine whether a newly promulgated
regulation is "major" and therefore
subject to the requirements of a
Regulatory Impact Analysis. This rule is
not a major regulation because it neither
creates new responsibilities nor
adversely affects the economy in any
significant way. Nor is this regulation a
new rule per se. It is merely a rule
providing public notice of past
delegations that previously were not
published in the Federal Register and
listing the specific pollutant categories
that have been so delegated.
This regulation was submitted to the
Office of Management and Budget
(OMB) for review as required by
Executive Order 12291.
(Sees. Ill and 112 of the Clean Air Act. as
amended, (42 U.S.C. 1857C-6 and 1857C-7))
Dated: July 30,1981.
Ann* M. Goreuch,
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PART 61-NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS
Subparts A of Parts 60 and 61 of
Chapter I, Title 40 of the Code of Federal
Regulations are amended as follows:
1. Sections 60.4(b)(F) and 61.04(b)(F]
are each amended by revising the
addresses of the following Air Pollution
Control Districts.
{80.4 Address.
{61.04 Address.
*****
(b)***
fF) California.
Del Norte County Air Pollution Control
District, 909 Highway 101 North, Crescent
City, CA 95531
Fresno County Air Pollution Control District,
P.O. Bex 11867,1246 L Street, Fresno, CA
93721
Monterey Bay Unified Air Pollution Control
District, 1270 Natividad Road, Room 105.
Salinas. CA 93906
Northern Sonoma County Air Pollution
Control District, 134 "A" Avenue, Auburn,
CA 95448
Santa Barbara County Air Pollution Control
District. 300 North San Antonio Road.
Santa Barbara. CA 93110
Shasta County Air Pollution Control District.
2650 Hospital Lane, Redding. CA 96001
South Coast Air Quality Management
District, 9150 Flair Drive, El Monte. CA
91731
Stanislaus County Air Pollution Control
District, 1030 Scenic Drive, Modesto. CA
95350
Trinity County Air Pollution Control District,
P.O. Box AK. Weaverville, CA 96093
Ventura County Air Pollution Control
District, 800 South Victoria Avenue,
Ventura. CA 93009
2. Sections 60.4(b)(F) and 61.04(b)(F)
are further amended by adding the
V-471
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Federal Register / Vol. 46, No. 19E / Ttmreday, October 8. 1961 / Rules and Regulations
addresses of the following Air Pollution
Control Districts.
9$ 60.4 and ei.04 [Amended]
(F) California.
Amador County Air Pollution Control
District P.O. Box 43ft 810 Court Street
Jackson. CA 96642
Bulte County Air Pollution Control District
P O. Box 1229. 316 Nelson Avenue,
Oroville. CA 95966
Caldveras County Air Pollution Control
District. Government Center. El Dorado
Road. San Andreas. CA 95249
Colusa County Air Pollution Control DfetHet
751 Fremont Street. CoJu&a. CA 95952
F.I Dorado Air Pollution Control District 33*
Fair Lane. Placerville. CA 95667
Clenn County Air Pollution Control District,
P.O. Box 351, 720 North Colusa Street
Willows, CA 96986
Great Basin Unified Air Pollution Control
District. 863 North Main Street. Suite 2U,
Bishop. CA 93514
Imperial County Air Pollution Control
District. County Services Building. 939
West Main Street. El Centre. CA 92248
Kings County Air Pollution Control District.
330 Campus Drive. Hanford, CA 03230
Lake County Air Pearton Control District
256 North Forbes StrMt Uktpert CA
95453
Ussen Co»nly Air Pollatioa Control District
175 RitsMll Avenue, SuMnvilie. CA 9813*
Mariposa County Air Pollution Control
District Box 5. Mflripoaa, CA 96338
Merced County Ah- Pollution Control District
P.O. Box 471.240 East 15th Street Merced,
CA 95340
Modoc County Air Pollution Control District
202 West 4th Street, Altaraa, CA 98101
Nevada County Air Pollution Control District
H.E.W. Complex. Nevada City. CA 96B3B
P1ac*r County Air Pollution Control District
11491 "8" Avenue. Auburn CA 96609
Phimas Coonty Air Pollution Control District
P.O. Box 480, Quincy, CA 96871
San Bernardino County Air Pollution Control
District 155r9-»tn. Victorvilla. CA 92992
San Luis Oiu&po County Air Pollution Control
District P.O. Box 637. San Luis Obispo, CA
93408
Sierra County Air PoDurion Control District
P.O. Box 286. Downieville. CA 95936
Slsklyon County Air Pollution Control
District, 525 South Foothill Drive. Yreka,
CAgaoar
Sutler County Air Pollution Control District.
Suiter Coonty Office Buikhng. 142 Garden
Highway. Yuba City. CA 95991
Tehama County Air Pollution Control
District. P.O. Box 36.1760 Walnut Street
Rod Bluff CA oenaa
Toiare Count/ Air Pollution Control District
County Civic Center. Visaiia. CA 93277
Tuolumne County Air Pollution Control
District 9 North Washington Street
Sonora, CA 95370
Yolo-Geleae Air PoJWtfoa Control District.
P.O. Bos UOt. 323 First Street *&
WoodUad. CA066BB
3. Section 00.4(b)(F) is araeitded by-
adding paragraph (b)(FHl) to read as
follows;
960.4 I
II
(b) * ' *
(FT"
(1) This notice lists in tabular form, only
Air Pollution Control Districts that are
affected by this notice. The table lists each
pollutant category by its subpart letter and
pollutant source name. A star (*) or cross(t)
is used to indicate the specific pollutant
category that an Air Pollution Control District
has been delegated authority over and the
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BILLING CODE 6S60-M-C
-------
Federal Register / Vol. 46, No. 208 / Wednesday, October 28. 1981 / Rules and Regulations
131
40 CFR Part 60
[LCE FRL-1921-1]
Alternate Method 1 to Reference
Method 9 of Appendix A—
Determination of the Opacity of
Emissions From Stationary Sources
Remotely by Udar, Addition of
Alternate Method
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: EPA is amending its
regulations to establish an Alternate
Method 1 to Reference Method 9 of
Appendix A of 40 CFR Part 60. This
alternate method employs a lidar (laser
radar) for the nonsubjective
determination of the opacity of visible
emissions from stationary sources. It
will be used during nighttime hours as it
Is during the day. The use of Reference
Method 9 is restricted to daylight.
The effect of this rulemaking is to
allow EPA, state and local agencies to
use Alternate Method 1 (lidar) to
enforce opacity standards in all cases
where Reference Method 9 is now
authorized. These cases include New
Source Performance Standards codified
in 40 CFR Part 60 and, pursuant to 40
CFR 52.12(c)(l), opacity standards in
State Implementation Plans (SIPs) that
do not specify any test procedure.
EFFECTIVE DATE: October 28,1981.
FOR FURTHER INFORMATION CONTACT:
Arthur W. Oybdahl, National
Enforcement Investigations Center, U.S.
Environmental Protection Agency, P.O.
Box 25227, Denver, Colorado 80225, (303)
234-4658. FTS 234-4658.
SUPPLEMENTARY INFORMATION:
Introduction
Udar, an acronym for LJghl Detection
and flanging, was first applied to
meteorological monitoring in 1963. Since
that time lidar has been developed as a
measurement technique for plume
opacity, and today is approved as an
alternate to Reference Method 9 which
employs visible emissions observers.
Lidar contains its own unique light
source (a laser transmitter which emits a
short pulse of light) which enables it to
measure the opacity of stationary source
emissions during both day- and
nighttime ambient lighting conditions.
The optical receiver within the lidar
collects the laser light backscattered
(reflected) from the atmospheric
aerosols before and beyond the visible
plume as well as that from the aerosols
(particulates) within the plume. The
receiver's detector converts the
backscatter optical signal into an
electronic signal. Plume opacity is
calculated from the backscatter signal
data obtained from just before and
beyond the plume.
Background
During its development. Reference
Method 9 was found to be influenced by
the color contrast between a smoke
plume and the background against
which the plume is viewed by visible
emissions observers. It was also
influenced by the total ambient light
(luminescence contrast) present. A
plume is most visible and presents the
greatest apparent opacity when viewed
against a contrasting background (white
plume viewed against a clear blue sky).
Under conditions presenting a less
contrasting background, the apparent
opacity of a plume is less and
approaches zero as the color contrast or .
the ambient light level decreases toward
zero. An example is viewing a white-to-
gray plume against a cloudy or hazy sky.
The measurement of smoke plum*
opacity with the lidar is independent of
the color contrast conditions that exist
between a plume and the respective
background (clear sky, cloudy sky,
terrain, etc.), and ambient lighting
conditions. Lidar does not consider
plume-to-background contrast in
measuring plume opacity.
On July 1,1980, EPA proposed the
lidar technique in the Federal Register
(45 FR 44329) as Alternate Method 1 to
Reference Method 9 of Appendix A.
Need for the Alternate Method
Persuasive considerations supporting
EPA development and approval of the
alternate (lidar) method include the
following:
• Independence from ambient lighting
conditions which allows opacity
measurement during day- and nighttime
hours;
• Objective measurement of a
physical property (opacity) which is
calibrated, and correlated with the
reference method;
• Remote operation which neither
interferes with nor disrupts the
regulated public; ~
• Application of statistical techniques
to assure high confidence levels in the
data used for compliance determination.
Difference From Proposed Method
The approved alternate method varies
from its proposed form as published in
V-475
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Federal Register / Vol. 48, No. 208 / Wednesday. October 28, 1981 / Rules and Regulations
me July 1,1980 Federal Register. The
proposal was edited for clarity and
brevity. Informative material (examples)
and the mathematical derivations were
moved into the technical support
document. Reference 5.1. The final
regulation is approximately two thirds
of the proposal'siength.
A list of definitiens relating to lidar
technology was placed in the first
section. The selection of pick intervals
was simplified to avoid ambiguity. The
equation for the standard deviation was
further derived and simplified to assure
a high confidence level in the data that
is used. Its definition and derivation are
contained in the technical support
document. The opacity concept is
clearly identified and the terms "actual
plume opacity" and "actual average
plume opacity" are defined using lidar
measurements. These opacities are
correlated to the reference method. A
more accurate azimuth angle correction
equation was put into the regulation for
converting the opacity values measured
along the laser beam's slanted pathway
through the plume to the opacity value
of the piume cross section. The running
average method was eliminated so that
it would not be confused with any other
applicable standard.
The design performance specifications
for the lidar system were generalized
and converted into affirmative
requirements. This enables the
construction and use of lidar systems
with ruby or other lasers.
All recordkeeping requirements were
changed to suggestions. EPA operators
will follow these suggestions closely but
others who design, build, or operate a
lidar system will have no recordkeeping,
reporting, or other paperwork
obligations. This flexibility allows
construction of lidar systems by those
persons wanting to use the alternate
method without imposing any additional
regulatory burden upon the public.
Public Comments
The public comments received on the
proposed regulation were individually
examined by the EPA workgroup. Each
comment was resolved and appropriate
changes appear in today's regulation.
All of these comments were generalized
into the major topics which are
discussed below. These include the
application of lidar technology to the
regulatory process and its applicability
for measuring the opacity of emissions
from a specific source. Several
commentators examined the available
literature or recounted their own
experiences when they asked to see a
correlation between the proposed
method and the reference method. The
results of this test also satisfied many of
the theoretical and philosophical
concerns. Safety concerns for the
operators and the public were
expressed. Comments were also
received on how the system would
operate, what degree of subjectivity the
operators would have and the
availability of equipment or operators.
Legal concerns were directed to an
inferred regulatory change and also to
constitutional issues. The response to
these comments is detailed below.
Public comments expressed a concern
that the use of lidar for the remote
measurement of emissions opacity from
stationary sources was a premature
application of experimental technology.
EPA evaluated two decades of literature
describing the development of lidar
technology. The list of references in the
technical support document
demonstrates the careful agency
consideration used to develop lidar into
an alternate method for the remote
measurement of opacity.
Several commentators indicated that
the data derived from the application of
the alternate method to a specific
emission source might be stricter than
data produced by the reference method.
Plume characteristics, including particle
size and particle color, were mentioned
as individual variables which might
affect the data generated by lidar. EPA
performed extensive tests to correlate
Alternate Method 1 with Reference
Method 9 (see Reference 5.1]. The data
reduction technique assures that lidar-
determined opacity values will not show
an emission source exceeding an
opacity standard when the reference
method would not also show that it was
exceeding the standard. In some cases,
Alternate Method 1 will show a source
to be in compliance with opacity
standards when a visual observer would
report that the source was not in
compliance with the standard.
Some of the comments were directed
toward an apparent subjectivity in the
use of lidar when there was a potential
for external interference during an
opacity measurement. EPA has shown
that lidar may be used to measure
opacity values under a wider variety of
conditions than would be possible using
the reference method. However, lidar-
determined opacity values will not be
used for enforcement purposes when
intervening variables significantly
interfere with an opacity determination.
Examples of a heavy precipitation event
or excessive ambient (wind blown) dust
were given to explain potential causes
of erratic data. These opacity values
would be excluded from an enforcement
decision by the data reduction technique
which identifies and discards
unsatisfactory data.
All of the other limitations noted by
commentators are no more restrictive
than conditions met during the visual
determination of opacity. For example,
the proximity of other plumes was
mentioned. EPA has shown that a lidar
is able to distinguish individual plumes
that are not in spatial coincidence. It
requires no more than 50 meters of-
clearance before and beyond the plume
along its line-of-sight. The positioning
problem is far less restrictive because
the lidar system only measures the
optical backscatter produced by its own
unique light source. Its only position
restriction is a 15* cone angle about the
sun which eliminates solar signal noise
in the receiver. The initial positioning of
the lidar is approximately perpendicular
to the direction of the plume. The lidar
data reduction technique compensates
for signficant plume drift and, unlike the
reference method, adjustments are made
to determine the opacity of the actual
cross section of the plume. The lidar
operators verify that the measurements
are -taken in the same part of the plume
that visual observers would use. This,
for example, precludes misleading
measurements taken if a certain plume
were to loop tightly back upon itself.
Some commentators were concerned
with the lidar's ability to determine
opacity values for a source with an
attached steam plume during nighttime
measurements. EPA has suggested
several visual aids which are available
to verify the proper use of the lidar
during nighttime measurements. Even
without these aides, the lidar is capable
of discerning the sudden change in
opacities which would allow the
alternate method to be used for this
purpose. The system's data display
allows the lidar operator to distinguish
the end of an attached steam plume and
consequently permits the measurement
of the residual plume opacity. It is the
characteristic of the nearly 100% opacity
and high reflectivity of a steam plume
that allows the lidar to make this
measurement when the other mentioned
visual aids may not provide adequate
information. Other nighttime concerns
expressed were the inability of a source
to refute lidar determinations because
the source would be unable to field a
team of visual observers. EPA notes that
the source is in control of the operation
and has access to monitoring and
production records which could be used
for this purpose.
Many commentators were concerned
with the possibility that the lidar-
determined opacity values for an
emission source would vary from
opacity values determined by visual
observers. As a result of these
V-476
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/ Vol. 48. No. 208 / Wednesday. October 28, 1981 / Rules and Regulations
comments, EPA conducted a
collaborative test to determine if any
discemable variance would be detected.
The resulto of the teat showed that the
lidar-meaoured average opacity wao 453
(full scale) greater than that obtained by
the visual emissions obaervero for black
smoke. For whit a smoke the lidar-
measured average opacity was 8% (full
ocale) lower than that obtained by the
observers.
EPA applied the results of the
collaborative test and the fact that lidar
is more sensitive to low-level visible
emissions than visible emissions
observers (giving rise to the definition of
correlation which states that 0% opacity
by Reference Method 9 is defined as
being less than or equal to 5% plume
opacity by lidar determination), to
define actual plume opacity. This
opacity value is calculated from the
lidar-measured opacity as shown in
Equation AMl-15 of the Alternate
Method. The reasons for, and the
derivation of this equation, is provided
in Reference 5.1 of Alternate Method 1.
Other comments were addressed to
the correlation of the lidar system with
various operators or with other lidar
systems. Each EPA crew of lidar
operators must demonstrate their
proficiency at least annually during the
calibration tests. Other lidar systems
must satisfy the requirements of the
Performance Evaluation Tests of the
Alternate Method. EPA sees no useful
enforcement purpose for comparing lidar
systems with each other.
Commentators suggested that lidar
opacity values obtained from a small
portion of a plume would fail to account
for the averaging effect of a visual
observer or the slower responding in-
stack transmissometer, when reading a
highly variable plume. This was not
observed during the collaborative
testing, but even if it is an inherent
characteristic, the lidar-determined
opacity values would average out the
variation observed in time and space.
The comments directed to aspects of
Reference Method 9 do not apply to the
Alternate Method. Such comments
included discussions of: (1) stricter
technical requirements for in-stack
transmissometers than those used for
the Method 9 calibrating smoke
generators, and (2) the relationship
between visual opacity and mass
emissions. The use of the alternative
method does not change the basis for
the reference method. Lidar is used to
make the same determinations that
Method 9 was approved to make. The
approval of a lidar system for the
remote determination of the opacity of
stationary source emissions provides a
consistent, reliable mechanism for
extending regulatory compliance
determinations: under a wider variety of
conditions. This extension clearly
furthers the objectives of the opacity
standard by verifying that stationary
sources meet opacity requirements at all
times, day and night
A frequent comment wao addressed to
the safe use of a lidar system in the field
environment Concerns were expressed
for potential encounters with the laser
beam by plant personnel, bystanders,
and wildlife. The list of referenced
includes manuals with detailed
requirements used by EPA operators to
prevent exposure of individuals to the
laser beam. This list in addition to
Section VH of Reference 5.1, is
indicative of the thorough safety training
that is an integral part of the EPA
operator-training program. EPA
operators must verify that no plant
personnel are in the vicinity of the laser
beam. This is accomplished visually and
the procedure is repeated anytime the
lidar is directed close to the lip of a
stack or other source. The Federal
Aviation Administration (FAA) is
satisfied with EPA precautions. Flight
paths near an intended source aro
reviewed prior to a test and the FAA is
notified of the testing in a particular
area. The required operator vigilence
prevents an accidental exposure to the
direct laser beam by the public or by .
wildlife. The regulation does not specify
safety procedures because EPA's
position is that the adoption and
practice of laser safety in the field is
incumbent upon any owner/operator of
a lidar. Any lidar manufacturer can
provide training in lidar safety
(References 48 and 49 of the Technical
Support Document). The purpose of this
regulation is to provide a method for
measuring plume opacity by lidar.
Section VII of the Technical Support
Document [Reference 5.1] describes
adequate laser safety requirements and
procedures when applied to field use.
The aiming telescope indicates where
the laser beam will strike the emission
source when the lidar range in
determined. The operator may use 8
variety of visual aides to determine that
no employees are working on a stack or
other source that is to be tested. The
lidar will not be operated when there is
a reasonable, though slight, probability
that people or animals will intersect the
laser beam. Similarly, objects that could
reflect a laser pulse intact are avoided.
The diffuse reflection of a laser beam
from an opaque object does not present
a hazard to the public or to the lidar
operators. A prior notification of
intended source testing was not added
to the regulation as requested by several
commentators. The present safeguards
are adequate for protecting employeeo
and a notice requirement could limit
enforcement applications.
One commentator questioned tho
Agency's ability to enforce the
restriction on operator use of dulling
drugs or medications prior to or during
lidar operations. EPA based these
restrictions upon safety regulations
specified for the operator of
sophisticated or powerful equipment
that presents a potential risk to the
public, such as an aircraft pilot. It is tho
individual responsibility of lidar
operators to avoid the use of any
substance which will impair their senses
or their ability to operate the lidar
safely. Abuse of this restriction may be
detected by other operators or by an
operator's inability to perform
satisfactorily. EPA clearly emphasizes
the individual's responsibility in laser
safety during the training program.
Several commentators noted that the
running average method for the lidar -
determination of average opacity values
contradicted the Method 9 calculation.
EPA deleted the running average
requirement from the alternate method,
and replaced it with the calculation for
the average of actual opacity.
Comments regarding the discarding of
opacity values indicate the need for an
explanation of quality control and the
linkage of the alternate method with the
variations of the reference method. The
reference or ambient air signals required
during a test maintain the accuracy and
precision of the alternate method. Only
measurements that provide high quality
data are used for compliance
determination. The acceptance/re; ction
criterion assures the objectivity of the
alternate method and further reinforces
the accuracy of the results. The
requirement that the associated
standard deviation, So. for a lidar-
determined opacity value be less than or
equal to 8% (full scale), accounts for the
variations that are inherent to Method 9
observations.
Several commentators suggested that
quality assurance procedures are a vital
aspect of any system. The Agency
agrees with this observation and
continued the requirements for lidar
performance verification. This includes
annual calibration of a lidar system,
routine equipment calibrations,
refererence measurements (ambient air
shots), and an acceptance/rejection
criterion. Additionally, collaborative
tests were conducted to verify the
correlation between opacity values
determined by lidar and those
determined by certified visual emissions
observers. The test results were
V-477
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Federal Register / Vol. 46. No. 208 / Wednesday, October 28. 1981 / Rules and Regulations
incorporated into the data reduction
technique to provide high quality data.
Other commentators mentioned
apparent subjectivity of the lidar
operator in determining plume opacity
values. The alternate method
requirements virtually eliminate
subjectivity. The individual
characteristics of each source will
control positioning and use of the lidar
system. These judgments are no more
subjective than those required by the
reference method. The alternate method
produces more objective data because
lidar is less restricted, and is able to
compensate or correct for plume drift.
The operator is able to visually verify
that the lidar measurements are free
from interference.
Commentators correctly perceived
that training is required to produce lidar
operators. Some commentators felt that
EPA should institute a certification
program for lidar operators. EPA
decided not to make a lidar operator
certification program a part of this
alternate method because proper and
adequate training in lidar operations is
the responsibility of the lidar owner/
.operator and is readily provided by any
number of lidar manufacturers.
EPA expects that the performance
verification of the lidar will be
performed by the personnel who will be
operating the system in the field using
this method. If a lidar is not properly
operated, it will not fulfill the
performance verification requirements
of this method.
EPA's experience with the training,
certification and use of non-specialized
trainees has been successful. Usually
lidar manufacturers will offer training
for prospective lidar operators.
Comments were made concerning the
availability of lidars and lidar
equipment. Several contractors located
throughout the country offer the
manufacture or lease of lidar systems.
Other comments were directed
toward the availability of lidar data.
EPA policy encourages the
dissemination of information to the
public. Lidar-generated data will be
available to the same extent that data
obtained by EPA visible emission
observers is available.
After review of one commentator's
observation of the improper application
of a mathematical formula, the
appropriate corrections were made In
the alternate method. Derivations for the
formulas in the alternate method are
contained in the Technical Support
Document [Reference 5.1].
Another commentator speculated
upon undefined problems and
unobserved interferences. EPA will deal
with speculative problems when they
are encountered.
One commentator contended that the
use of a lidar system was
unconstitutional, but failed to provide
any reasoning or legal authorities to
support this argument. In any event, it is
without merit
Stack plumes are visible from "plain
fields" and the Constitution does not bar
air pollution enforcement officials from
enforcing standards by observing and
measuring the opacity of such plumes.
Air Pollution Variance Board of
Colorado v. Western Alfalfa Corp., 416
U.S. 861 (1974). An owner or operator of
such a stack does not have a reasonable
expectation that the opacity of such
plumes will not be observed and
measured. Therefore, such observation
and measurement does not constitute a
"search" under the Fourth Amendment.
See, Katz v. United States. 389 U.S. 347
(1967). Such observation and
measurement does not become a
"search" simply because it is performed
by a mechanism such as lidar, that
makes the measurement more reliable,
and allows measurement at night.
United States v. Lee. 274 U.S. 559, 563
(1927); State v. Stachler. 570 P. 2d 1323
(Haw, S. Ct. 1977); Burkholder v.
Superior Court, 158 Cal. Rptr. 86 (Ct.
App. 1979).
The commentator also objected that
EPA lacks statutory authority to
authorize the enforcement of opacity
limits by lidar. He argued that EPA is
not authorized to use "remote,
surreptitious, non-entry" means of
enforcement This argument is without
merit.
Section 114 of the Clean Air Act is a
broad grant of authority to sample
emissions. It provides that, for the
purposes of carrying out virtually all
provisions of the Act including
enforcement of state implementation
plans and new source performance
standards, "the Administrator may
require any person who owns or
operates any emission source" to
"install, use, and maintain such
monitoring equipment or methods," and
"sample such emissions (in accordance
with such methods, at such locations, at
such intervals, and in such manner as
the Administrator may prescribe) * * *
as he may reasonably require" and that
the Administrator may "sample any
[such] emissions," Section 114(a)(l),
(2)(B). Because lidar is a reliable means
of sampling the opacity of emissions and
of monitoring the performance of
pollution control techniques, the
Administrator may reasonably allow its
use.
There is nothing in the language or
legislative history of Section 114 to
suggest that if a sampling or monitoring
technique can be used from outside the
boundaries of a polluting plant without
the owner's knowledge, it may therefore
not be used as an enforcement
technique. Indeed, EPA has required the
use of Method 9 to monitor and sample
emissions since 1971, 36 FR 24876, 34895
(Dec. 23,1971), and Method 9 can b'e and
is used from outside plant boundaries
without owners' knowledge. The use of
Method 9 has been upheld as a
reasonable enforcement technique.
Portland Cement Association v. Train.
513 F.2d 506, 508 (D.C. Cir. 1975).
Finally, Section 301(a)(l) makes it
clear that the Administrator may
exercise his authority under Section 114 ,
by regulation. It provides, "The
Administrator is authorized to prescribe
such regulations as are necessary to
carry out his functions under this
chapter [the Act]." Therefore, the
Administrator has the authority to
prescribe by regulation the manner in
which lidar may be used.
Another commentator objected in
general terms that the rulemaking has
not complied with Section 307(d) of the
Act, but did not mention any specific
defect. EPA agrees that the rulemaking
is governed by Section 307(d), but
believes that it fully complies with that
section.
This commentator also objected that
EPA is required to provide opportunity
for hearings on this rulemaking in every
state of the United States, under Section
110(c)(l), of the Act. This appears to
refer to EPA's regulations on Approval
and Promulgation of Implementation
Plans, 40 CFR Part 52, which provide, in
the General Provisions, § 52.12(c) that:
For the purpose of Federal enforcement, the
following test procedures shall be used:
(1) Sources subject to plan provisions
which do not specify a test
procedure * * * will be tested by means of
the appropriate procedures and methods
prescribed in Part 60 of this chapter * * *
This provision, promulgated on May
31.1972 (37 FR 10842,18847), has
governed all state plans approved under
the Clean Air Act. It merely provides
that where a state has not specified a
procedure for testing a source's
compliance with its plan, EPA will use
the appropriate Federally-established
test method.
The commentator implies that
because 40 CFR 52.12(c) allows EPA to
use Part 60 methods to enforce state
plans, a rulemaking adding lidar to the
Part 60 methods requires a hearing in
each state. This is incorrect.
Section 110(c)(l) requires EPA to hold
a hearing in a state only where the state
has failed to submit an approvable
V-478
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/ Vol. 43, No. 208 / Wednesday. October 23, 1831 / Rules and Regulations
implementation plaa, and EPA
thereupon promulgates a plan for that
state. This rulemaking does not deal
with such a case. It merely established
an alternate test method that may be
used to enforce a state plan where &
state has not otherwise provided.
Section MO does not require that
regulations of national applicability
affecting state plans may bs adopted
only after opportunity for 55 hearings,
one in each state.1 Indeed, all such
regulations have been promulgated
without opportunity for a hearing in
each state. See 40 CFR Part 52, Subparta
A-and EEE and Appendices, ami Part 5S.
In particular, EPA has from time to time
revised and updated its test methods, as
it is now doing for Method 8. EPA has
done so in every case by rulemakingo
without providing opportunity for
hearings in every state. See generally 40
CFR Part 60, Appendix A (1380).
Section 307(d) also makes clear that
Congress did not intend to require
multiple hearings for rulemaMngs
governing implementation plans. Section
307(d) establishes procedural
requirements for EPA rulemakings,
including all rulemakings relating to tha
prevention of significant deterioration
("PSD"). PSD rulemakings. both before
and since Section 307(d) was added to
the Act. have taken the form of
regulations amending all state plans, off
governing all state plans. See, 40 CFR
52.21 and 51.24 (1960). Section 307(d)(5),
however, requires only a single public
hearing for such rulemakings. EPA
therefore fully complied with the Clean
Air Act by holding a single public
hearing for this rulemaking.
Finally, there was no reason to hold
more than one hearing. Only seven
persons requested a hearing. No one
requested additional hearings, or gave
any reason why hearings in other states
should be held. Indeed, the commentator
waived a request for any hearing. Since
there was no reason to hold additional
hearings, it was lawful for EPA not to
hold them. See American Airlines Inc. v.
CAB. 359 F. 2d 624, 832-«33 (D.C Cir.
1966); Clean Air Act Section
307(d)(9)(D)(i). (iii).
This alternate method is issued under
the authority of Sections 111, S14, and
301 of the Clean Air Act, as amended (42
U.S.C 7411, 7414, 7601).
Tho docket. Number A-78-M. is
available for public inspection and
copying between 8:00 a.m. and 0*0 p.m.
at EPA'o Central Docket Section. Room
2S03B, Waterside Mall, 401 M Street,
S.W.. Washington, DC 20480.
Under Executive Order 12281, EPA
must judge whether a regulation io majoF
and therefora subject to tho
requirements of a Regulatory Impact
Analysis. This regulation is not majos
because tho annual offect oa tba
economy io less than $100 million. This
is an alternate teat method to an axis ting
enforceable test method. It imposed no
new regulator requirements. Tho uss of
this alternate method is optional fo?
opacity determination.
This regulation wao submitted to the
Office of Management and Budget
(OMB) for review as required by
Executive Order 12291.
Dated: October 19,1981.
Aura M. Gorara&,
Administrator.
EPA is amending 40 CFR Part 80,
Appendix A by adding an alternate
method to Method S as follows:
Method E—Visual Determination off EJw
1 Under the dean Air Act "ototo" to defined to
include the SO atateo. pluo five Dinar oreoo. Sactioa
302(d). Each of the 55 "ototeo" bao o plan. CO CFR
Part 52. Subparto B-DDD.
Alternate Metaod 2—ffiatennlBcStea tt3 to
Opadty of Emissions From Stationary
Sourcoo Remotely by UcSor
This alternate method provides tho
quantitative determination of the opacity o!
an emissions plume remotely by a mobile
lidar system (laser radar; Light Detection and
Ranging). The method includes procedureo
for the calibration of the lidar and procedureo
to be used in the field for the lidaf
determination of plume opacity. The lidar Io
used to measure plume opacity during either
day or nighttime houro because It contains ito
own pulsed light source or transmitter. The
operation of the lidar io not dependent upon
ambient lighting conditions (light, dark, ounny
or cloudy).
The lidof mechanism or technique is
applicable to meaouring plums opacity at
numerouo wavelengths of laser radiation.
However, the performance evaluation and
calibration teot resulto given in oupport of
this method apply only to Q lidar that
employe a ruby (red light) laoar [Reference
8.1).
3. Principle and Applicability
S.i Principle. The opacity o? vi&iblo
Gmisslono from stationery oooreeo (otscltc,
roof vents, etc.) io meaoured remotely by Q
mobile lidar (laser radar).
1.2 Applicability. This method io
applicable for the remote measurement of tho
opacity of vloible emissions from otationary
oourceo during both nighttime and daylight
conditions, pursuant to 40 CFR 0 eo.ll(b). It io
alse applicable for the calibration and
performance verification of the mobile lids?
for the measurement of the opacity of
emissions. A performonce/dosiga
specification for Q booic Edar oyotesa k> olc9
incorporated into tfcis azsthsd.
1.3 Definitions}.
Azimuth angle: Tha angle in the horizontal
plane that designates where the laser beam la
pointed. It is measured from an arbitrary
fixed reference line in that plane.
Backscatter: The ocattering of laser light In
Q direction opposite to that of the incident
laser beam due to reflection from porticulateo
along the beam'o atmospheric path which
may include Q smoke plume.
Backscatter signal The general term for tho
lidar return oignal which results from laser
light being backscattered by atmospheric aad
omoka plume particulatso.
Convergence distance: The distance from
the lidar to the point of overlap of the lidar
receiver's fleld-of-view and the laser beam.
Elevation angle: The angle of inclination oS
the laser beam referenced to the horizontal
plane.
Far region: The region of the atmosphera'o
path along tho lidar line-of-sight beyoad or
behind the plume being measured.
Lidar: Acronym for Light Detection and
Ranging.
Lidar range: The range of distance from the
Hdar to a point of interest along the lidar liac-
of-sight.
Near region: Tbe region of the atmospheric
path along the Hdar line-of-sight between the
lidar'o convergence distance and the phimo
being measured.
Opacity: One minus the optical
trancmittance of a smoke plume, seeem
target, etc.
Pick interval: The time or range intervals ta
the lidar backscatter signal whose minimum
average amplitude is used to calculate
opacity. Two pick intervals are required, ono
in the near region and one in the far region.
Plume: The plume being measured by lidar.
Plume signal: The backscatter signal
resulting from the laser light pulse passing
through Q plume.
1/R" correction: The correction made for
the systematic decrease in lidar backscatter
oignal amplitude with range.
Reference signal: The backscatter signal
resulting from the laser light pulse passing
through ambient air.
Sample interval: The time period between
successive samples for a digital signal or
between successive measurements for an
analog signal.
Signal spike: An abrupt, momentary
Increeoe and decrease in signal amplitude.
Source: The oource being tested by lidar.
Time reference: The timely when the
laser pules emerges from tho laser, used an
the reference in all lidar tirob or range
Bieasuremento.
£ Procedural.
The mobile lidar calibrated In accordance
with Paragraph 3 of this method shall use tho
following procedurao for remotely measuring
tho opacity of Dictionary oource emissions:
V-479
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Federal Register / Vol. 46. No. 208 / Wednesday. October 28. 1981 / Rules and Regulations
2.1 Lidar Position. The lidar »h"all be
positioned at a distance bom the plume
sufficient to provide an unobstructed view of
the source emissions. The plume must be at a
range of at least 50 meters or three
consecutive pick intervals (whichever is
greater) from the lidar'* transmitter/receiver
convergence distance along the line-of-sight.
The maximum effective opacity measurement
distance of the lidar -is a function of local
atmospheric conditions, laser beam diameter,
and plume diameter. The test position of the
lidar shall be selected so that the diameter of
the laser beam at the measurement point
within the plume shall be no larger than
three-fourths the plume diameter. The beam
diameter is calculated by Equation (AMl-1):
D(lidar) = A+R=laser beam divergence measured in
radians
R =range from the lidar to the source (cm)
D(Lidar = diameter of the laser beam at range
R (cm),
A=diameter of the laser beam or pulse
where it leaves the laser.
The lidar range. R, is obtained by aiming
and firing the laser at the emissions source
structure immediately below the outlet. The
range value is then determined from the
backscatter signal which consists of a signal
ipike (return from source structure) and the
atmospheric backscatter signal [Reference
5.1]. This backscatter signal should be
recorded.
When there is more than one source of
emissions in the immediate vicinity of the
plume, the lidar shall be positioned so that
the laser beam passes through only a single
plume, free from any interference of the other
plumes for a minimum of 50 meters or three
consecutive pick intervals (whichever is
greater) in each region before and beyond the
plume along the line-of-sight (determined
from the backscatter signals). The lidar shall
initially be positioned so that its line-of-slght
is approximately perpendicular to the plume.
When measuring the opacity of emissions
from rectangular outlets (e.g.. roof monitors,
open baghouses. noncircular stacks, etc.), the
lidar shall be placed in a position so that its
line-of-sight is approximately perpendicular
to the longer (major) axis of the outlet.
2.2 Lidar Operational Restrictions. The
lidar receiver shall not be aimed within an
angle of ± 15' (cone angle) of the sun.
This method shall not be used to make
opacity measurements if thunderstorms,
snowstorms, hail storms, high wind, high-
ambient dust levels, fog or other atmospheric
conditions cause the reference signals to
consistently exceed the limits specified in
Section 2.3.
2.3 Reference Signal Requirements. Once
placed in its proper position for opacity
measurement, the laser is aimed and fired
with the line-of-sight near the outlet height
and rotated horizontally to a position clear of
the source structure and the associated
plume. The backscatter signal obtained from
this position is called the ambient-air or
reference signal. The lidar operator shall
inspect this signal [Section V of Reference
5.1) to: (1) determine if the lidar line-of-sight
is free from interference from other plumes
and from physical obstructions such as
cables, power line*, etc.. for a minimum of SO
meters or three consecutive pick interval*
(whichever is greater) in each region before
and beyond the plume, and (2) obtain a
qualitative measure of the homogeneity of the
ambient air by noting any signal spikes.
Should there be any signal spike* on the
reference signal within a minimum of 50
meters or three consecutive pick intervals
(whichever is greater) in each region before
and beyond the plume, the laser shall be fired
three more times and the operator shall
inspect the reference signals on the display. If
the spike(s) remains, the azimuth angle shall
be changed and the above procedures
conducted again. If the spike(s) disappears in
all three reference signals, the lidar line-of-
sight is acceptable if there is shot-to-shot
consistency and there is no interference from
other plumes.
Shot-to-shot consistency of a series of
reference signals over a period of twenty
seconds is verified in either of two ways. (1)
The lidar operator shall observe the reference
signal amplitudes. For shot-to-shot
consistency the ratio of Rf to Rn (amplitudes
of the near and far region pick intervals
(Section 2.61)] shall vary by not more than ±
6% between shots: or (2) the lidar operator
shall accept any one of the reference signals
and treat the other two as plume signals; then
the opacity for each of the subsequent
reference signals is calculated (Equation
AMl-2). For shot-to-f hot consistency, the
opacity values shall be within ± 3% of 0%
opacity and the associated S, values less
than or equal to 8% (full scale) (Section 2.6].
If a set of reference signals fails to meet the
requirements of this section, then all plume
signals [Section 2.4] from the last set of
acceptable reference signals to the failed set
shall be discarded.
2.3.1 Initial and Final Reference Signals.
Three reference signals shall be obtained
within a 90-second time period prior to any
data run. A final set of three reference signals
shall be obtained within three (3) minutes
after the completion of the same data run.
2.3.2 Temporal Criterion for Additional
Reference Signals. An additional set of
reference signals shall be obtained during a
data run if there is a change in wind direction
or plume drift al 30* or more from the
direction that was prevalent when the last set
of reference signals were obtained. An
additional set of reference signals shall also
be obtained if there is a change in amplitude
in either the near or the far region of the
plume signal, that is greater than 6% of the
near signal amplitude and this change in
amplitude remains for 30 seconds or more.
2.4 Plume Signal Requirements. Once.
properly aimed, the lidar is placed in
operation with the nominal pulse or firing
rate of six pulses/minute (1 pulse/10
seconds). The lidar operator shall observe the
plume backscatter signals to determine the
need for additional reference signals as
required by Section 2.3.2. The plume signals
are recorded from lidar start to stop and are
called a data run. The length of a data run is
determined by operator discretion. Short-
term stops of the lidar to record additional
reference signals do not constitute the end of
a data run if plume signals are resumed
within 90 seconds after the reference signals
have been recorded, and the total stop or
interrupt time does not exceed 3 minutes.
2.4.1 Non-hydrated Plumes. The laser
•hall be aimed at the region of the plume
which displays the greatest opacity. The lidar
operator must visually verify that the laser is
aimed clearly above the source exit structure.
2.4.2 Hydrated Plumes. The lidar will be
used to measure the opacity of hydrated or
so-called steam plumes. As listed in the
reference method, there are two types, i.e.,
attached and detached steam plumes.
2.4.2.1 Attached Steam Plumes. When
condensed water vapor Is present within a
plume, lidar opacity measurements shall be
made at a point within the residual plume
where the condensed water vapor is no
longer visible. The laser shall be aimed into
the most dense region (region of highest
opacity) of the residual plume.
During daylight hours the lidar operator
locates the most dense portion of the residual
plume visually. During nighttime hours a
high-intensity spotlight, night vision scope, or
low light level TV, etc., can be used as an aid
to locate the residual plume. If visual
determination is ineffective, the lidar may be
used to locate the most dense region of the
residual plume by repeatedly measuring
opacity, along the longitudinal axis or center
of the plume from the emissions outlet to a
point just beyond the steam plume, The lidar
operator should also observe color
differences and plume reflectivity to ensure
that the lidar is aimed completely within the
residual plume. If the operator does not
obtain a clear Indication of the location of the
residual plume, this method shall not be used.
Once the region of highest opacity of the
residual plume has been located, aiming
adjustments shall be made to the laser line-
of-sight to correct for the following:
movement to the region of highest opacity out
of the lidar line-of-sight (away from the laser
beam) for more than 15 seconds, expansion of
the steam plume (air temperature lowers
and/or relative humidity increases) so that it
fust begins to encroach on the field-of-view of
the lidar's optical telescope receiver, or a
decrease in the size of the steam plume (air
temperature higher and/or relative humidity
decreases) so that regions within the residual
plume whose opacity is higher than the one
being monitored, are present.
2.4.2.2 Detached Steam Plumes. When the
water vapor in a hydrated plume condenses
and becomes visible at a finite distance from
the stack or source emissions outlet, the
opacity of the emissions shall be measured in
the region of the plume clearly above the
emissions outlet and below condensation of
the water vapor.
During daylight hours the lidar operators
can visually determine if the steam plume is
detached from the stack outlet. During
nighttime hours a high-intensity spotlight.
night vision scope, low light level TV, etc.,
can be used as an aid in determining if the
steam plume is detached. If visual
determination is ineffective, the lidar may be
used to determine if the steam plume is
detached by repeatedly measuring plume
opacity from the outlet to the steam plume
along the plume's longitudinal axis or center
V-480
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Federal Register / Vol. 46, No. 208 / Wednesday. October 28, 1981 / Rules and Regulations
line. The lidar operator should also observe
color differences end plume reflectivity to
.detect • detached plume. If the operator does
not obtain a clear indication of the location of
the detached plume, this method shall not be
used to make opacity measurements between
the outlet and the detached plume.
Once the determination of a detached
steam plume has been confirmed, the laser
shall be aimed into the region of highest
opacity in the plume between the outlet and
the formation of the steam plume. Aiming
adjustments shall be made to the War's line-
of-sight within the plume to correct for
changes in the location of the most dense
region of the plume due to changes in wind
direction and speed or if the detached steam
plume moves closer to the source-outlet
encroaching on the most dense region of the
plume. If the detached steam plum* should '
move too close to the source outlet for the
lidar to make interference-free opacity
measurements, this method shall not be used
2.5 Field Records. In addition to the
recording recommendations listed in other
sections of this method the following records
should be maintained. Each plume measured
should be uniquely identified. The name of
the facility, type of facility, emission source
type, geographic location of the lidar with
respect to the plume, and phirae
characteristics should be recorded. The date
of the test, the time period that a source was
monitored, the bine (to the nearest second] of
each opacity measurement, and the sample
interval should also be recorded. The wind
speed, wind direction, air temperature,
relative humidity, visibility (measured at the
lidar's position), and cloud cover should be
recorded at the beginning and end of each
time period for a given source. A small sketch
depicting the location of the laser beam
within the plume should be recorded.
If a detached or attached steam plume is
present at the emissions source, this fact
should be recorded. Figures AM1-I and AMl-
n are examples of logbook forms that may be
used to record this type of data. Magnetic
tape or paper tape may also be used to record
data.
V-481
-------
LIDAR LOG CO>TROI.
I,«(I Bnnlt
|ltti|**i CONTROl N«HRER ti nek
TABIL4TIO>
uirci ii«n tut)
CONTROl
NUMRER
iU
oo
DITE
ISSKNED
FIOIECT
CITT. STITE
CHtinil ii ml Ml*
MDAR M>C CONTROL UMRER TABILATIO* (r..r)
Itttlfi i CONTROl NUMRER ll lick lilmtfill tlirci M«ir tut)
CONTROl
NUMRER
DATE
ASSIGNED
•ROIECT
; 51111 STATE
Control Number Tabulation
•»l
m
f
09
90
CD
5*
5
<
3
o
i
^
1
1
Q.
CD
b
o^
o"
r
to
§
90
e^
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B
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Q.
JQ
5"
D
-------
• ••• Iti UlMMI:
i IIM K ioi. or opnmio>N
• ••brr: II *M. \-
IIIMH OfllUTOrs NOTES
Iliclili Hlitiii It luir III* litlli HIBI-- iltlttll |l»«l. Ill I
it tti IUN ill* H
IxMlM tl HIM:
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i.
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E-
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lllll IIEllllllll l» ll|ll II l| Illlllltll II I I
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C III C l«l«IUt k>_Ult|: ll|ll _____ V ««l *.
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till »4ii<> ••«• to ItoM Ituii. )ii «t€ |
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73
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oo
Figure AM1-II Lidar Log Of Operations
-------
Federal Register / Vol. 46. No. 208 / Wednesday. October 28,1981 / Rules and Regulations
OJ
•o
(a) Reference Signal, 1/R2 Corrected
(Near Region)
(Far Region)
Convergence Point
OJ
•o
Time or Range
(b) Plume Signal, 1/R2 Corrected
'Plume Spike
Time or Range
p
(a) Reference signal, l/R -corrected. This reference signal is for
plume signal (b). R , R, are chosen to coincide with In, 1^.
o
(b) Plume signal, l/R -corrected. The plume spike and the decrease
in the backscatter signal amplitude in the far region are due to
the opacity of the plume. I , If are chosen as indicated in
Section 2.6. n T
Figure AMl-III. Plots of Lidar Backscatter Signals
BILLING COOt 656O-31-C
V-484
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Federal Register / Vol. 46. No. 208 / Wednesday. October 28, 1981 / Rules and Regulations
2.6 Opacity Calculation end Data
Analysis. Referring to the reference signal
and plume signal in Figure AM1-III. the
measured opacity (Op) in percent for each
lidar measurement is calculated using
Equation AM1-2. [O,=l-Tpi T, is the plume
transmittance.)
(AM1-2)
where:
!„ = near-region pick interval signal'
iimplitude, plume signal. 1/R* corrected.
I, = far-region pick interval signal amplitude,
plume signal, 1/R' corrected.
RB = near-region pick interval signal
amplitude, reference signal. 1/R1
corrected, and
R, = far-region pick interval signal amplitude.
reference signal, 1/R: corrected.
The 1/R1 correction to the plume and
reference signal amplitudes is made by
multiplying the amplitude for each successive
sample interval from the time reference, by
the square of the lidar time (or range)
associated with that sample interval
[Reference 5.1 J.
The first step in selecting the pick intervals
for Equation AMl-2 is to divide the plume
signal amplitude by the reference signal
amplitude at the same respective ranges to
obtain a "normalized" signal. The pick
intervals selected using this normalized
signal, are a minimum of 15 m (100
nanoseconds] in length and consist of at least
S contiguous sample intervals. In addition.
the following criteria, listed in order of
importance, govern pick interval selection. (1)
The intervals shall be in a region of the
normalized signal where the reference signal
meets the requirements of Section 2.3 and is
everywhere greater than zero. (2) The
Intervals (near and far) with the minimum
average emplitude are chosen. (3) If more
than one interval with the same minimum
average amplitude is found, the interval
closest to the plume is chosen. (4) The
standard deviation. S0. for the calculated
opacity shall be 8% or less. (S0 is calculated
by Equation AM1-7).
If S0 is greater thaji 8%. then the far pick
interval shall be changed to the next interval
of minimal average amplitude. If S, is still
greater than 8%. then this procedure is
repeated for the far pick interval. This
procedure may be repeated once again for the
near pick interval, but if S0 remains greater
than 8%. the plume signal shall be discarded.
The reference signal pick intervals. Rn and
R(, must be chosen over the same time
>•
The standard deviation. Si,,, of the set of
amplitudes for the near-region pick interval.
!„. shall be calculated using Equation
(AMl-5).
[m ( Ini ' !„ )z~| %
1=1 (m-l) J
(AMl-5)
Similarly, the standard deviations Su, SRn,
and SB, are calculated with the three
expressions in Equation (AMl-6).
1=1
(m-l)
f; ( Rfi • «t >']*
1.1=1 (m-l) J
: _ I J fl f I The standard deviation. So. for each
If ~ ,_, t ,. ' associated opacity value, Op, shall be
L l-A I"! il J calculated using Equation (AM1-7).
The calculated values of !„, l(. Rn. R,, SIB. S|f,
SH,,. SR(, Op. and S, should be recorded. Any
plume-signal with an S0 greater than 8% shall
be discarded.
2.8.1 Azimuth Angle Correction. If the
azimuth angle correction to opacity specified
in this section is performed, then the
elevation angle correction specified in
Section 2.6.2 shall not be performed. When
opacity is measured in the residual region of
an attached steam plume, and the lidaV line-
(AM1-7)
of-sight is not perpendicular to the plume, it
may be necessary to correct the opacity
measured by the lidar to obtain the opacity
that would be measured on a path
perpendicular to the plume. The following
method, or any other method which produces
equivalent results, shall be used to determine
the need for a correction, to calculate the
correction, and to document the point within
the plume at which the opacity was
measured.
interval as the plume signal pick intervals, I,
and If. respectively [Figure AM1-III). Other
methods of selecting pick intervals may be
used if they give equivalent results. Field-
oriented examples of pick interval selection
are available in Reference 5.1.
The average amplitudes for each of the
pick intervals. !„, I(, RD. R* shall be calculated
by averaging the respective individual
amplitudes of the sample intervals from the
plume signal and the associated reference
signal each corrected for 1/R1. The amplitude
of !„ shall be calculated according to
Equation (AM-3).
1
=
(AM1-3)
where:
In,=the amplitude of the ith sample interval
(near-region),
2 = sum of the individual amplitudes for the
sample intervals.
m = number of sample intervals in the pick
interval, and
!„ = average amplitude of the near-region pick
interval.
Similarly, the amplitudes for If. Rn, and R,
are calculated with the three expressions in
Equation (AMl-4).
. =i
f m
m
I
fi '
(AMl-4)
(AMl-6) '
Figure AMl-fV(b) shows the geometry of
the opacity correction. L' is the path through
the plume along which the opacity
measurement is made. P' is the path
perpendicular to the plume at the same point.
The angle < is the angle between L' and the
plume center line. The angle (jr/2-e). is the
angle between the L' and P'. The measured
opacity. Op. measured along the path L' shall
be corrected to obtain the corrected opacity,
Ope, for the path P', using Equation (AMl-6).
pc
- op)Cos
- On)
P
Sin
(AMI-8)
The correction in Equation (AMl-8) shall
be performed if the inequality in Equation
(AMl-9) is true.
e > Sin
., I" In (1.01 - Op) "I
L ln »- v J
(AMI-9)
Figure AMl-IV(a) shows-trie geometry
used to calculate t and the ppsition in the
plume at which the lidar measurement is
made. This analysis assumes that for a given
lidar measurement, the range from the lidar
to the plume, the elevation angle of the lidar
from the horizontal plane, and the azimuth
angle of the lidar from an arbitrary fixed
reference in the horizontal plane can all be
obtained directly.
BILLING CODE ISM-M-M
V-485
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Projection of P onto the yz-plane, P "
00
CTl
Plume measurement position
R
W *'• V
Plume drift angle position
Pa (Ra. *' *a'. Pa>! ••'
L1dar Position
a.
CD
CD
era
5*
Lidar Line-of-Sight.
Position P_,
(b) P
Projection of Pfl onto the xy-plane, P '
Figure AMI - IV. Correction In Opacity for Drift of the
Residual Region of an Attached Steam Plume.
BILLINO CODE »5BO-J»^
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Federal Register / Vol. 46. No. 208 / Wednesday. October 28, 1981 / Rules and Regulations
R, = range/rom lidar to source*
/3, = elevation angle of R,*
R. = range from lidar to plume al the opacity
measurement point*
0, = elevation angle of Rp'
R, = range from lidar to plume at some
arbitrary point. P., so the drift angle of
the plume can be determined*
0, = elevation angle of R.*
a = angle between R, and R.
R', = projection of R, in the horizontal plane
R'. = projection of R, in the horizontal plane
R'. = projection of R. in the horizontal plane
' = angle between R'; and R'p*
a'= angle between R', and R'.*
RS = distance from the source to the opacity
measurement point projected in the
horizontal plane
Ra = distance from opacity measurement
point Pp to the point in the plume P..
= Sin-'
R Sina
, (AMI-ID)
The correction angle t shall be determined
using Equation A.M1-10.
where:
n = Cos"' (Cos/J, Cos0. Cosct' -t- Sin/i, Sin/y.
and
Ra = (IV + R.2-2 RB R. Cosa)1':
R6. the distance from the source to the
opacity measurement point projected in the
horizontal plane, shall be determined using
Equation AMl-11.
V
R'Cos*1
(AMl-11)
where:
R'. = R, Cos0,. and
R. = R0Cos/3B.
In the special case where the plume
center-line at the opacity measurement point
is horizontal, parallel to the ground. Equation
AMl-12 may be used to determine t instead
of Equation AMl-10.
f. - Cos-
R 2 + R 2 - R"2
p 6 s
2RpRs
1 (AMl-12)
where:
If the angle t is such that «•„ 30 or t ^
150'. the azimuth angle correction shall not
be performed and the associated opacity
value shall be discarded.
2.6.2 Elevation Angle Correction. An
individual lidar-measured opacity. Op. shall
be corrected for elevation angle if the laser
elevation or inclination angle. /3P [Figure
AMl-V). is greater than or equal to the value
calculated in Equation AM1-13.
> Cos ''
lnd.01 -
- V
(AMI-13)
The measured opacity. OB. along the lidar opacity. Op,, for the actual plume (horizontal|
path L. is adjusted to obtain the corrected path. P. by using Equation (AM1-14).
PC
« 1 - (1 -
(AM1-14)
where:
0t = lidar elevation or inclination angle.
O0 = measured opacity along path 1.. and
O,,, = corrected opacity for the actual plume
thickness P.
The values for /30. O, and Op, should !»•
recorded.
•IU.MO CODE 6MO-M-M
'Obtained directly from lidar. These value*
should be recorded.
V-487
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Stack's Vertical Axis
Horizontal Plane
00
00
_ E
Lidar Line-of-Sight
Referenced to Level Ground
(Horizontal Plane)
Vertical Smoke Plume
R , Lidar Elevation or
Inclination Angle
IP
8-
50
&
I
= Effective Plume Thickness
= Actual Plume Thickness
= LCOSlr.p
= Opacity measured along path L
= Opacity value corrected to the
actual plume thickness, P
s.
3
n
109
a.
B)
o
S
09
Q.
50
|
E"
5'
M
Figure AM1-V. Elevation Angle Correction for Vertical Plumes.
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2.6.3 Determination of Actual Plume
Opacity. Actual opacity of the plume shall be
determined by Equation AMI-IS.
pa
pc
(AMI-IS)
2.6.4 Calculation of Average Actual Plume
Opacity. The average of the actual plume
opacity. Op., shall be calculated as the
average of the consecutive individual actual
opacity values. OM. by Equation AM1-16.
n
I
lc=l
<°pa>K
(AM1-16)
where:
(OM)k=the kth actual opacity value in an
averaging interval containing n opacity
values; k is a summing index.
Z=the sum of the individual actual opacity
values.
n=the number of individual actual opacity
values contained in the averaging
interval.
0.. = average actual opacity calculated over
the averaging interval.
3. Lidar Performance Verification. The
lidar shall be subjected to two types of
performance verifications that shall be
peformed in the field. The annual calibration,
conducted at least once a year, shall be used
to directly verify operation and performance
of the entire lidar system. The routine
verification, conducted for each emission
source measured, shall be used to insure
proper performance of the optical receiver
and associated electronic*.
3.1 Annual Calibration Procedures. Either
a plume from • smoke generator or screen
targets shall be used to conduct this
calibration.
If the screen target method is selected, five
screens shall be fabricated by placing an
opaque mesh material over • narrow frame
(wood, metal extrusion, etc.). The screen
shall have • surface area of at least one
square meter. The screen material should be
chosen for precise optical opacities of about
10. 20.40,60, and 80%. Opacity of each target
shall be optically determined and should be
recorded. If • smoke generator plume Is
selected, it shall meet the requirements of
Section 3.3 of Reference Method 9. This
calibration shall be performed in the field
during calm (as practical) atmospheric
conditions. The lidar shall be positioned in
accordance with Section 2.1.
The screen targets must be placed
perpendicular to and coincident with the
lidar line-of-sight at sufficient height above
the ground (suggest about 30 ft) to avoid
ground-level dust contamination. Reference
signals shall be obtained Just prior to
conducting the calibration test.
The lidar shall be aimed through the center
of the plume within 1 stack diameter of the
exit, or through the geometric center of the
screen target selected. The lidar shall be set
in operation for a 6-minute data run at a
nominal pulse rate of 1 pulse every 10
seconds. Each backscarter return signal and
each respective opacity value obtained from
the smoke generator transmissometer. shall
be obtained in temporal coincidence. The
data shall be analyzed and reduced in
accordance with Section 2.6 of this method.
This calibration shall be performed forO%
(clean air), and at least five other opacities
(nominally 10.20.40,60, and 80%).
The average of the lidar opacity values
obtained during a 6-minute calibration run
shall be calculated and should be recorded.
Also the average of the opacity values
obtained from the smoke generator
transmissometer for the same 6-minute run
shall be calculated and should be recorded.
Alternate calibration procedures that do
not meet the above requirements but produce
equivalent results may be used.
3.2 Routine Verification Procedures.
Either one of two techniques shall be used to
conduct this verification. It shall be
performed at least once every 4 hours for
each emission source measured. The
following parameters shall be directly
verified.
1) The opacity value of 0% plus a minimum
of 5 (nominally 10,20.40,60. and 80%)
opacity values shall be verified through the
PMT detector and data processing
electronics.
2) The zero-signal level (receiver signal
with no optical signal from the source
present) shall be inspected to insure that no
spurious noise is present in the signal. With
the entire lidar receiver and analog/digital
electronics turned on and adjusted for normal
operating performance, the following
procedures shall be used for Techniques 1
and 2, respectively.
3.2.1 Procedure for Technique 1. This test
shall be performed with no ambient or stray
light reaching the PMT detector. The narrow
band filter (694.3 nanometers peak) shall be
removed from its position in front of the PMT
detector. Neutral density filters of nominal
opacities of 10, 20.40.60. and 80% shall be
used. The recommended test configuration is
depicted in Figure AMl-Vl.
BILLING CODE SSSO-3S-M
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Federal Register / Vol. 46. No. 208 / Wednesday. October 28.1981 / Rules and Regulations
PMT Entrance
Window Completely
Covered
[
Lldar Receiver
Photomultlplier
Detector
(a) Zero'-Slgnal Level Test
CW Laser or
Light-Emitting Diode
(Light Source)
light path
Lidar Receiver
Photomultiplier
Detector
(b) Clear-Air or 0% Opacity Test
Neutral-density
optical filter
CW Laser or
Light-Emitting Diode
(Light Source)
light path
Lidar Receiver
Photomultiplier
Detector
(c) Optical Filter Test (simulated opacity values)
*Tests shall be performed with no ambient or stray light reaching the
detector.
Figure AM1-VI. Test Configuration for Technique 1
nume cooc MM-M-C
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The zero-signal level shall be measured
mi should be recorded, as indicated in
Kigure AMl-VI(a). This simulated clear-air or
;r'i> opacity value shall be tested in using the
selected light source depicted in Figure AM1-
The light source either shall be a
continuous wave (CW) laser with the beam
mechanically chopped or a light emitting
diode controlled with a pulse generator
(rectangular pulse). (A laser beam may have
to be attenuated so as not to saturate the
PMT detector). This signal level shall be
measured and should be recorded. The
opacity value is calculated by taking two pick
intervals (Section 2.6] about 1 microsecond
apart in time and using Equation (AMl-2)
setting the ratio R*/R(=1. This calculated
value should be recorded.
The simulated clear-air signal level is also
employed in the optical test using the neutral
density filters. Using the test configuration in
Figure AMl-VI(c). each neutral density filter
shall be separately placed into the light path
from the light source to the PMT detector.
The signal level shall be measured and
should be recorded. The opacity value for
each filter is calculated by taking the signal
level for that respective filter (I,), dividing it
by the 0% opacity signal level (I.) and
performing the remainder of the calculation
by Equation (AMl-2) with Rn/R,=l. The
calculated opacity value for each filter should
be recorded.
The neutral density filters used for
Technique 1 shall be calibrated for actual
opacity with accuracy of ±2% or better. This
calibration shall be done monthly while the
filters are in use and the calibrated values
should be recorded.
3.2.2 Procedure for Technique 2. An
optical generator (built-in calibration
mechanism) (hat contains a light-emitting
diode (red light for a lidar containing a ruby
laser) is used. By injecting an optical signal
into the lidar receiver immediately ahend of
the PMT detector, a backscatter signal is
simulated. With the entire lidar receiver
electronic* turned on and adjusted for normal
operating performance, the optical generator
is turned on and the simulation signal
(corrected for 1/R'J is selected with no plume
spike signal and with the opacity value equal
to 0%. This simulated clear-air atmospheric
return signal is displayed on the system's
video display. The lidar operator then makes
any fine adjustments that may be necessary
to maintain the system's normal operating
range.
The opacity values of 0% and the other five
values are selected one at a time in any
order. The simulated return signal data
should be recorded. The opacity value shall
be calculated. This measurement/calculation
shall be performed at least three times for
each selected opacity value. While the order
is not important, each of the opacity values
from the optical generator shall be verified.
The calibrated optical generator opacity
value for each selection should be recorded.
The optical generator used for Technique 2
shall be calibrated for actual opacity with an
accuracy of ±1% or better. This calibration
shall be done monthly while the generator is
in use and calibrated value should be
recorded.
Alternate verification procedures that do
not meet the above requirements but produce
equivalent results may be used.
3.3 Deviation. The permissible error for
the annual calibration and routine
verification are:
3.3.1 Annual Calibration Deviation.
3.3.1.1 Smoke Generator. If the lidar-
measured average opacity for each data run
is not within ±5% (full scale) of the
respective imoke generator'* average opacity
over the range of 0% through 60%. then the
lidar shall be considered out of calibration.
3.3.1.2 Screens. If the lidar-measured
average opacity for each data run is not
within ±3% (full scale) of the laboratory-
determined opacity for each respective
simulation screen target over the range of 0%
through 80%. then the lidar shall be
considered out of calibration.
3.3.2 Routine Verification Error. If the
lidar-measured average opacity for each
neutral density filter (Technique 1) or optical
generator selection (Technique 2) is not
within ±3% [full scale) of the respective
laboratory calibration value then the lidar
shall be considered non-operational.
4. Performance/Design Specification for
Basic Lidar System.
4.1 Lidar Design Specification. The
essential components of the basic lidar
system are a pulsed laser (transmitter).
optical receiver, detector, signal processor.
recorder, and an aiming device that is used in
aiming the lidar transmitter and receiver.
Figure AM1-VII shows a functional block
diagram of a basic lidar system.
SILLING CODE 6SM-M-M
V-491
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Transmitted Light Pulse |
BacKscatter Return Signal
| Pulsed
Laser
Narrow Band Optical Filler
t
Optical
Receive*
t
Aiming Device
/
Steerable Mount
Video Signal
1
1
1 ClOCK 1
1
Signal Processor 1
!
Recorder
H
Video
Display
n
IS.
5
*>.
vo
N)
BILUNO CODE esao-ss-c
Figure AMI-VII functional Stock Diogiam of a Btnit lie/or System
to
I
0)
Q.
0)
ve
O
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s
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Federal Register / Vol. 46. No. 208 / Wednesday. October 28, 1981 / Rules and Regulations
•1.2 Performance Evaluation Test*. The
owner of a lidar system shall subject such •
lidar system to the performance verification
tests described in Section 3. The annual
calibration shall be performed for three
separate, complete runs and the results of
each should be recorded. The requirements of
Suction 3.3.1 must be fulfilled for each of the
three runs.
Once the conditions of the annual
calibration are fulfilled the lidar shall be
subjected to the routine verification for three
separate complete rung. The requirements of
Soction 3.3.2 must be fulfilled for each of the
three runs and the results should be recorded.
The Administrator may request that the
results of the performance evaluation be
submitted for review.
5. References.
5.1 The Use of Lidar for Emissions Source
Opacity Determination, U.S. Environmental
Protection Agency. National Enforcement
Investigations Center, Denver, CO. EPA-330/
1-79-003-R. Arthur W. Dybdahl, current
edition (NTIS No. PB81-246662).
5.2 Field Evaluation of Mobile Lidar for
the Measurement of Smoke Plume Opacity.
U.S. Environmental Protection Agency.
National Enforcement Investigations Center.
Denver. CO, EPA/NEIC-TS-12B, February
1976.
5.3 Remote Measurement of Smoke Plume
Transmittance Using Lidar, C. S. Cook, G. W.
Bethke, W. D. Conner (EPA/RTP). Applied
Optics 11. pg 1742, August 1972.
5.4 Lidar Studies of Stack Plumes in Rural
and Urban Environments. EPA-650/4-73-002,
October 1973.
5.5 American National Standard for the
Safe Use of Lasers ANSI Z 136.1-176.8 March
1976.
5.6 U.S. Army Technical Manual TB MED
279. Control of Hazards to Health from Laser
Radiation, February 1969.
5.7 Laser Institute of America Laser
Safety Manual, 4th Edition.
5.8 U.S. Department of Health. Education
«nd Welfare. Regulations for the
Administration and Enforcement of the
Radiation Control for Health and Safety Act
of 1968, January 1976.
5.9 Laser Safety Handbook. Alex Mallow.
Leon ChaboU Van Nostrand Reinhold Co.,
1978.
*****
|KR Doe. 81-31241 Filed 10-27-81: MS im|
•IUIMO CODE AMO-M-M
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Federal Register / Vol. 46, No. 219 / Friday, November 13, 1981 / Rules and Regulations
132
40 CFR Part 60
AE-FRL-1895-3]
Waiver From New Source Performance
Standard for Homer City Unit No. 3
Steam Electric Generating Station;
Indiana County, Pa.
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: Pursuant to section lll(j) of
the Clean Air Act, as amended (the Act),
42 U.S.C. 7411(j), the Environmental
Protection Agency (EPA) hereby grants
an innovative technology waiver to
Homer City Steam Electric Generating
Station; Indiana County, Pennsylvania.
The statutory waiver will allow
emissions from Unit No. 3 at Homer City
Steam Electric Generating Station to
exceed the Standards of Performance
for New Stationary Sources for control
of sulfur dioxide (SO2) for a limited time
period to provide an opportunity to
adequately demonstrate a new
precombustion coal cleaning technology.
DATES: Pursuant to section 553(d)(l) of
the Administrative Procedures Act, 5
U.S.C. 553(d)(l), this waiver is effective
November 13,1981.
FOR FURTHER INFORMATION CONTACT:
Stuart I. Silver-man, Esq., or Louis R.
Paley, P.E., Division of Stationary
Source Enforcement, U.S. Environmental
Protection Agency, EN-341,401 M
Street, SW., Washington, D.C. 20460,
(202) 382-2858 and (202) 382-2884.
respectively.
SUPPLEMENTARY INFORMATION: Homer
City Steam Electric Generating Station
(hereinafter Homer City) is located in
Center Township, Indiana County,
Pennsylvania (Southwest Pennsylvania
Air Quality Control Region) and is
jointly owned by Pennsylvania Electric
Company (a subsidiary of General
Public Utilities Corporation) and by
New York State Electric & Gas
Corporation. Pennsylvania Electric
Company and New York State Electric &
Gas Corporation (hereinafter also
known as "owners and operator" or
"Company") are corporations registered
in accordance with the corporate laws
of the Commonwealth of Pennsylvania
and the State of New York, respectively.
Homer City is operated by
Pennsylvania Electric Company and
consists of two 600 megawatt coal-fired
electric generating boilers (Units Nos. 1
and 2) each with an 809 foot (246.6
meters) stack and one 650 megawatt
coal-fired electric generating boiler (Unit
No. 3) with a 1,200 foot (365.8 meters)
stack.
Federal law requires Units Nos. 1, 2,
and 3 to limit total emissions of certain
air contaminants. Most pertinent for this
rulemaking are sulfur dioxide (SO2)
emissions from Units Nos. 1, 2, and 3
resulting from coal combustion during
the generation of electrical power. All •
three generating units utilize bituminous
coal as fuel.
Under the Pennsylvania State
Implementation Plan, Units Nos. 1 and 2
may not emit more than 4.0 Ibs of SOj/
106 Btu of heat input.1 Unit No 3 is
subject to Federal Standards of
Performance for New Stationary
Sources for SOa under Section 111 of the
Act,2 42 U.S.C. 7411, and may not emit
1 Pennsylvania Department of Environmental
Resources: rules and regulations; { 123.22(c) (as
adopted on January 27,1972). Pursuant to section
110 of the Act, 42 U.S.C. 7410, ! 123.22(c) was
approved on May 31,1972, as part of the
Pennsylvania State Implementation Plan and
thereby federally enforceable.
"Federal Standards of Performance for New
Stationary Sources under section 111 of the Act are
technology based emission limitations promulgated
by the Administrator pursuant to section
lll(b)(l)(B), 42 U.S.C. 7211(b)(l)(B), for certain
enumerated new source categories.
more than 1.2 Ibs of SO2/10* Btu of heat
input.8
On February 6,1981, at 46 FR11490,
EPA proposed to grant, subject to the
concurrence of the Governor of the
Commonwealth of Pennsylvania, an
innovative technology waiver, pursuant
to section lll(j) of the Act, to the Homer
City Steam Electric Generating Station;
Indiana County, Pennsylvania. The
waiver would allow emissions from Unit
No. 3 at Homer City to exceed the
Federal Standards of Performance for
New Stationary Sources for control of
SOi for a limited period and under
specific enforceable terms and
conditions. Specifically, the statutory
waiver would provide an opportunity to
adequately demonstrate at generating
Unit No. 3 a new innovative
technological system of achieving
continuous reductions of SO» emissions
generated from coal combustion in
electric utility boilers. The innovative
control system, known as the Multi-
Stream Coal Cleaning System (MCCS) is
a precombustion coal cleaning technique
designed to produce a deep cleaned
(low sulfur) coal and a middling
(medium sulfur) coal by physically
removing pyritic sulfur from coal used
as a boiler fuel for electrical power
generation. There is substantial
likelihood that the resultant deep
cleaned coal will enable Unit No. 3 to
comply with the Federal Standards of
Performance for New Stationary
Sources of 1.2 Ibs of SO2/106Btu. The
middling coal will be sufficiently
cleaned to enable Units Nos. 1 and 2 to
comply with the Pennsylvania State
Implementation Plan emission limitation
of4.0lbsofSO2/106Btu.
Public comments and requests for a
public hearing were invited concerning
the waiver proposal. Although EPA did
not receive any requests for a public
hearing, numberous written comments
were received in response to the
proposed innovative technology waiver.
With the exception of comments
submitted on behalf of the owners and
operator of Homer City as well as the
Commonwealth of Pennsylvania, all
comments received by EPA were fully
supportive of the waiver as proposed.
Those comments submitted on behalf of
the Company and the Commonwealth of
Pennsylvania which necessitated
modifications in the waiver proposal of
a nonsubtantive nature as a result of
administrative oversight will not be
addressed in this final rulemaking. All
others submitted on behalf of the
'40 CFR 60.43(a)(2) [July 1,1979); 39 FR 20792.
June 14,1974, as amended at 41 FR 51398. November
22,1976.
V-494
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 / Rules and Regulations
Company and the State are individually
considered below.
By letter dated September 23.1961. the
Honorable Richard Thornburgh.
Governor of the Commonwealth of
Pennsylvania, concurred in the
innovative technology waiver as set
forth herein. Under section lllfjMIHA}
of the Act 42 U.S.C. 7411(i)(l)(A). such
concurrence is a prerequisite for the
granting of a innovative technology
waiver by the Administrator under
section lll(j) of the Act The waiver a»
set forth herein is hereby granted.
Final Agency Action
The innovative technology waiver as
specified below is final Agency action.
and as such, is judicially reviewable
under section 307(b) of the Act. 42 U.S.C.
~607(b) in the United States Court of
Appeals, Third Circuit. Petitions for
judicial review must be filed on or
before January 12.1982.
Note.—Pursuant to Section 605(b) of the
Regulatory Flexibility Act. I certify that this
rule will not have a significant economic
impact on a substantial number of small
entities because it affects only a single
facility.
Under Executive Order 12291. EPA must
judge whether a regulation is "Major" and
thereby subject to the requirements of a
Regulatory Impact Analysis. This regulation
is not Major because it provides, pursuant to
section lll(j) of the Act, a waiver from
certain environmental requirements for a
specified time period to enable
demonstration of innovative technology for
the control of a pollutant Such technology is
likely to achieve pollutant emission
reductions at lower cost in terms of energy,
economic and nonair quality environmental
impact. Therefore, the waiver reduces, for an
interim period, normal regulatory
requirements and enhances the prospects of
developing more cost effective pollution
control technology.
This regulation has been submitted to the
Office of Management and Budget for review
as required by Executive Order 12291.
Dated: October 31.1981.
Anne M. Gorauch,
Administrator.
Response to Comments
1. Extension of Waiver Period.
Pennsylvania Electric Company and
the New York State Electric & Gas
Corporation commented that the
innovative technology waiver for Homer
City Unit No. 3 should be extended
beyond December 1,1981. the date EPA
has proposed for conclusion of the
waiver period The Company requested
an additional twelve months and
contended that such an extension of the
waiver period is justified given certain
purported delays in implementation of
the MCCS during initial phases of
control system experimentation. It was
alleged that these delays were beyond
the control of the Company due. in part
to an evalaatian program initiated by
•EPA which required combustion of run-
of-rrrine coal at Homer City Unit No. 3.
Notwithstanding whatever initial
delays may have occurred in the
implementation of the MCCS, the
Company's reqnest for a waiver
extension beyond December 1,1981, is
contrary to the plain language of section
111 of the Act. Under section
lll(j)(l)(E). 42 U.S.C. 7411(j)(lME), a
waiver for a qualifying source, or
portion thereof, may not extend beyond
the date ft) seven years after the date on
which any waiver is granted to such
source or portion thereof or (ii) four
years after the date on which such
source or portion thereof commences
operation, whichever is earlier. Given
Homer City Unit No. 3 commenced
operation on December 1,1977. a fact
uncontested by the Company, a section
lll(j) innovative technology waiver for
this combustion source may not extend
beyond December 1,1981.
Pennsylvania Electric Company and
the New York State Electric & Gas
Corporation contend, however, that EPA
must exercise the discretion the
Company apparently believes is
available to the Agency and determine
that the "portion" (i.e., MCCS) of the
source for which the waiver was sought
did not start operating until
approximately twelve months
subsequent to commencement of
operation by Homer City Unit No. 3.
Thus, the Company requested that the
Agency consider the twelve-month delay
in the commencement of operations of
the MCCS in determining the
appropriate length of time under section
lll(j)(l)[E) for an innovative technology
waiver for combustion Unit No. 3.
The basis of the Company's waiver
extension request rests upon an
erroneous interpretation of "stationary
source" as that term is defined under
section 111 of the Act and implementing
regulations. Section lll(a)(3) of the Act
42 U.S.C 7411(aX3), defines "stationary
source" as "any-building, structure,
facility, or installation which emits or
may emit any air pollutant" (emphasis
added). Further, "affected facility" is
equated at 40 CFR 60.2(e) with "any
apparatus to which a standard is
applicable." Given that both the MCCS
and combustion Unit No. 3 are governed
by separate standards of performance
under section 111, each is an "affected
facility" and a separate stationary
source rather than a single source as the
Company contends.4The Company has
requested an innovative technology
waiver solely for combustion Unit No. 3.
Thus, consideration of the date for
commencement of operation of the
MCCS would be inappropriate for
arriving at the expiration date for a
section lll(j) waiver applicable to Unit
No. 3.
2. Waiver Emission Limits for Homer
City Units Nos. J and 2.
Pennsylvania Electric Company and
the New York State Electric & Gas,
Corporation questioned the need for SOi
emission limitations for Homer City
Units Nos. 1 and 2 specified in the
proposed waiver during time periods
when Homer City Unit No. 3 is
inoperable during the waiver period.
During such periods, the Company
contended that Units Nos. 1 and 2
should be allowed to emit up to 4.0 Ibs
SO,/106Bru. the allowable SO, emission
limitation under the Pennsylvania State
Implementation Plan, rather than the
more restrictive SO, emission
limitations as specified in the waiver.
The Company argued that the waiver's
emission limits would not be needed to
fully compensate for increases in SOj
emissions from Unit No. 3 during periods
when Unit No. 3 is inoperable.
EPA disagrees with the Company's
comment. Given the nature of the
experimentation and demonstration
program at the Homer City MCCS. it is
likely that during the waiver period.
Unit No. 3 will be shut down
intermittently both on a routine, planned
and unplanned basis. Thus, for the
purpose of ensuring protection of
national ambient air quality standards
during the waiver period, predictable
and consistent SO, emission limitations
for Units Nos. 1, 2 and 3 are required to
enable the enforcement of and source
compliance with these waiver limits on
a continuous basis.
3. Delegation of Authority to States
Under Section 111 and Source Specific
Innovative Technology Waivers.
The Department of Environmental
Resources (DER), on behalf of the
Commonwealth of Pennsylvania.
submitted comments in response to
EPA's proposed innovative technology
waiver which raise a number of Federal-
State jurisdictional issues regarding
implementation and enforcement of
Standards of Performance for New
Stationary Sources under section 111 of
the Act
More specifically, pursuant to section
lll(c) at 45 FR 3109 (January 10,1980),
the authority to implement and enforce
• See: ASARCO. Inc. v. EPA. 578 F. 2d 318 (1978):
United Stale* *. City of Painesville. 644 F. 2d 1188
(6th Clr. 1981 p. Potomac Electric Power Company.
No. 80-1255 (4th Cir.. June 4.1981); Sierra Pacific
Power Company v. EPA. 647 F. 2d 60 (9th Cir. 1981).
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Standards of Performance for New
Stationary Sources (promulgated as of
July 1.1978 in 40 CFR Part 60) was
delegated to the Commonwealth of
Pennsylvania for sources located in the
State. This delegation encompassed the
authority to implement and enforce the
Federal Standards of Performance for
New Stationary Sources for SOi
applicable to Homer City Unit No. 3. In
view of this delegation of authority, DER
questioned the legality of EPA's
statement in the Federal Register waiver
proposal which indicated that during the
period the innovative technology waiver
is effective, the delegated authority of
the Commonwealth of Pennsylvania to
enforce the Federal Standards of
Performance for New Stationary
Sources for SO> applicable to Unit No. 3
would be superceded and enforcement
of the terms and conditions of the
waiver shall be the responsibility of
EPA.
DER's comment concerns both the
very nature of the Administrator's
authority under section lllfj) of the Act
to grant innovative technology waivers
as well as the scope of authority
delegable by the Administrator to a
qualifying State under section lll(c).
Fundamentally, the Administrator of
EPA lacks authority to delegate his
power to States pursuant to section
lll(c) to issue innovative technology
waivers.9 Given that the terms of the
section lll(j) waiver for Unit No. 3 are
new, temporary Federal performance
standards promulgated subsequent to
and in lieu of those previously delegated
to the Commonwealth of Pennsylvania,
9 Support for this limitation of authority is
threefold: First, issuance of a section lll(j) waiver
is in the nature of standard setting. The Congress
contemplated that standard setting either under
section lll(b)(l)(B) or lll(j) is within the sole
power of the Administrator of EPA. not the power of
the States. Further. Section lll(c) provides for
delegation to qualifying States only the power to
"enforce"& performance standard established
either under section lll(b)(l)(B) or lll(j) of the Act.
Second, (he Congress strictly limited the use of
Section lll(j). Section lll(j)(l)(c) provides that no
more innovative technology waivers may be granted
than "the Administrator finds necessary" to
determine if a particular technology will yield
greater emission reductions than otherwise required
or yield equivalent reductions at lower cost. The use
of Section lll(j) could not reasonably be so limited
if innovative technology waivers were being
granted by States throughout the country.
Delegation of authority to States under section
lll(c) to issue innovative technology waivers would
therefore be contrary to the terms and purposes of
section lll(j). Finally, Congress specifically
provided a role for the States in section lll(j)(l)(A)
which provides that the consent of the Governor of
the State for the issuance of a waiver. In enacting
this provision, the Congress was aware that State
participation could be provided instead by allowing
the Administrator to delegate the power to issue
innovative technology waivers. Congress chose,
however, to grant the States only the more limited
concurrence power under section lll(j)(l)(A).
such performance standards
predominate during the waiver period-
As noted in the previously published
waiver proposal and in this final
rulemaking, the Commonwealth of
Pennsylvania may, and is encouraged to
seek delegation of authority, pursuant to
section lll(c)(l), to enforce the
temporary Federal Standards of
Performance for New Stationary
Sources specified in this waiver. In
response to this invitation for delegation
which appeared in the waiver proposal,
DER contended that such delegation is
unnecessary due to an existing State
court decree, entered in the
Commonwealth Court of Pennsylvania
(No. 161 C.D. 1981) on January 26,1981,
which, in most respects, mirrors the
fundamental terms and conditions of the
innovative technology waiver for Unit
No. 3. EPA agrees and does not intend,
by promulgation of an innovative
technology waiver for Unit No. 3, to
supplant the independent authority of
the Commonwealth of Pennsylvania to
enforce its own rales and regulations
duly promulgated pursuant to state law.
Further, the terms and conditions under
which the Company may operate Homer
City Units No. 1, 2 and 3 during the
waiver period are conditioned by the
terms of the waiver as granted herein as
well as the terms of the State court
decree entered in the Commonwealth
Court of Pennsylvania on January 28,
1981. In granting the waiver, EPA does
not believe that the terms and
conditions of the waiver are in conflict
with the provisions of the State court
decree. Additionally, the innovative
technology waiver does not supersede,
change or modify any of the provisions
of the State court decree, be they
methods of monitoring compliance,
interim emission limitations, or any
other provisions thereof.
4. Stringency of Monitoring and
Reporting Requirements.
The Company made the general
comment that the monitoring and
reporting requirements in the proposed
waiver were more stringent than
necessary and should be changed to
resemble those presently imposed by the
Standards of Performance for New
Stationary Sources for fossil-fuel-fired
steam generators. However, section
lll(j)(l)(B)(i) of the Act requires that an
innovative technology waiver be
granted on such terms and conditions as
the Administrator determines necessary
to ensure that emissions from the source
will not prevent attainment and
maintenance of national ambient air
quality standards. Therefore, the
stringency of the waiver's monitoring
and reporting requirements were
specifically designed to ensure
acquisition of emission data of sufficient
quality and quantity to allow the
continual determination of control
system performance and source
compliance with waiver emission
limitations established in conformity
with section lll(j)(l)(B)(i).
EPA has considered various means of
clarifying and streamlining the ~"
monitoring and reporting requirements
that were contained in the proposed
waiver. As a result, the monitoring and
reporting requirements that appear in
the innovative technology waiver
granted herein are modifications of
those which were proposed. However,
such changes will not result in
sacrificing the quantity and quality of
data essential to ensure protection of
ambient air quality standards during the
waiver period. EPA finds the monitoring
proposed for this waiver period is
compatible with that required under
state law. Compliance with the waiver's
monitoring requirements does not
excuse compliance with state
monitoring requirements.
5. "Discrete" Versus ("Rolling")
"Running " A verages.
DER commented that the proposal
was internally inconsistent because its
reporting requirements prescribed
"discrete" 3- and 24-hour standards,
while its emission limitations required
("rolling") "running" 3- and 24-hour
standards. Note, "Running" and
"Rolling" averages are (mathematically)
identical. For consistency with previous
EPA standards the term "rolling"
average (e.g., 1:00 to 4:00 o'clock, 2:00 to
5:00 o'clock, etc.) will be used, rather
than "running". The "discrete versus
running" inconsistency has been
resolved by changing all references to 3-
and 24-hour standards to read
"discrete". The use of 3- and 24-hour
discrete (e.g., 3:00 to 6:00 o'clock; 6:00 to
9:00 o'clock) averaging periods (rather
than rolling) in these standards is
considered adequate to protect the 3-
and 24-hour NAAQS and to represent 3-
and 24-hour source emissions."
Additionally, discrete 3- and 24-hour
averaging periods allow the use of both
continuous emission monitoring systems
(GEMS) and continuous bubblers (CB)
as the primary and secondary
compliance methods. Given the
possibility of CEMS breakdown,
Company use of a back-up (secondary)
• While EPA considers discrete averaging periods
adequate to protect the 3- and 24-hour NAAQS the
Agency interprets the NAAQS to actually be
running averages. 40 CFR Part 58, Appendix F,
{ 2.12. 44 FR 27597 (May 10.1979). Guidelines For
The Interpretation of Air Quality Standards.
OAQPS No, 1.2-008 (February 1977).
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method for collecting emission data is
essential to granting this waiver.
Because of the need for a simple tow
cost, continuous and very reliable back-
up method, the CB train is considered
the only appropriate back-up method.
Furthermore, requiring 3- and 24-hour
continuous bubbler data on a rolling
basis, which would necessitate the
collection of hourly samples when
continuous monitors are out of service,
is considered unnecessary in this case.
With regard to the longer, 30-day
averaging period required by this
waiver, a rolling 30-day averaging
period (instead of a discrete 30-day
averaging period) has been chosen for
this waiver. Daily computation of the
rolling 30-day average combined
emission rates, for every day of the year,
helps ensure that EPA and the Company
are continually aware of the long-term
performance of the control systems. The
30-day rolling average will also allow
EPA to frequently assess the
environmental impact resulting from
operation of the source and control
systems. In contrast calculation (once
each 30 days) of the discrete 30-day
emission rates would result in updated
emission data only once a month. Such
an infrequent update is considered
insufficient for the continual evaluation
implicit in the provisions of section
lll(j).
6. Calculation of Emissions™
DER commented that although the
proposed waiver required SO, emissions
to be calculated in lb/10'Btu, it did not
specify the method for determining heat
input. This comment incorrectly
described the procedure to be used for
calculating SO, emissions from
individual boilers. The Standards of
Performance for New Stationary
Sources for fossil-fuel-fired steam
generators specifies that sulfur dioxide
emissions (in lb/106Btu) are to be
calculated using SO, and diluent (O, or
CO,) gas concentration data and the
appropriate conversion ("F-factor")
equation. This calculation procedure
was published by the Agency at 40 FR
46250 (October 6,1975), and has since
been widely accepted by EPA and most
State agencies.
The proposed waiver also contained
emission limitations for the combined
emissions from two and from three '
boilers, in units of Ibs SO,/10'Btu and
in units of tons of SO, per unit of time.
Since the emission rates from each
boiler, in units of lb/106 Btu, are not
directly additive, they must first be
converted to the units of Ib SO, per
averaging period in order to determine
the combined average emission rates
from Units Nos. 1, 2, and 3 and from
Units Nos. 1 and 2. This conversion step
requires the calculation of heat input
rates for each boiler. In this regard,
DER'i comment is applicable, and EPA
has, therefore, specified the procedures
to be used for determining heat inputs
for individual boilers.
7. Drift Testing Procedures.
The Company requested that the drift
testing procedures of the proposed
waiver be changed to allow the use of
internal gas cells in their Lear Seigler
SO, and O» moniters. During the waiver
period, EPA will not permit the use of
gas cells in lieu of calibration gases for
the drift tests. When gas cells are used
to calibrate such Lear Siegler monitors,
an important portion of the monitor
circuitry is bypassed, and the monitor
operates in a mode different than during '
the sampling mode. On occasion, EPA
has experienced inadequate evaluations
of the performance of Lear Siegler SO,/
O, monitors because of the limitations
associated with using gas cells. The use
of calibration gases will not alter the
operational mode of the Lear Siegler
monitor and will provide a more
realistic evaluation of the monitor's
performance. Therefore, calibration
gases will be required for all drift testing
required by this waiver.
8. Continuous Bubbler.
DER commented that "the continuous
bubbler has not been proved reliable."
EPA's Emission Standards and
Engineering Division (ESED) has
performed comparative tests in
developing and evaluating the
continuous bubbler (CB) method, and
EPA's Division of Stationary Source
Enforcement (DSSE) has evaluated CB
performance in the laboratory and in the
field. The DSSE and ESED evaluations
of the CB were conducted at fossil-fuel-
fired electric utility steam generators.
These evaluations demonstrated that
the continuous bubbler can be an
acceptable substitute for continuous
emission monitoring systems.
Also indicative of EPA's confidence in
the use of CB technology at facilities
such as the Company's, is the proposal
of the CB technology as Methods 6A and
6B at 46 FR 8359 (January 26,1981).
Method 6A was proposed as an
alternate to Reference Methods 3 and 6.
and Method 6B was proposed as a
substitute for continuous emission
monitors when the monitors are out of
service. Additionally, since the proposal
of the waiver on February 6,1981, the
Company has successfully demonstrated
its ability to accurately and reliably
operate CB systems.
The Company has recently
experimented with various CB
equipment configurations and has
identified modifications to the sampling
apparatus that have produced the best
results. As a result the Company
requested approval to use the following
modifications to the CB sampling
equipment required by the proposed
waiver
a. Use of heated probe for sampling;
b. Use an upstream in-stack filter for
particulate removal;
c. Eliminate the isopropanol impingen
and
d. Replace the peristaltic pump with a
diaphragm pump.
EPA accepts these modifications
because the Company has shown that
they will result in improved bubbler
performance at the Homer City Station
and because they are consistent with
Method 6B (as proposed on January 26,
1981). Nevertheless, the quality
assurance requirements for the CB
method specified in § 60.47(g)[6)(ii) of
the section are in effect during the
waiver period. They require that the
Company demonstrate, at least initially
and quarterly, that the CB method
consistently provides emission data
comparable to data generated by
Reference Methods 3 and 6.
The Company also requested that the
criteria for the allowable percent
difference between CB and reference
method data be changed from 10 percent
to 20 percent. EPA denies this request
because the CB sampling and analytical
techniques for SO, is essentially the
same as that for EPA Reference Method
6. Furthermore, the CB procedures for
collecting and quantifying CO, are
standard laboratory procedures.
Conceptually, the CB is capable of
generating results within 10 percent of
reference method results because of the
similarities between CB and reference
method technologies. Also, in actual
field testing at fossil-fuel-fired steam
generators, the CB results were shown
to be consistently within 10 percent of
the reference method results.
9. Mininum Data Requirements.
DER commented that the proposed
waiver's data requirements were
inadequate and would exempt certain
critical periods of time during which the
Company would not be required to
obtain emission data. The intent of the
waiver was not to allow such
exemptions. EPA has reviewed the
proposed data requirements and agrees
that the allowances provided did not
clearly reflect the Agency's intent.
Therefore, EPA has restructured and
clarified the requirements for obtaining
emission data.
The data requirements have been
organized into three distinct sampling
scenarios. Each scenario applies
separately to each of Homer City Units
Nos. 1, 2. and 3: (1) During normal
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operation of a continuous emission
monitor: (2] during the transition period
when switching from a continuous
emission monitor to a CB system; and
(3) during the continuous operation of
the CB method (when a monitor is out of
service). The data requirements for each
sampling scenario are also separated
into requirements for each of the three
averaging periods (i.e., 3-hours, 24-hours,
and 30-days) specified in the waiver.
Underlying all of the emission
requirements of the waiver is EPA's
intent that the Company monitor the
emissions from each boiler on a
continuous, uninterrupted basis
(whenever fuel is being fired). However,
EPA recognizes that requiring
continuous emission data without
allowing for some interruption is neither
practical, achievable nor necessary.
Even the most well engineered CEMS
cannot be expected to operate over long
periods of time without at least some
breakdowns. Additionally, necessary
routine maintenance and required daily
calibrations preclude the acquisition of
uninterrupted data. Therefore, the
Agency's objective in establishing
minimum data requirements is two-fold:
(1) To provide sufficient emission data
to help ensure Company compliance
with the waiver's emission limitations;
and (2) to allow reasonable periods for
routine monitor maintenance and
calibration, and for the Company to
switch to the secondary compliance
monitoring system (CB method)
whenever monitor breakdowns
necessitate such action.
The Company commented that the
proposed waiver's monitoring
requirements were more stringent and
costly than necessary to achieve the
Agency's stated objective, and that the
data requirements should be more
consistent with those in 40 CFR Part 60,
Subpart D, Standards of Performance for
New Stationary Sources. In response to
this comment, EPA believes that the
waiver's data requirements are
reasonably achievable and are no more
stringent than necessary to ensure
continual source compliance with the
waiver's emission limitations. Since the
waiver stipulates "continuous
compliance" and since the averaging
times of the emission limitations are of
various durations (e.g., 3-hours. 24-
hours, and 30-days), the (40 CFR Part 60.
Subpart D) Standards of Performance
for New Stationary Sources data
acquisition requirements are neither
applicable nor sufficient for this wavier.
Also, given the language contained in
section lll(j) the Agency cannot allow
the Company to be exempted from
demonstrating continuous compliance
with the emission limitations during all
periods of boiler operation.
Furthermore, the Company agreed to
acquire virtually continuous emission
data, using a combination of CEMS and
CBs. As a result the Company has
already acquired the necessary CB
equipment and expertise to use the CBs.
Also the added expense to the
Company, as a result of running the CBs
is insignificant compared to the
operation and maintenance of their coal
cleaning equipment and the savings they
have made by reducing their emissions.
The Company specifically requested
substantial relief from the requirement
to obtain discrete 3-hour continuous
bubbler data when a CEMS is out of
service. In this regard, the Company
suggested several variations of a
calculation procedure for obtaining
upper estimates of any missing 3-hour
data (from one or more units) by
multiplying the highest available
corresponding 3-hour averages (from the
other units) by the ratio of the respective
24-hour averages. EPA believes that the
use of the Company's suggested "
calculation procedure (which assumes a
consistent relationship of maximum 3-
hour to 24-hour emissions between all
three units and which has not been
verified with actual emission data) is
not a prudent alternative to obtaining 3-
hour CB data. In further consideration of
this request, EPA has determined that
the operation of six 3-hour CB systems
(when a CEMS is out of service) will
adequately represent the 3-hour
emission rate and therefore will
sufficiently protect National Ambient
Air Quality Standard.
The Company also maintained that
more than one hour is required to
initiate any back-up samplying. EPA
agrees with this comment and has
therefore increased the time allowed for
the Company to switch from a CEMS to
the CB method. Accordingly, the waiver
requires back-up CB sampling to be
initiated immediately, but no later than
six hours after it has determined that the
CEMS is not meeting the performance
requirements (delineated in Table 1). It
should be noted that a similar time
exemption is not provided when
switching back to (or reinstating) a
CEMS after it has been taken out of
service. In this situation, the Company
must continue samplying with the CB
method until the CEMS is fully
operational and is documented to be
producing valid data.
Also, the waiver allows additional
time exemptions for the Company to
conduct: (1) Routine maintenance and
daily calibrations of the CEMS: and (2)
weekly gas calibrations for the CBs.
However, exemptions from acquiring
continuous data because of routine
maintenance and daily calibrations are
not allowed (nor necessary) when the
CB method is being used.
10. Performance Specifications. DER
commented that the monitor
performance specifications proposed by
EPA at 44 FR 58802 (October 19.4979)
were withdrawn and should, therefore,
not be included as provisions of this
waiver. EPA does not agree with this
comment. EPA has proposed two
substantial revisions to the original
monitor performance specifications
promulgated at 40 FR 46250 (October 6,
1975): (a) Those proposed at 44 FR 58602
(October 10,1979); and (b) those
proposed at 46 FR 8359 (January 26,
1981). Each is an improvement over the
October 6,1975 promulgation. After a
close examination of both revisions and
the goals of this waiver, EPA has
determined that during the waiver
period a combination of the best
features of both of the proposed
revisions should be used. Therefore,
during the waiver period, the Company
must comply with the drift and
calibration error test requirements
proposed on October 10,1979 and the
location and accuracy test requirements
proposed on January 26,1981. This
requirement will not appreciably affect
the probability that the Company's
CEMS will meet the combined (SOa/Oj)
performance specification requirements.
However, requiring the combination of
the proposed performance specifications
will result in a more specific and
accurate definition of monitor system
performance and data quality.
Furthermore, EPA is considering a
similar combination of performance
specifications for promulgation in the
near future. Therefore, the Agency
believes that this combination is both
reasonable and necessary during the
waiver period.
11. Quality Assurance (QA)
Requirements. The Company
commented that the proposed
requirement to use both 24-hour and
eight 3-hour continuous bubbler runs, as
a QA check on the CEMS, was
unreasonable and unnecessary. EPA has
reassessed this requirement and agrees
that it would impose an unnecessary
burden on the Company. If the Company
demonstrates that a CEM is accurate
over a 24-hour period (as determined by
performing one or more 24-hour bubbler
runs), the monitor accuracy over each of
the eight 3-hour periods that constitute
the 24-hour period should be acceptable
for determining 3-hour emission rates.
Therefore, the proposed QA
requirements for CEMS have been
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revised to require the Company to
perform one 24-hour check each week
during the waiver period. EPA believes
that this streamlining of the QA checks
will be less burdensome, and will
enhance the overall quality of the data.
The Company also requested that the
frequency and number of several other
QA checks be decreased. EPA denies
this request because all checks are
required to insure collection of data
having sufficient quality for both EPA
and the Company to continually assess
the compliance status with waiver's
emission limitations as well as to
evaluate the performance of the control
system. Ensuring the accuracy of the
emission data through a comprehensive
quality assurance program, is equally
beneficial and important to all parties
affected by this waiver.
Finally. DER commented that although
the QA criteria in the proposed waiver
required the CEMS to meet certain 24-
hour drift criteria, the result of these
criteria was unclear. DER was
concerned that the allowed duration (24-
hours) for operating the CEMS outside
the criteria, before a CEMS is to be
taken out of service, could permit a
CEMS to be out of control by any
magnitude, on alternate days. EPA did
not intend to allow any excursions of
the QA performance criteria and agrees
that the column headings in Table 1 of
the proposed waiver were misleading.
The intent of the rim'. durations
designated in the proposal was to
establish the time Intervals for which
the performance criteria are applicable.
The designation of the durations (or
averaging times) associated with the
CEMS drift criteria has, therefore, been
clarified through changes in the text and
in Table 1 of the waiver.
In addition. EPA has re-examined the
required numerical drift specifications
and has determined that the proposed
limits for 24-hour zero and calibration
drift were overly stringent. Therefore
these drift specifications have been
revised (by doubling the allowances, for
up to 3 days) to prevent occasional
monitor drift variability from
. unnecessarily requiring the Company to
take the CEMS out of service.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Title 40. Part 60, Subpart D of the
Code of Federal Regulations is amended
by adding new § 60.47 as set forth
below:
Subpart D—Standards of Performance
for Fossil-Fuel Fired Steam Generator*
§ 60.47 Innovative technology waivers;
waiver of sulfur dioxide standards of
performance for new stationary sources
for Homer City Unit No. 3 under section
111(J) of the Clean Air Act for Multi-Steam
Coal Cleaning System.
(a) Pursuant to section lll(j) of the
Clean Air Act, 42 U.S.C. 7411(j),
commencing on November 13,1981
Pennsylvania Electric Company and
New York State Electric & Gas
Corporation shall comply with the
following terms and conditions for
electric generating Units Nos. 1,2, and 3
at the Homer City Steam Electric
Generating Station, Center Township,
Indiana County, Pennsylvania.
(b) The foregoing terms and
conditions shall remain effective
through November 30.1981, and
pursuant to section lll(j)(B), shall be
Federally promulgated standards of
performance. As such, it shall be
unlawful for Pennsylvania Electric
Company and New York State Electric &
Gas Corporation to operate Units Nos. 1.
2. and 3 in violation of the standards of
performance established in this waiver.
Violations of the terms and conditions
of this waiver shall subject
Pennsylvania Electric Company and
New York State Electric & Gas
Corporation to Federal enforcement
under sections 113 (b) and (c), 42 U.S.C.
7413 (b) and (c). and 120.42 U.S.C. 7420,
of the Act as well as possible citizen
enforcement under section 304 of the
Act 42 U.S.C. 7604. Pursuant to section
lll(c)(l) of the Act. 42 U.S.C. 7411{c)(l).
at 45 FR 3109, January 16.1980, the
Administrator delegated to the
Commonwealth of Pennsylvania
authority to implement and enforce the
Federal Standards of Performance for
New Stationary Sources of 1.2 Ib SO,/
108 Bru applicable to Homer City Unit
No. 3. The SO, emission limitations
specified in this waiver for Unit No. 3
are new Federally promulgated
Standards of Performance for New
Stationary Sources for a limited time
period. Thus, during the period this
waiver is effective, the delegated
authority of the Commonwealth of
Pennsylvania to enforce the Federal
Standards of Performance for New
Stationary Sources of 1.2 Ib SO./108 Btu
applicable to Homer City Unit No. 3 is
superseded and enforcement of the
terms and conditions of this waiver shall
be the responsibility of the
Administrator of EPA. The
Commonwealth of Pennsylvania may.
and is encouraged to. seek delegation of
authority, pursuant to section lll(c)(l),
to enforce the temporary Federal
Standards of Performance for New
Stationary Sources specified in this
waiver. Should such authority be
delegated to the State, the terms and
conditions of this waiver shall be
enforceable by the Administrator of
EPA and the Commonwealth of
Pennsylvania, concurrently. Nothing in
this waiver shall affect the rights of the
Commonwealth of Pennsylvania under
the Decree filed in the Pennsylvania
Commonwealth Court on January 28,
1981, at Docket No. 161 C.D. 1981.
(c) On December 1.1981, and
continuing thereafter, at no time shall
emissions of SO, from Unit No. 3 exceed
1.2 lb/10* Btu of heat input, as specified
in 40 CFR 60.43(a)(2) (July 1.1979).
(d) On January 15,1982, Pennsylvania
Electric Company and New York State
Electric & Gas Corporation shall
demonstrate compliance at Homer City
Unit No. 3 with 40 CFR 60.43(a)(2) (July
1,1979) in accordance with the test
methods and procedures set forth in 40
CFR 60.8 (b). (c), (d). (e) and (f) (July 1,
1979).
(e) Emission limitations. (1)
Commencing on November 13,1981 and
continuing until November 30,1981:
(i) At no time shall emissions of SO,
from Units Nos. 1, 2, and 3, combined,1
exceed: 2.87 Ib SO./106 Btu of heat input
in a rolling 30-day period (starting with
the 60th day after the effective date of
the waiver): 3.6 Ib SO,/10eBtu of heat
input in any day;1 and 3.1 Ib SO,/106Btu
of heat input on more than 4 days in any
rolling 30-day period.
(ii) At no time shall emissions of SO,
from Units Nos. 1. 2, and 3, combined.1
exceed 695 tons in any day.
(iii) At no time shall emissions of SO,
from Units Nos. 1, 2, and 3, combined,2
exceed 91 tons in any discrete ' 3-hour
period.
(iv) At no time shall emissions of SO.
from Units Nos. 1 and 2, combined,
exceed 463 tons in any day.
(v) At no time shall emissions of SO,
from Units Nos. 1 and 2, combined,
exceed 61 tons in any discrete ' 3-hour
period.
(f) Installation Schedule. (1)
Pennsylvania Electric and New York
State Electric & Gas have selected
engineering designs for necessary
modifications to the Multi-Stream Coal
Cleaning System (MCCS) 93B Circuit.
(2) Pennsylvania Electric and New
York State Electric & Gas have placed
1A "day" (a 24-hour period) and a "discrete 3-
hour period" l> defined in section (g](7)(iv).
'The procedures used for calculating combined
SO, emission* are given In paragraph (g)(5) of this
section.
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Federal Register / Vol. 46. No. 219 / Friday, November 13. 1981 / Rules aid Regulations
purchase orders for all major equipment
necessary to complete necessary
modifications to the MCCS 93B circuit.
(3) Pennsylvania Electric and New
York State Electric & Gas have
completed design engineering of the
modifications tcnthe MCCS 93B circuit.
(4) On or before September 15,1981,
Pennsylvania Electric and New York
State Electric & Gas shall complete
construction of the MCCS 93B circuit.
(5) On or before October 15.1981.
Pennsylvania Electric and New York
State Electric & Gas shall start-up the
MCCS 93B circuit.
(g) Monitoring and Reporting.
Throughout the waiver period the
Company shall acquire sufficient
quantities of emission monitoring and
fuel analysis data to continuously
demonstrate compliance with the
combined emission limitations. The
Company shall acquire heat input and
emission data (sufficient to demonstrate
compliance) from each boiler during all
operating periods (i.e., whenever fuel is
being fired), including periods of process
start-up, shutdown, and malfunction.
This requirement shall be met through
the use of continuous emission
monitoring systems (CEMS) [or as
supplemented by continuous bubbler
(CB) systems], heating value as
determined by as-fired fuel analysis,
and coal mass feed-rate measurements.
(1) Continuous Emission Monitoring
System (CEMS): Primary Compliance
Monitoring Method:
(i) The Company shall install, test,
operate, and maintain all CEMS as the
primary compliance monitoring method
in such a manner as to result in the
acquisition of validated data which are
representative of each boiler's 3-hour,
24-hour, and 30-day emission rates. (See
paragraph (g)(7) of this section.)
(ii) The validity of the emission data
obtained with CEMS shall be
determined initially by conducting a
performance specification test (PST).
Subsequent CEMS data validations shall
be performed in accordance with
paragraphs (g)(6) and (g)(7) of this
section. All PSTs of CEMS shall include
at least: (A) All of the specifications and
test procedures contained in the January
26,1981 proposed Performance
Specifications 2 and 3 (Ref. 1). 46 FR
8352; and (B) the calibration error and
response time specifications and test
procedures contained in the October 10.
1979 proposed Performance
Specifications 2 and 3 (Ref. 2), 44 FR
58602. The calibration error, response
time, and all drift tests shall be
conducted using calibration gases which
conform to the requirements of
paragraph (g)(6)(iii) of this section.
(2) Continuous Bubbler System (CB):
Secondary Compliance Test Method:
(i) The Company shall use the CB
system as a secondary compliance
monitoring method to supplement CEMS
data whenever a CEMS is out of service
or is otherwise providing data of
insufficient quality or quantity. The CB
technique shall also be used to
periodically assess the validity of CEMS
data (See paragraph (g)(6)(i)(C) of this
section).
(ii) The CB technique for
quantitatively assessing SOt emissions
(in lb/10* Btu) is delineated in Appendix
I of this waiver. This technique is based
upon combining the basic wet-chemical
technique of EPA's Reference Method 8
at 40 CFR Part 60, Appendix 1. July 1.
1979, (for determining SO,
concentrations) with the gravimetric
method (absorption of COi onto
ascarite) for determining COj
concentrations. Using reduced flow
rates and increased reagent volumes
and concentrations, the CB system may
be run for much longer periods of time
than Reference Method 6 at 40 CFR Part
60, Appendix I (July 1,1979). The
Company may make the following
modifications to the CB method as long
as they periodically demonstrate that
their modified CB method meets the
performance criteria of paragraph
(g)(6)(ii) of this section:
(A) Use a heated sample probe
(B) Use an in-stack filter (up stream of
the implngers) to remove particulate
matter
(C) Eliminate the isopropanol (initial)
impingers
(D) Use a diaphragm pump with flow
regulators in place of the peristaltic
pump
(iii) The Company shall initially
demonstrate its proficiency in acquiring
SO./CO, data with the CB method by
comparing the results obtained using the
CB method with those obtained using
Reference Methods 3 and 6 (See Ref. 3
and paragraph (g)(6)(ii)(B) of this
section). The CB data shall be deemed
initially acceptable if the results of this
test are within the limits prescribed in
paragraph (gX8)(ii) (A) and (B) of this
section. Subsequently, the CB data shall
be periodically revalidated as per the
QA requirements of paragraph (g)(6)(ii)
(A) and (B) of this section.
(3) Requirements for Obtaining 3-hour
and 24-hour Emission Data from
Individual Boilers: Using the methods
set forth in this waiver, the Company
shall obtain the following quantities of
3-hour and 24-hour emission data.
Failure to acquire the specified quantity
or quality of data shall constitute a
violation of the terms and conditions of
this waiver.
(i) Data and calculation requirements
for continuous emission monitoring
system (CEMS). During normal
operation of a CEMS (primary
compliance method) to obtain emission
data from one or more of Units Nos. 1,2.
and 3, the Company shall obtain the
following data from each CEMS: ~~
(A) 3-hour discrete averaging times
using CEMS.—For each boiler,
continuously measure and calculate
eight discrete 3-hour averages each day.
using the three consecutive (exclusive of
exemptions below) 1-hour emission
averages (each consisting of four equally
spaced data points per 1-hour period).
The only periods when CEMS
measurements are exempted are periods
of routine maintenance (as specified in
the Lear Siegler Operator's Manual) and
as required for daily zero/span checks
and calibrations. Such exemptions
notwithstanding, at no time shall less
than six discrete 3-hour averages per
day be obtained. Note that in
calculations each 3-hour average one
only uses the data available from that
specific discrete average.
(B) 24-hour averaging times using
CEMS. For each boiler, continuously
measure and calculate one discrete 24-
hour average per day, using the
available (18-24) 1-hour emission
averages obtained during that specific
day. The only periods when CEMS
measurements are exempted are periods
of routine maintenance (as specified in
the Lear Siegler Operator's Manual) and
as required for daily zero/span checks
and calibrations. Such exemptions
notwithstanding, and except for the
instances when a boiler operated for
only part of the day. at no time shall a
calculated 24-hour average consist of
less than a total of eighteen 1-hour
averages.
(ii) Data requirements when switching
from CEMS to CB system. If it becomes
necessary to take a CEMS out of service
(because of CEMS inoperability or
failure to meet the performance
requirements (paragraph (g)(6)(i) of the
section), the Company shall immediately
initiate the activities necessary to begin
sampling with the secondary (CB)
compliance test method. However, EPA
recognizes that some reasonable amount
of time will be necessary to diagnose a
CEMS problem, to determine whether
minor maintenance will be sufficient to
resolve the problem, or to determine if
the monitoring system must be taken out
of service. Additionally. CEMS
downtime could occur during the night
time shifts or other times when
immediate corrective action cannot
reasonably be made. Therefore, the
waiver requires that at no time shall
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 / Rules and Regulations
•more than six hours elapse between
acceptable operation of the CEMS and
the start of CB sampling. All data which
are obtained during any interrupted
averaging period(s) shall be used to
calculate the reported average(s), and
the Company shall clearly indicate this
data "shortfall" (e.g.. acquisition of only
2 hours of data for a 3-hour averaging
period) in the subsequent report (See
paragraph (g)(8) of this section).
(A) 3-hour averaging times during
CEMS-to-CB transition.—During any
day in which a transition (from the
GEMS) to the secondary compliance
method is made, at least four (4) 3-hour
average rates of the affected boiler's
emissions shall be obtained.
Note.—Al least six (6) 3-hour emission
averages are required when a planned CB-to-
CEMS transition is performed.
(B) 24-hour averaging times that
include a CEMS-to-CB transition. During
any day in which a transition (from the
CEMS) to the secondary compliance
method is made, a 24-hour average rate
of the affected boiler's emissions shall
be obtained, using the combination of all
available 1-hour CEMS emission
averages and 3-hour CB emission
averages. Such a calculation shall
weight (e.g., one CB average is
equivalent to three 1-hour CEMS
average values) the CB data
appropriately.
(iii) Data and calculation requirements
for continuous bubbler (CB) monitoring
systems. During all periods when a
CEMS is out of service and a CB system
is in use at one or more of Units Nos. 1,
2. or 3, the Company shall obtain the
following data from each CB:
(A) 3-hour averaging times using CB
systems. For each boiler being
monitored by a CB system, measure and
calculate at least six discrete 3-hour
emission rates each day.
(B) 24-hour averaging times using CB
systems. For each boiler being
monitored by the CB method, calculate
one 24-hour average emission rate each
day. Each average shall be based upon a
continuous 24-hour sample.
(4) Requirements for Measuring and
Calculating Heat Input Rates:
(i) The Company shall determine the
coal feed rate, for each boiler that is
being fired, for each 24-hour period in
accordance with the Company's
standard procedures for weighing coal
being fed to the boilers.
(ii) The Company shall determine the
heat content (gross calorific value) of
the coal, for each boiler being fired and
for each 24-hour period, in accordance
with the Company's established
procedures for as-fired, 24-hour fuel
sampling (15-minute sample intervals)
and composite automated analysis.
(iii) The Company shall calculate the
average heat input rate for each boiler
for each 24-hour period (10e Btu/24-
hours). For each boiler, multiply the
average heat content of the coal (Btu/lb)
by the coal feed rate as determined for
the same 24-hour averaging period.
(iv) The Company shall estimate the
average 3-hour heat input rate (10* Btu/
3-hours) for each boiler from the
previously determined 24-hour values.
To estimate a 3-hour heat input rate
multiply the corresponding 24-hour
value (lO'Btu/24-hours) by the ratio of
the respective 3-hour to the 24-hour
megawatt outputs.
(5) Requirements for Calculating
Combined SO, Emissions:
(i) 3-hour averaging period: The
combined emission rates from the
operating boilers are equal to the sum of
the products of the individual heat input
rates (10* Btu/3-hours) and the SO,
emission rates (lb/10* Btu as determined
for the 3-hour period). This quantity,
when divided by 2000 Ib/ton, equals the
combined tons of 3-hour SO, emissions
(see Equation 1).
M| "S 2000° Equation 1 •
i=l
Where:
M,=combined (e.g.. Units Nos. 1 and 2 or
Units Nos. 1,2, and 3) emission rates for
the operating units in tons SO,, for the jth
averaging period (3-hour or 24-hour).
EU=average emission rates from the "ith"
unit in Ib SO* for the jth average period
where ) = 3-hour or 24-hour.
HU=average heat input rates for the "ith"
unit in 10* Btu per "jth" averaging period
where )=3-hour or 24-hour.
n=number of operating units.
Note.—Equation 1 is to be used for
calculating: (1) combined tons of SO,
emissions from Units Nos. 1 and 2 and (2)
combined tons of SO, emissions from Units
Nos. 1,2, and 3. Equation 1 is applicable to
both 3-hour and 24-hour averaging periods.
Furthermore, if a unit is not combusting fuel,
"Hu" will be zero.
(ii) 24-hour averaging period:
(A) The combined emissions from the
operating boilers is equal to the sum of
the products of the individual heat
inputs (10* Btu/24-hour) and the SO,
emissions (lb/10* Btu as determined for
the 24-hour period). This quantity, when
divided by 2000 Ib/ton. equals the
combined tons of 24-hour SO, emissions
(see Equation 1).
(B) The combined emissions from the
operating boilers, in the units lb/10* Btu.
is equal to the sum of the products of the
individual heat inputs (10* Btu/24-hour)
and the SO, emissions fib/10* Btu as
. determined for the 24-hour period)
divided by the sum of the combined heat
inputs (see Equation 2).
Equation 2
H
Where:
E=combined emission rates for the operating
units in Ib SO,/10*Btu. for the 24-hour
averaging period.
E,=24-hour average emission rates from the
"ith"unitlnlbSO./10
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•
Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 / Rules and Regulations
each boiler's CEMS data. Where including those for relative accuracy, of
designated, the response time and the January 26.1981 proposed
calibration error test procedures Performance Specifications 2 and 3 (Ref.
contained in Reference 2 and the l) shall be used.
remaining performance test procedures.
(A) Daily zero and calibration checks of the CEMS. Conduct the following zero
and calibration drift checks of each CEMS at approximately 24-hour intervals, and
use the equations provided here to determine if the CEMS meets the designated
drift specifications. All monitors that have exhibited drift during the previous 24-
hour period mus\ be adjusted immediately after the drift checks have been per-
formed and the results have been recorded.
(1) 24-hour zero drift of the SO. monitor (this test is to be performed using low
range (2-5%) span gas):
Specification limits: 8.0% of span in any 24-hour period: 2.0% of span for any three
consecutive 24-hour periods.
24-hour SO, zero drift = !CEM:!lz5L| X100 Equations
: CEMS; ]
where:
CEMS.=monitor zero value (ppm)
C,=zero gas value (ppm)
CEMS.=monitor span value (ppm)
(2) 24-hour zero drift of the O» monitor:
Specification limits: 2.0% Cs in any 24-hour period: 0.5% O, for any three consecutive 24-
hour periods.
24-hour O, zero drift = | CEMS,-G.|xlOO Equation 4
where:
CEMS,=monitor zero value (%O>)
G,=zero gas value (%O>)
(3) 24-hour calibration drift of the SO> monitor (this test is to be performed
using 65-95% span gas):
Specification limits: 10.0% of span in any one 24-hour period: 2.5% of span for any three
consecutive 24-hour periods.
24-hour SO, calibration drift =
CEMSj-GJxlOO Equations
I
where:
CEMS,= monitor reading (ppm)
G, = calibration gas value (ppm)
CEMS,= monitor span value (ppm)
(4) 24-hour calibration drift of the O» monitor
Specification limits: 2.0% O, in any one 24-hour period; 0.5% Ot for any three consecutive
24-hour periods.
24-hour O, calibration drift = | CEMSr-G, | xlOO Equation 6
where:
CEMS, = monitor reading (%O,)
G,=calbration gas value (%O>)
(B) Daily mid-range checks of the CEMS. — Conduct the following mid-range
calibration checks of each CEMS after performing the zero and calibration drift
checks. The purpose for requiring mid-range calibration checks is to verify CEMS
linearity between the zero and calibration values. The mid-range calibration
checks shall be conducted at approximately 24-hour intervals (or more frequently),
and the equations provided shall be used to determine if the CEMS meets the
designated specification limits:
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 / Rules and Regulations
24-hour mid-range drift check of the SO, and the O, monitor* (this test ie to be performed
using 45-55% span gas): Specification limits (same for SO, and O, monitors): 10% of
mid-range gas in any one 24-hour period and 5.0% of mid-range gas in any three
consecutive 24-hour periods.
SO, and O, mid-range drift- I GEMS, _, I x ^ Qn ,
I o, i
where:
CEMS,=monitor reading (ppm SO, or %O,)
G,=mid-range gas value (ppm SO, or %O,)
(C) Initial and weekly checks of the GEMS.—Initially and once each week,
conduct at least one 24-hour modified relative accuracy test of each CEMS (com-
bined SOi and O> channels in units of SO. lb/106 Btu) using the CB method. If the
difference between the CEMS and CB exceeds the designated specification limit,
the 24-hour test must be repeated, within the next 24-hour period. If the CEMS
again fails to meet the specification limit, remove the monitor from service.
Specification limit: ±20% (maximum percent difference between CEMS and CB)
24-hour percent difference (CEM vs. CB) CEMS I _i x 100 Equation 8
I CB I
where:
CEMS = SO,/Oi monitor system reading (SO, lb/108 Btu)
CB=CB measurement results (SO. lb/10" Btu)
(D) Initial and quarterly performance specification tests of CEMS. Initially and
once each three months, conduct at least one 3-hour relative accuracy test (com-
bined SO] and Oi channels as per Reference 1), and a response time and calibra-
tion error test, (as per Reference 2). The calculation procedures provided in Refer-
ences 1 and 2 shall also be used.
Specification limits: • Relative Accuracy = ±20% (maximum percent difference between
the CEMS and the RM data in units of Ib SO>/10a Btu)
• Response Times 15 minutes
• Calibration Error=5.0% (SO, and O, channels separately)
(E) Unscheduled performance specification tests of the CEMS.—If for any
reason (other than routine maintenance as specified in the Lear Siegler operating
manual) the CEMS is taken out of service or its performance is not within the
specification limits of paragraph (g)(6) of this section, the Company shall conduct a
complete Performance Specification Test (PST) of the CEMS, according to the
combined requirements of References 1 and 2, as per paragraph (g)(6)(i)(D) of this
section. Whenever a CEMS is taken out of service and a supplementary CB system
is being used, the CEMS shall not replace the CB system until such time that the
Company has demonstrated that the performance of the CEMS is within all of the
performance limits established by paragraphs (g)(6)(i)(A), (B), (C), and (D) of this
section.
(ii) QA requirements, calculation procedures, and specification limits for CB
systems: At a minimum, the Company shall conduct the following initial, weekly.
and quarterly QA evaluations of all CB systems that are being used: (1) For any
quality assurance evaluations of a CEMS; and (2] as the secondary compliance
method when a CEMS is out of service. If a CB system does not meet these
specifications, then: (1) The CB must immediately be taken out of service; (2) the
Company must notify the Director, Division of Stationary Source Enforcement
(Washington, D.C.) within 72 hours after this determination is made; and (3) the
Company will be considered in violation of the provisions of the waiver until an
acceptable monitoring method is initiated (see paragraph (g)(8)(iii) of this section).
(A) Initial and weekly mid-range calibration checks of the CB system.—Cali-
bration checks of the CB system, using mixed SCs/COi mid-range calibration gas,
shall be performed initially and at least once each week thereafter. The calibration
gas shall be sampled by the CB system for no less than 2 hours at a flow rate
approximately the same as used during emission sampling. The following equation
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 / Rules and Regulations
shall be used to determine if the CB meets the designated mid-range calibration
specification limit.
Specification limit: 10-0% (maximum percent difference between CB value and mid-range
gas value).
Percent difference (CB vs. calibration gas) =
XlOO
Equation 9
where:
CB = bubbler value (SO, lb/10«Btu)
Gv=mixed SO,/CO, mid-range calibration gas value (SOi lb/10'Blu)
(B) Initial and quarterly relative accuracy tests of the CB systems. Operate at
least one of the CB systems used during the quarter for a 3-hour period. During the
same three hour period, collect at least one paired set of Reference Method 3 and 6
samples: Each paired set shall consist of at least three to six 20-60 minute
consecutive ("back-to-back") runs. The following equation shall be used to deter-
mine if the CB meets the designated relative accuracy specifications limit.
CB Specification limit: 10.0% (maximum percent difference between CB value and and
RM value).
Percent difference (CB vs. RM)
CB
RM
-1
XlOO
Equation 10
I
where:
CB=bubbler value (SO, lb/10'Btu)
RM = average value of the paired Reference Method 3 and 6 runs (SO, lb/10" Btu)
(iii) QA requirements and specification limit for calibration gases: All calibra-
tion gases used for daily, weekly, or quarterly calibration drift checks. CB calibra-
tion checks and performance specification tests shall be analyzed following EPA
Traceability Protocol No. 1 (see reference 4) or with Method 3 or 6. If Method 3 or
6 is used, do the following. Within two weeks prior to its use on a CEMS. perform
triplicate analyses of the cylinder gas with the applicable reference method until
the results of three consecutive individual runs agree within 10 percent of the
average. Then use this average for the cylinder gas concentration.
(iv) Quality assuance checks for laboratory analysis: Each day that the Compa-
ny conducts Reference Method 6 or CB laboratory analyses, at least two SO, audit
samples shall be analyzed concurrently, by the same personnel, and in the same
manner as the Company uses when analyzing its daily emission samples. Audit
samples must be obtained from EPA. The following equation shall be used to
calculate the designated specification limit to determine if the Company's labora-
tory analysis procedures are adequate.
Analysis specification limit (for each of two audit samples): 5% (maximum percent
difference between laboratory value and the average of the actual value of the audit
samples).
Percent difference (laboratory vs. actual) =
si.y
SAV
-1
I
xioo
Equation 11
where:
SLV = laboratory value (mg/DSCM) of the audit sample
SAV = ocJuo/ vulue (mg/DSCM) of the audit sample
(v) QA requirements, calculation procedures, and specification limits for 24-
hour fuel sampling and analysis: At a minimum, the Company shall conduct the
following bi-weekly QA evaluations of each boiler's fuel sampling and analysis
data.
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 7 Rules and Regulations
(A) Initially and at least bi-weekly the Company (or its own contractor labora-
tory) shall prepare and split a 60 mesh (250 micron) sample of coal (24-hour
composite) with an independent laboratory. The Company shall compare the inde-
pendent laboratory's heat content values to those of the Company's respective
analyses. Use the following equation to determine if the Company's coal analysis
procedures are adequate.
Specification limit: 500 Btu/lb (maximum difference between the two laboratories' results)
Inter-laboratory difference = CFA —IFA Equation 12
where:
CFA=Company's fuel analysis (Btu/lb)
IFA = Independent laboratory anlysis (Btu/lb)
(B) Analysis of reference coal.—At a minimum, the Company shall initially
(and thereafter bi-weekly), but on alternating weeks from above (g)(6)(v](A) of this
section analysis, analyze the heat content of at least one reference coal sample.
Reference coal samples must be obtained from EPA. Use the following equation to
determine if the Company's fuel analysis procedures are adequate.
Specification limit: 500 Btu/lb (maximum difference betwee'n the Company laboratory's
value and the heat content of the reference coal).
Difference between Company's laboratory and reference= FAV —FLV Equation 13
where:
FLV laboratory value (Btu/lb)
FAV=reference value (Btu/lb)
(vi) The use of more than the
minimum quantities of data to calculate
the QA specifications: Whenever the
Company supplements, expands, or
otherwise obtains more than the
minimum amount of QA data required
by paragraph (g}(6) of this section for the
QA evaluations, the Company shall use
all available data in assessing
achievement of the QA specifications.
All of the equations delineated above
may be expanded algebraically to
accommodate increased data, sample
runs, or test repetitions.
(7) Compliance Provisions:
(i) Compliance with all of the
provisions of this waiver requires:
(A) Documentation that the combined
emission levels (of Units Nos. 1, 2, and 3
or 1 and 2, as appropriate) did not
exceed the emission limitations
specified in paragraph (e) of this section.
(B) Documentation that the Company
acquired at least the minimum quantity
and quality of valid emission data
specified in paragraph (g)(3) of this
section.
(C) Documentation that the Company
performed at least the minimum quality
assurance checks specified in paragraph
(g)(6) of this waiver, and
(D) Timely and adequate reporting of
all data specified in paragraph (g)(8) of
this section.
Failure to meet any of these
requirements constitutes a violation of
this waiver.
(ii) SOj emissions rate data from
individual boilers shall be obtained by
the primary compliance test method
(CEMS), by the secondary compliance
test method (CB), or other methods
approved by the Administrator. Data for
the heat input determination shall be
obtained by 24-hour as-fired fuel
analysis and 24-hour coal feed rate
measurements, or other methods
approved by the Administrator.
Compliance with all SOi emission
limitations shall be determined in
accordance with the calculation
procedures set forth in paragraph (g)(5)
of this section or other procedures
approved by the Administrator. The
Company must demonstrate compliance
with all 3-hour, 24-hour, and 30-day SOi
emission limitations during all periods
of fuel combustion in one or more
boilers (beginning with the effective
date of the waiver), and including all
periods of process startup, shutdown,
and malfunction.
(iii) If the minimum quantity or quality
of emission data (required by paragraph
(g) of this section) were not obtained,
compliance of the affected facility with
the emission requirements specified in
this waiver may be determined by the
Administrator using all available data
which is deemed relevant.
(iv) For the purpose of demonstrating
compliance with the emission
limitations and data requirements of this
waiver
(A) "A day" (24-hour period) begins at
12:01 p.m. and ends at 12:00 noon the
following day. The Company may select
an alternate designation for the
beginning and end of the 24-hour day.
However, the Agency must be notified
of any alternate designation of a "day"
and must be maintained throughout the
waiver period. Also, for the purpose of
reporting, each day shall be designated
by the calendar date corresponding with
the beginning of the 24-hour period;
(B) Where concurrent 24-hour data
averages are required (i.e., coal feed
rate, fuel sampling/analysis, SOj tons/
24 hours, and SO, lb/108 Bra), the
designated 24-hour period comprising a
day shall be consistent for all such
averages and measurement data; and
(C) There are eight discrete 3-hour
averaging periods during each day.
(8) Notification and Reporting
Requirements.
(i) Notification: The Company shall
provide at least 30 days notice to the
Director, Division of Stationary Source
Enforcement (Washington, D.C.) of any
forthcoming quarterly CEMS
Performance Specification Tests and CB
accuracy tests.
(ii) Quarterly Compliance and
Monitoring Assessment Report
requirements: The Company shall
submit to the Director, Division of
Stationary Source Enforcement
(Washington, D.C.) "hard copy"
quarterly reports that present
compliance data and relevant
monitoring and process data (e.g.,
process output rate, heat input rate,
monitoring performance, and quality
assurance) acquired during the reporting
period. Quarterly reports shall be
postmarked no later than 30 days after
the completion of every (whole or
partial) calendar quarter during which
the waiver is in effect.
Note.—These requirements do not replace
or preclude the "Unscheduled Reporting
Requirements" contained in paragraph
(g)(8)(iii) of this section.
The following specific information shall
be furnished for every calendar day:
(A) General Information:
(1) Calendar date;
(2) The method(s), including
description, used to determine the 24-
hour heat input to each boiler (in units
of Btu/hour);
(3) The "F" factor(s) used for all
aoplicable calculations, the method of
V-505
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1981 / Rules and Regulations
its determination, and the type of fuel
burned;
(B) Emission Data:
{/) Combined [Units Nos. 1. 2, and 3)
24-hour average SO, emission rate (in
units of Ib/MMBtu);
(2) Combined (Units Nos. 1,2 and 3)
rolling 30-day average SOt emission rate
(in units of Ib/M&fBtu);
(3) Combined (Units Nos. 1,2, and 3)
3-hour average emission rates (in units
of tons SO,);
(4) Combined (Units Nos. 1. 2. and 3)
24-hour average emission rates (in units
of tons SO,);
(5) Combined (Units Nos. 1 and 2) 3-
hour average emission rates (in units of
tons SO,); and
(6) Combined (Units Nos. 1 and 2) 24-
hour average emission rates (in units of
tons SO,).
(C) Quality Assurance Check Data;
(7) The date and summary of results
from all (initial and repetitions) of the
quality assurance checks performed
during the quarter. This includes all
analytical results on EPA's SO, and COH!
audit samples.
[2] Description(s) of any
modification(s) made to the CEMS or CB
which could affect the ability of those
systems to comply with the performance
specifications in References 1 and 2. or
the CB performance specifications
established by Section (g) of this waiver.
(D) Atypical Operations:
(1) Identification of specific periods
during the calendar quarter when each
boiler was not combusting fuel;
(2) Periods of time when 3-hour, 24-
hour, and/or 30-day averages were
obtained using continuous bubbler data:
(3) All emission averages which have
been calculated using a composite of
two or more different sampling methods
(i.e., periods when both CEMS and CB
systems have been used) must be
identified by designating all duration(s)
and cause(s) of data loss during such
periods;
(4) For each instance when a CEMS
has been out of service, the Company
shall designate:
(/) Time, date, duration;
(/'/) Reason for such downtime;
(Hi) Corrective action taken;
(/v) Duration before CB sampling
began:
(v) Time, date, and performance
specification test (summary) results
acquired before CEMS returned to
service; and
(w) Time and date when CEMS
actually returned to service, relative to
terminating CB sampling.
(5) Where only a portion of
continuous data from any averaging
period(s) was obtained, the duration per
averaging period(s) when data were
acquired and were used to calculate the
emission average(s) must be identified;
(6) If the required quantity or quality
of emission data (as per paragraph (g) of
this section) were not obtained for any
averaging period(s). the following
information must also be reported for
each affected boiler. (See also
Unscheduled Reporting Requirements,
paragraph (g)(7)(iv) of this section:
(/) Reason for failure to acquire
sufficient data:
{//) Corrective action taken;
(iv) Characteristics (percent sulfur.
ash content, heating value, and
moisture) of the fuel burned;
(v) Fuel feed rates and steam
production rates;
(vi) All emission and quality
assurance data available from this
quarter, and
(vif) Statement (signed by a
responsible Company official) indicating
if any changes were made in the
operation of the boiler or any
measurement change (±20 percent)
from the previous averaging period) in
the type of fuel or firing rate during such
period.
(E) Company Certifications: The
Company shall submit a statement
(signed by a responsible Company
official) indicating:
(7) Whether or not the QA
requirements of this waiver for the
CEMs, CB, and fuel sampling/analysis
methods, or other periodic audits, have
been performed in accordance with the
provisions of this waiver;
(2) Whether or not the data used to
determine compliance was obtained in
accordance with the method and
procedures required by this waiver,
including the results of the quality
assurance checks;
(3) Whether or not the data
requirements have been met or, if the
minimum data requirements have not
been met due to errors that were
unavoidable (attach explanation);
(4) Whether or not compliance with
all of the emission standards
established by this waiver have been
achieved during the reporting period.
(iii) Unscheduled Reporting
Requirements. The Company shall
submit to the Director, Division of
Stationary Source Enforcement
(Washington, D.C.).
(A) Complete results of all CEMS
performance specification tests within
45 days after the initiation of such tests:
(B) The Company shall report, within
72 hours, each instance of:
[1] Failure to maintain the combined
(Units Nos. 1, 2, and 3 and Units Nos. 1
and 2, respectively) SO, emission rates
below the emission limitations
prescribed in Section (e) of this waiver;
(2) Failure to acquire the specified
minimum quantity of valid emission
data; and
(3) Failure of the Company's CB(s) to
meet the quality assurance checks.
References
1. Standards of Performance for New
Stationary Sources: Revisions to General
Provisions and Additions to Appendix A. and
Reproposal of Revisions to Appendix B, 46 FR
8352 (January 26, 1981).
2. Proposed Standards of Performance for
New Stationary Sources; Continuous
Monitoring Performance Specifications 44 FR
58802 (October 10.1979).
3. 40 CFR Part 60. Appendix A (July 1.
1979).
4. Quo/it} Assurance Handbook for Air
Pollution Measurement Systems, Volume 111.
Stationary Source Specific Methods. EPA-
600/4-77-027b. August 1977.
V-506
-------
I
tm*>d) ,
?4-hour calibration drift (SO» and Oi or CO,)
Mtd-range check (SO./CO,) . _
Relative accuracy (SO,/CO, combined)
Specification Krnft
0 5 percent O, . . .
20 0 percent difference
500 Btu/hr difference
500 Btu/hr difference, . .
Duratton
24 hours
24 hour* . ..
24 hour*
24 houra
24 hour*1
9-12 noun)
(N/A)
ffJ/A)
(N/A) . . '
3 hour*
(N/A)
(N/A)
(N/A)
Calculation
procedures
Equation 4
Equation 6
Equation 9 '
See Reference 1
See Reference 2
See Reference 2
See Reference 1
Equation 10
Equation 11
Equation 13
o
O
(B
1 Failure to meet On apecitication raquirea the lest to be repeated one time. I) this test documents a second failure to CEMS must be taken out of service.
to
0.
oj
oo
c
o
CD
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Federal Register / Vol. 46. No. 219 / Friday. November 13. 1T81 / Rules and Regulations
Appendix I—Determination of Sulfur Dioxide
Emission! From Fossil Fuel Fired Combustion
Sources (Continuous Bubbler Method)
(Note.—The Company may use the method
or its modifications which it requested and
which are reflated in Section (g)(2)(ii)(A)
during the waiver period.)
1. Applicability and Principle.
1.1 Applicability. This method applies to
the determination of sulfur dioxide (SO»)
emissions from combustion sources in terms
of emission rate ng/J (Ib/MMBtu).
1.2. Principle. A gas sample is extracted
from the sampling point (in the emission
exhaust duct or stack) over a 24-hour or other
specified time period. The SO, and CO,
contained in the sampled exhaust gases are
separated and collected in the sampling IrHJn.
The SO, fraction is measured by (he barium-
thorium titration method and COi is
determined gravimetrically.
2. Apparatus.
2.1 Sampling. The sampling train is shown
in Figure 1; the equipment required is the
same as for Method 6, except as specified
below:
2.1.1 Impingers. Three 150 ml. Mae West
impingcrs with a 1-mm restricted tip.
2.1.2 Absorption Tubes. Two 51 mm x 178
mm glass tubes with matching one-hole
stoppers.
2.2 Sample Recovery and Analysis. The
equipment needed for sample recovery and
analysis is the same as required for Method
6. In addition, a balance to measure (within
O.OSg) is needed for analysis.
3. Reagents.
Unless otherwise indicated, all reagents
must conform to the specifications
established by the Committee on Analytical
Reagents of the American Chemical Society.
Where such specifications are not available.
use the best available grade.
3.1. Sampling. The reagents required for
campling are the same as specified In Method
6. except that 10 percent hydrogen peroxide
it used. In addition, the following reagent*
are required:
3.1.1 Drierite. Anhydrous calcium tulfate
(CaSOJ dessicant. 6 mesh.
3.1.2 Ascarite. Sodium hydroxide coated
asbestos for absorption of CO,. 8 to 20 mesh.
3.2 Sample Recovery and Analysis. The
reagents needed for sample recovery and
analysis are the same at for Method 6,
Sections 3.2 and 3.3. respectively.
4. Preparation of Collection Train. Measure
75 ml. of 60 percent IPA into the first impinger
and 75 ml. of 10 percent hydrogen peroxide
into each of the remaining impingers. Into one
of the absorption tubes place a one-hole
stopper and glass wool plug in the end and
add 150 to 200 grams of drierite to the tube.
As the drierite is added shake the tube to
evenly pack the absorbent. Cap the tube with
another plug of glass wool and a one-hold
stopper (use this end as the inlet for even
flow). The ascarite tube is filled in • similar
manner, using 150-175 grams of ascarite.
Clean and dry the outside of the ascarite tube
and weigh (at room temperatue. 20 degrees C)
to the nearest 0.1 gram. Record this initial
mass as Mw. Assemble the train as shown in
Figure 1. Adjust the probe heater to a
temperature sufficient to prevent water
condensation.
4.1.1 Sampling. The bubbler shulPbe
operated continuously at a sampling rate
sufficient to collect 70-80 liters of source
effluent during the desired sampling period.
For example, a sampling rate of 0.05 liter/
min. is sufficient for a 24-hour average and
0.40 liter per minute for a 3-hour average. The
sampling rule shall not. however, exceed 1.0
liter/min.
4.2 Sample Recovery.
4.2.1 Peroxide Solution. Pour the contents
of the tecond and third impingers into a leak-
free polyethylene bottle for ttorage or
shipping. Rinse the two impingers and
connecting tubing with deionized distilled
water, and add the washings to the same
ttorage container.
4.2.2 Ascarite Tube. Allow the ascarite
tube to equilibrate with room temperature
(about 10 minutes), clean and dry the outside.
and weigh to the nearest O.lg in the tame
manner as in Section 4.1.1. Record this final
mass (M.i) and discard the used ascarite.
4.3 Sample Analysis. The tample analysis
procedure for SO, is the same as specified in
Method 6. Section 4.3.
5. Calculations.
5.1 SO, mass collected.
M,«=32.03 (V,- V*) N VM,BV. Equation A1-1
Where:
Msn=mass of SO, collected, mg
V, = volume of barium perchlorate titrant
used for the sample, ml (average of
replicate titrations).
V|»= volume of barium perchlorate titrant
used for the blank, ml.
N = normality of barium perchlorate titrant.
milliequivalents/ml.
V«,u, = total volume of solution in which the
sulfur dioxide sample is contained, ml.
V.= volume of sample aliquot titrated, ml. 5.2
Sulfur dioxide emission rate
ESM=FC(K.) MSM Equation Al-2
Where:
Mu=initial mass of ascarite. grams.
Ma= final mass of ascarite, grams.
E^, = Emission rate of SO,, ng/) (Ib/MMBtu).
F,=Carbon F factor for the fuel burned. MVJ.
from Method 19 (Ref. 2)
K'=1.B29X10*
MtUNOCOOC tSSO-2«-M
V-508
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Federal Register / Vol. 4(i. No. 219 / Friday. November 13. 19B1 / Rules and Regulations
FIGURE 1
CONTINOUOUS BUBBLER (S02/O>2) SAMPLING TRAIN
(NOTE: See Section (g)(2)(ii) for acceptable modifications of the
CB train during the waiver period.]
801
2-PROPANOL
(OPTIONAL)
OPTIONAL:
HEATED
PROBE AND
IN-STACK
FILTER
CONSTANT
RATE
PUMP
1FR Doc 81-32510 FiUd 11-12-81; 8:45 im|
MLUNO COM «MO-M-C
V-509
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Federal Register / Vol. 46. No. 226 / Tuesday. November 24. 1981 / Rules and Regulations
133
40 CFR Part 60
[A-7-FRL 1967-2]
Adjustment of Opacity Standard for
Fossil Fuel Fired Steam Generator
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: On August 18,1981, there was
published in the Federal Register (46 FR
41817) a "notice of proposed rulemaking
setting forth a proposed EPA adjustment
of the opacity standard for Omaha
Public District (OPPD). Nebraska City
Power Station, Nebraska City,
Nebraska. The proposal was based on a
demonstration by OPPD 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.
One written comment was received
after the close of the comment period
from OPPD pointing out in the proposal
that the fourth paragraph under
Supplementary Information referred to
sixteen performance tests conducted
from February 25.1981 to April 16, 1981.
as the basis for the EPA determination.
This was incomplete information. The
performance tests were conducted on
January 20, 21, 22, 1981. In addition
OPPD submitted data on sixteen
opacity/mass correlation tests
conducted from February 25,1981. to
April 16.1981. All of this data was the
basis for the EPA determination. There
were three requests for copies of the
background data. All test data on all
tests was provided the requesters.
Since the omission was of additional
testing which in fact enhances thr EPA
determination, and there were no
comments other than from the source
itself, there appears to be nothing of a
substantive nature which would require
the delay of repromulgation. The
proposed adjustment is approved
without change and is set forth below.
EFFECTIVE DATE: November 24,1981.
FOR FURTHER INFORMATION CONTACT:
Anthony P. Wayne, telephone 816-374-
7130, or Henry F. Rompage, telephone
816-374-7152, Enforcement Division.
EPA, Region VII, 324 E. llth Street,
Kansas City, Missouri 64106.
SUPPLEMENTARY INFORMATION: Under
Executive Order 12291, EPA must judge
whether a rule is "major" and therefore
subject to the requirement of a
Regulatory Impact Analysis. This rule is
not "major" because it only approves a
slight variance in opacity as provided
for in 40 CFR 60.11(e) and imposes no
iuklilional substantive requirements
xvhich are not currently applicable under
applicable NSPS requirements. Hence it
is unlikely to have an annual effect on
the economy of Si00 million or more, or
to have other significant adverse
impacts on the national economy.
This rule was submitted to the Office
i-I Management and Budget (OMB) for
review as required by Executive Order
1::291.
Pursuant to the provisions of 5 U.S.C.
ti05(b) I hereby certify that this rule as
promulgated will not have a significant
impact on a substantial number of small
entities. The reason for this finding is
that this action only affects one entity.
Dated: November 19. 1981.
Anne M. Gorsuch,
Ail.tiinistralor.
PART 60— STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
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
1. Section 60.42 is amended by adding
paragraph (b)(3) as follows:
§60.42 [Amended]
» * * * i
(b) ' * *
(3) Omaha Public Power District shall
not cause to be discharged into the
atmosphere from its Nebraska City
Power Station in Nebraska City.
Nebraska, any gases which exhibit
greater than 30% opacity, except that a
maximum of 37°6 opacity shall be
permitted for not more than six minutes
in any hour.
2. Section 60.45(g)(l) is amended by
Adding paragraph (hi) as follows:
§ 60.45 Emission and fuel monitoring.
(8) * ' *
{IP**
(iii) For sources subject to the opacity
standard of Section 60.42(b)(3), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 30 percent opacity,
except that one six-minute average per
hour of up to 37 percent opacity need
not be reported.
(Sec. 111. 301(a), Clean Air Act as amended
(42 USC 7411. 7601))
JIT? One. il-UBi: Filed 11-23-81:143 dm|
V-510
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Federal Register / Vol 4ft No, 240 /Tuesday. December 1& 19S1 / Rules and Regulations
134
40 CFR Part 60
[A-4-FRL 1977-8]
Standards of Performance for New
Stationary Sources; Alternative Test
Requirements for Anaconda Aluminum
Company's Sebree Plant, Henderson,
Kentucky
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: EPA today establishes
alternative performance testing
frequency requirements for Anaconda
Aluminum Company's Sebree plant in
Henderson, Kentucky, as provided in 40
CFR 60.195(b). Rather than conduct
monthly performance tests, this source
will be allowed to test once a year. This
action was proposed in the Federal
Register of August 25,1981 (46 FR
42878); no comments were received.
DATE: This action is effective January 14.
1982.
ADDRESSES: Background information is
available for public inspection during
normal business hours at the Air
Facilities Branch, EPA Region IV, 345
Courtland Street, N.E., Atlanta, Georgia
30365.
FOR FURTHER INFORMATION CONTACT:
Joe Riley, Air Facilities Branch, EPA
Region IV, Atlanta, GA at 404/881-2786
(FTS 257-2786).
On January 26.1976 (41 FR 3828), EPA
promulgated Standards of Performance
for New Primary Aluminum Reduction
Plants as Subpart S of 40 CFR Part 60,
pursuant to the provisions of Section 111
of the Clean Air Act. Under the original
standards, the affected source was
required to conduct a performance test
on startup and on any other occasion
the Agency might require a test under
Section 114 of the Clean Air Act. On
June 30,1980 (45 FR 44202), EPA revised
40 CFR 60.195 to require performance
testing at least once a month for the life
of a new primary aluminum plant. At the
same time, however, the Agency
provided that alternative test
requirements could be established for
the primary control system or an anode
bake plant if the source could
demonstrate that emissions have low
variability during day-to-day operations.
On April 12,1977, EPA delegated to
the Commonwealth of Kentucky
authority to administer Subpart S of 40
CFR Part 60. Under the terms of the
delegation, performance tests were to be
scheduled and performed in accordance
with the procedures set forth in 40 CFR
Part 60 "unless alternate methods or
procedures are approved by the EPA
Administrator." Accordingly, the
Kentucky Department for Natural
Resources and Environmental Protection
transmitted to EPA for its approval •
petition for alternative test requirement*
submitted by Anaconda Aluminum
Company of Henderson. Kentucky.
Anaconda Ahrnirnum reqnested that it
be allowed to (1) use the historic mean
for primary emissions to calculate total
monthly pot-room group emissions
instead of emissions from the most
recent lest, (2) change the frequency of
testing the anode bake plant from once a
month to once a year, and (3) change the
frequency of testing the primary control
system from once a month to once a
year.
On the basis of the supporting
information submitted, EPA is granting
•the latter two requests since they meet
the requirements of 40 CFR 60.195(b).
Actual emissions from the primary
control system are far beiow allowable
emissions: month-to-month variations in
anode bake plant emissions, which are
well below the allowable, are not great
enough to likely result in emissions in
excess of the standards for fluorides.
The Agency does not find, however.
that the first request can be justified
under 40 CFR 60.8(b). and it is herewith
deoied. To use the average of all past
performance tests of the primary system
to calculate emissions would defeat the
purpose of periodic testing, which is to
detect any deterioration in the control
system.
The alternative test requirements
established today will apply only to the
Sebree production plant of Anaconda
Aluminum in Henderson, Kentucky.
They do not preclude the Agency or the
Commonwealth of Kentucky from
requiring performance testing at any
time. Finally, they can be withdrawn at
any time the Administrator finds that
they are not adequate to assure
compliance with the emission standards
applicable to Ihistource.
Under section 307(b)(l) of the Clean
Air Act. judicial review of today's action
by EPA is available only by the filing of
a petition for review in the United States
Court of Appeals for the appropriate
circuit on or before (60 days from date of
publication]. Under section 307(b)(2) of
the Clean Air Act. the requirements
which are the subject of today's notice
may no* be challenged later in civil or
criminal proceedings brought by EPA to
enforce these requirements.
Pursuant to the provisions of 5 U.S.C.
section 605(b) 1 hereby certify that the
attached rule will not have a significant
economic impact on a substantial
number of small entities. The reason for
this finding is that this action only
affects oae facility.
Under Executive Order 12291, EPA
most Fudge whether a regulation it major
and therefore satyect to the requirement
of a Regulatory bnpact Analyst*. This
regulation is not nejor because it merely
relieves one source of part of the harden
of demonstrating compliance.
This regulation was submitted to the
Office of Management and Bttdgst
(OMB) for review as required by
Executive Order 122STL
(Section 111 of the Clean Air Act n
amended (42 U.S.C 7m))
Dated December R 19W.
Anne M. Gonudk.
A dministmtor.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter L Title 40, Code of
Federal Regulation*, is amended as
follows;
In § 60.196 paragraph (bKU is added
as follows:
§60.t96 Test methods and procedure*.
* * * • *
(bj * ' *
(1) Alternative testing requirements
are established for Anaconda Aluminum
Company's Sebree plant m Henderson;
Kentucky: the anode bake plant and
primary control system are to be tested
once a year rather than once a month.
|FR Due. U-397M PtM 1J-I4-*!; &46 an)
V-511
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Federal Register / Vol. 46. No. 245 / Tuesday. December 22, 1981 / Rules and Regulations
135
.40 CFR Part 60
fA-S-FRLMIO-a]
Standards of Performance for New
Stationary Sources; Additional Source
Categories Delegated to Ohio and
Indiana
AOENCY: Environmental Protection
Agency (EPA).
ACTION: Notice of delegation of
authority.
SUMMARY: The States of Ohio and
Indiana have both received delegation
of authority to implement certain new
source performance standards (NSPS)
under section lll(c) of the Clean Air
Act. Both States have requested and
received authority to Implement the
NSPS for additional source categories.
DATES: The effective dates of the
delegations are February 6,1981 for
Indiana and November 5,1979 and
August 27.1980 for Ohio.
FOR FURTHER INFORMATION CONTACT:
Ronald I. Van Mersbergen. U.S. EPA,
230 South Dearborn Street, Chicago,
Illinois 60604, (312) 886-6066.
SUPPLEMENTARY INFORMATION:
A. Indiana
The State of Indiana received
authority on April 21,1976 to implement
the twelve NSPSs published at 40 CFR
Part 60 Subparts D through O (Subparts
Da and Ka were not promulgated at that
time), the April 21,1976 delegation,
issued in accordance with section lll(c)
of the Clean Air Act, was published on
September 30,1976 (41 FR 43237). On
June 6,1977 the delegation was
amended and twelve more source
categories were added so that the
delegation then included Subparts D
through AA (Subparts Da and Ka were
not promulgated at that time). The
revised delegation was published on
September 12,1977 (42 FR 45705).
On January 5,1981 the State requested
authority for eight additional source
categories and authority for any
revisions to the previously delegated
source categories. A revised delegation
of authority was granted on February 6,
1981 and is as follows:
February 6.1981.
Certified Mail Return Requested
Mr. Ralph C. Pickard,
Technical Secretary. Indiana Air Pollution
Control Board. 1330 West Michigan
Street, Indianapolis, Indiana
Dear Mr. Pickard: Thank you for your
January 5,1981 letter requesting an expansion
of your existing delegated authority to
include the regulations for additional New
Source Performance Standards (NSPS)
categories and revision* to NSPS which you
already have been delegated.
We have reviewed your request and have
found your present new source review
programs and procedures to be acceptable.
Therefore, the U.S. Environmental Protection
Agency (USEPA) is delegating to the State of
Indiana authority to Implement and enforce
the NSPS program for additional categories
and for regulation revisions of previously
delegated source categories. The following
represents the NSPS now delegated to
Indiana:
40 CFR Part 60 Subparts D through HH as
amended by 45 FR 66742 October 7,1980 and
45 FR 74646 November 12.1980.
The terms and conditions applicable to this
delegation are in the delegation letters of
April 21.1976 and June 6,1977 except that
condition 4 of both letters which prevents
State enforcement in Federal Facilities is now
eliminated. Section 118(a) of the Clean Air
Act provides States with authority to enforce
permit requirements in Federal Facilities.
A notice of this delegated authority will be
published in the Federal Register.
This delegation Is effective upon the datr
of this letter unless the USEPA receives
written notice from the IAPCB of objections
within 10 days of receipt of this letter.
Sincerely yours.
John McGuire,
Regional Administrator.
B. Ohio
On June 3,1976, the State of Ohio
requested delegation of authority to
implement the NSPSs promulgated as of
that time. EPA on August 4,1976
delegated authority to Ohio to
implement 40 CFR Part 60 Subparts D
through AA (Subparts Da and Ka were
not promulgated at that time). That
delegation was published on December
21,1976 (41 FR 55575). On October 31.
1979 and May 12.1980 Ohio requested
authority for additional source
categories and any revisions of the
previously delegated source categories.
These requests were granted on
November 5,1979 and August 27.1980
respectively. The delegation now
includes source categories in Subpart D
through Subpart BB and Subparts DD.
GG, and HH.
The following letters are amendments
to the August 4,1976 delegation.
November 5.'1979.
Mr. James F. McAvoy.
Director, Ohio Environmental Protection
Agency, P.O. Box 1049. Columbus. Ohio
Dear Mr. McAvoy: Thank you for your
October 3,1979 letter requesting expansion of
your existing Delegation of Authority to
include additional New Source Performance
Standards (NSPS) categories.
We have reviewed your request and have
found your proposed program and procedures
to be acceptable. Therefore, we are
delegating to the State of Ohio authority to
V-512
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KBgioto / Vol. 48. Mo. &9S / Tuesday, December 22. 1881 / Rules and Regulation^
implement and enforce the NSPS pro^an far
the following souroa categories:
1. Kraft Pulp Mills (Subpart BB),
Promulgation Date—February 23,1978;
Clarifying amendments to the otandard a ad
Referance Method 16, Promulgation Da to—
August 7,1970.
2. Lignite-Bred Steam Generators
(Amendments to Subpart D). Promulgation
Date—March 7.1978.
3. Lime Manufacturing Planto (Subpart
HH). Promulgation Date—March 7,1978.
4. New, Modified and Reconstructed Grain
Elevators (Subpart DD), Promulgation Date—
August 3.1978.
5. Electric Utility Steam Generating Units
(Subpart Da), Promulgation Date—June 11.
1979.
6. (a) Petroleum refineries—Reevuluation of
opacity standards, Promulgation Date—June
24.1977.
(b) Petroleum refinery—Clauo sulfur
recovery plants, Promulgation Date—March
15.1978.
(c) Petroleum Refineries—Clarifying
Amendments to Subpart ], Promulgation
Date—March 12,1979.
7. Opacity standard for basic oxygen
process furnaces (Amendments to Subpart
N), Promulgation Date—April 23,1978.
8. Revisions to Reference Methods 1-8.
NSPS Appendix A, Promulgation Date—
August 18,1977; Corrections to Amendments
to Reference Methods 1-8 (March 23,1978).
9. Sewage Sludge Incinerators—
Amendments to Subpart O, Promulgation
Date—November 18,1977.
10. Primary Copper Smelters—
Amendments to General Provisions and
Copper Smelter Standards, Promulgation
Date—November 1,1977.
11. Emission Guidelines and times for
compliance for control of sulfuric acid mist
(addition to Subpart.G), Promulgation Date—
October 18.1977.
12. Revisions to Reference Method 11 for
determining the hydrogen sulfide content of
fuel gas streams. Promulgation Date—January
10,1978.
13. Amendments to Reference Method 13 A
and B—testing and analysis procedures for
fluoride emissions from stationary sources,
Promulgation Date—November 29,1975.
14. Amendment to Reference Method 16—
for determining total reduced sulfur
emissions from stationary sources,
Promulgation Date—January 12,1979.
15. Amendment to Sec. eo.ll(b) Compliance
with Standards and Maintenance
Requirements, Promulgation Date—May 23,
1977.
We are further amending the existing
Delegation of Authority under section 111
dated August 4,1976, by deleting Condition 3
so that this delegation may reflect recent
Amendments to the Clean Air Act which
deleted the exception relating to delegated
authority with respect to new stationary
sources owned or operated by the United
States. Ohio can now enforce New Source
Performance Standards against Federal
sources.
A notice of this amended authority will be
published in the Femoral Kogioto? In the near
future.
Since this delegation is effective upon the -
date of this letter, there is no requirement
that tho Ohio Environmental Protection
Agency (OEPA) notify the United States
Environmental Protection Agancy (USE?A) o?
its acceptance.
Unlcoo USBPA roo3lvc3 tirltten ootiso frsn
OH>A of objections within 10 daya of tho
receipt of thio latter, the OEPA will be
deemed to have accepted all of the terms o!
this delegation.
Sincerely yours,
John McGuire,
Regional Administrator.
August 27.1980.
Certified Moil Rohsra Heguooted
Mr. Jameo F. McAvoy,
Director, Ohio Environmental Protection
Agency, P.O. Box 1049, Columbus, Ohio.
Dear Mr. McAvoy: Thank you for your May
12, I960, letter requesting expansion of you;
existing Delegation of Authority to include
additional New Source Performance
Standards (NSPS) categories.
We have reviewed your request, and have
found your present program and procedures
to be acceptable. Therefore, via are
delegating to the State of Ohio authority to
implement and enforce the NSPS program for
the following source categorieo.
1. Gao turbines in Subpart GG, promulgated
September 10.1979.
2. Petroleum refinery—Clauo sulfur
recovery plants, amendment to Subpart O,
promulgated October 25,1979.
3. Petroleum liquid storage vesselo
construction after June 11,1973 and prior to
May 19,1979, which is a revision to Subpart
K, promulgated April 0. I960.
4. Petroleum liquid storage veosels
constructed after May 18,1078 in oubpart KE,
promulgated April 4.1880.
The terms and conditions applicable to thio
delegation are in the delegation letter of
August 4,1976, ao amended by the November
5., 1979 letter.
A notice of thio delegated authority will be
published in the Federal Register.
Since this delegation is effective upon the
date of this letter, there is no requirement
that the Ohio Environmental Protection
Agency (OEPA) notify the U.S.
Environmental Protection Agency (USEPA) of
its acceptance.
Unless USEPA receives written notice from
OEPA of objections within 10 days of receipt
of this letter, the OEPA will be deemed to
have accepted all of the terms of this
delegation.
Sincerely yours,
John McGuire,
Regional Administrator.
As additional source categories are
promulgated by EPA and delegated to
States, the delegation of authority
agreements will be amended end
published in the Federal Register.
Dated: December 3,1981.
Valdao V. Adosnkuo.
Regional Administrator.
|FR Doc. 01-O321 Died 12-21-01: 0:40 on)
nOEKXSv: Environmental Protection
Agency (EPA).
ACvms Notice of delegation.
v. On December 3. 1981. EPA
delegated to the State of Oregon
Department of Environmental Quality
additional source categories under the
New Source Performance Standards as
approved in their OAR 340-25-505 to
535. The additional source categories
are: coal preparation plant, ferroalloy
production facilities, steel plants —
electric arc furaecao, kraft pulp mills, .
grain elevators, stationary gas turbines,
electric utility steam generating units,
and glass manufacturing plants. This
delegation will amend the November 10,
1975 and April 8, 1978 delegations to the
State of Oregon.
EFFECTIVE OflTS December 3, 1981.
flBBHESSEO: The related material in
support of this delegation may be
examined during normal business hours
at the following locations:
Central Docket Section, (10A-81-6),
West Tower Lobby, Gallery I,
Environmental Protection Agency, 401
M Street, SW.. Washington, D.C.
20460.
Air Programs Branch, Environmental
Protection Agency, Region 10, 1200
Sixth Avenue, Seattle, Washington
98101.
State of Oregon, Department of
Environmental Quality, 522 S.W. Fifth
Avenue, Portland, Oregon 97207.
FOB FUHTHEB INFORKlflYIOK) COMTACT:
Mark H. Hooper, Air Programs Branch,
Environmental Protection Agency, 12CO
Sixth Avenue, Seattle, Washington
98101, Telephone: (208) 442-1260, FTS:
399-1260.
suppUEcasOTflnv IMFOKKJAYIOKS On
November 10, 1975, the Regional
Administrator of EPA, Region 10
delegated to the State of Oregon the
authority to implement and enforce
NSPS for twelve categories of stationary
sources as promulgated by EPA prior to
January 1, 1975. A Notice announcing
this delegation was published in the
Federal Register on February 28, 1978
(35 FR 7749). On April 3. 1978 an
additional source category under NSPS
was delegated to the State and was
published in the Federal Register on
May 10, 1978 (43 FR 20055).
The State of Oregon in a letter dated
May 22, 1981 requested delegation of
V-513
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Federal Register / Vol. 46. No. 245 / Tuesday. December 22. 1981 /Rules and Regulations
eight additional source categories under
NSPS as promulgated by EPA prior to
October 8.1980. The letter granting this
additional delegation of authority to the
State of Oregon was dated December 5,
1981 and is as follows:
Hon. Victor Atiyeh.
Governor of Oregon.
Salem. Oregon
Dear Governor Atiyeh: On May 22,1981.
William Young, Director of the Department of
Environmental Quality (DEQ). requested that
EPA extend the delegation of authority to
enforce additional source categories under
the New Source Performance Standards
(NSPS) granted to the State of Oregon on
November 10,1075. We have reviewed that
request and hereby delegate to DEQ the
authority to enforce the source categories
listed in OAR 340-35-505 to 535 as follows:
Coal Preparation Plants
Ferroalloy Production Facilities
Steel Plants—Electric Arc Furnaces
Kraft Pulp Mills
Grain Elevators
Stationary Gas Turbines
Electric Utility Stream Generating Units
Glass Manufacturing Plants
This delegation is subject to the conditions
outlined In the original letter of delegation
dated November 10.1975 and published in
the Federal Register on February 28.1978 (35
FR 7749) and in a later delegation dated April
3.1978 and published in the Federal Register
on May 10,1978 (43 FR 20055). In addition,
EPA hereby delegates to the State of Oregon
the authority to enforce revisions to NSPS
which have been promulgated through
October S. I960.
A Notice announcing this delegation will
be published in the Federal Register in the
future. The Notice will state, among other
things, that effective immediately, all reports
required pursuant to the Federal NSPS listed
in the State should be submitted to the State
of Oregon, Department of Environmental
Quality. P.O. Box 1760, Portland, Oregon
97207. Any reports which have been or may
be received in this Office prior to the
publication of the Notice will be forwarded to
the Department of Environmental Quality.
Since this delegation is effective
immediately, there is no requirement that the
State notify EPA of its acceptance. Unless
EPA receives from the State written notice of
objections within 10 days of the date of
receipt of this letter, the State will be deemed
to have accepted all the terms of the
delegation.
An advance copy of this Register is
enclosed for your information.
Sincerely yours,
John R. Spencer,
Regional Administrator.
(Sec. 110, Clean Air Act. 42 U.S.C. 7410(a) and
7502)
Dated: December 3,1981.
L Edwin Coate,
Acting Regional Administrator.
|FR Doc S1-M316 Filed 1«1 -61: MS um|
I3Z
'40 CFR Part 60
IA-8-FRL 2010-7]
Delegation of New Source
Performance Standard* to State of
Utah
AOENCY: Environmental Protection
Agency (EPA).
ACTION: Notice of delegation.
SUMMARY: The Environmental Protection
Agency (EPA) hereby places the public
on notice of its delegation of additional
NSPS authority to Utah. This action is
necessary to bring the State of Utah's
NSPS program delegation up to date
with recent EPA promulgations and
amendments of NSPS categories. This
action does not create any new
regulatory requirements affecting the
public. The effect of the delegation is to
shift primary program responsibility for
the affected NSPS source categories
from EPA to the State of Utah.
EFFECTIVE DATE: November 23.1981.
FOR FURTHER INFORMATION CONTACT:
Rex Callaway, 8E-GE, Attorney
Advisor, Environmental Protection
Agency, (EPA) Region VID, 1860 Lincoln
Street, Denver, Colorado 80295.
Telephone (303) 837-2361.
SUPPLEMENTARY INFORMATION: See the
letter included in this notice to the
Governor of Utah.
Since December 23,1971, pursuant to
section 111 of the Clean Air Act, as
amended, the Administrator
promulgated several regulations
establishing standards of performance
(NSPS) for twelve (12) categories of new
stationary sources.
Section lll(c) directs the
Administrator to delegate his authority
to implement and enforce NSPS to any
State which has submitted adequate .
procedures. Nevertheless, the
Administrator retains concurrent
authority to implement and enforce the
standards following delegation of •
authority to the State.
On July 28,1975, the Governor of the
State of Utah submitted to the EPA
Regional Office a request for delegation
of authority. Included in that request
were procedures for NSPS and
information on available resources to
implement such review. Also included in
that request were copies of the State of
Utah regulations which incorporate the
Federal emission standards and testing
procedures set forth in 40 CFR Part 60.
After thorough review of that request
and applicable State statutes, the
Regional Administrator determined that.
for those twelve (12) source categories.
delegation was appropriate, subject to
certain conditions. On May 13,1976, by
letter to the Governor, NSPS authority
was delegated to the State of Utah,
subject to certain enumerated
conditions. Notice of the delegation
appeared in the Federal Register on June
15.1976 (41 FR 24215).
On July 7.1981, the State of Utah
requested a further delegation of
authority for all additional NSPS
categories. The Environmental
Protection Agency revised the twelve
(12) categories of new stationary
sources delegated to Utah on May 13.
1976, several times between July 28,
1975, and July 7.1981. The
Environmental Protection Agency also
established and, subsequently revised
the following additional NSPS
categories during the same time period:
40 CFR Subparts Da, P. Q. R. S. T. U, V,
W, X. Y. Z. AA. BB, CC. DD. HH. GG. JJ.
MM and PP.
' On July 7.1981, the Governor of the
State of Utah submitted to the EPA
Regional Office a request for delegation
of authority for these additions and
revisions to the NSPS. After a thorough
review of the Utah program, the
Regional Administrator has determined
that, for the source categories set forth
in paragraph A of the following official
letter to the Governor of the State of
Utah, delegation is appropriate.
Paragraph B provides that the conditions
set forth in paragraphs 1 through 14 of
the letter of delegation of May 13.1976
(41 FR 24215, June 15,1976) shall be
incorporated herein by reference, and
shall be fully effective as if they were
set forth in full. The text of the letter
from the Regional Administrator to the
Governor of the State of Utah, dated
November 23,1981, is set forth below:
Dear Governor Matheson: I am pleased to
inform you that we are delegating to the State
of Utah authority to Implement and enforce
certain New Source Performance Standards
(NSPS) as provided for under the Clean Air
Act. This decision is in response to Mr. Alvin
E. Kickers' request of July 7,1981. This
delegation includes amendments to 40 CFR
Subparts D, E. F. G, H. I.). K, L, M, N and O
as promulgated by EPA through |uly 7,1981.
and delegation of the following NSPS
categories as promulgated and amended by
EPA as of July 7.1981:40 CFR Subparts Da. P.
Q, R. S, T. U. V, W, X. Y. Z. AA. BB. CC. DD,
GG. HH, J). MM and PP.
We have reviewed the pertinent laws and
regulations of the State of Utah and have
determined that they provide an adequate
and effective procedure for implementation
and enforcement of these additional NSPS by
the State of Utah. Therefore, we hereby
delegate our authority, pursuant to Section
lll(c) of the Clean Air Act. as amended, for
V-514
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Federal Register / Vol. 46. No. 245 / Tuesday. December 22. 1981 / Rules and Regulations
implementation and enforcement of the NSPS
to the State of Utah as follows:
A. Authority for all sources located in the
State of Utah subject to the standards of
performance for new stationary sources as
amended as of July 7,1981. including the
following categories: Electric Utility Steam
Generating Units (40 CFR Subpart Da).
Primary Copper Smelters (40 CFR Subpart P).
Primary Zinc Smelters (40 CFR Subpart Q).
Primary Lead Smelters (40 CFR Subpart R),
Primary Aluminum Reduction "Plants (40 CFR
Subpart S), Phosphate Fertilizer Industry:
Wet Process Phosphoric Acid (40 CFR
Subpart T). Phosphate Fertilizer Industry.
Super-phosphoric Acid (40 CFR Subpart U).
Phosphate Fertilizer Industry: Diammonium
Phosphate (40 CFR Subpart V). Phosphate
Fertilizer Industry: Triple Superphosphate (40
CFR Subpart W). Phosphate Fertilizer
Industry: Granular Triple Superphosphate (40
CFR Subpart X). Coal Preparation Plants (40
CFR Subpart Y), Ferroalloy Production
Facilities (40 CFR Subpart Z), Iron and Steel
Plants (40 CFR Subpart AA). Kraft Pulp Mills
(40 CFR Subpart BB), Glass Manufacturing
Plants (40 CFR Subpart CC), Grain Elevators
(40 CFR Subpart DD), Stationary Gas
Turbines (40 CFR Subpart GG), Lime
Manufacturing Plants (40 CFR Subpart HH),
Degreasers (40 CFR Subpart JJ), Automobile
and Light-Duty Trucks Surface Coating
Operations (40 CFR Subpart MM] and
Ammonium Phosphate (40 CFR Subpart PP).
The delegation of these additional
categories is based upon the following
conditions:
B. All conditions contained in the letter of
delegation dated May 13,1070, from John A.
Green, Regional Administrator,
Environmental Protection Agency, Region
VIII. to Governor Calvin L Rampton, are
incorporated herein by reference, and shall
be fully effective as If they were set forth In
full.
Since the original delegation to the State of
Utah, EPA has also amended the NSPS for
certain source categories. EPA revisions to
the following categories through July 7,1981,
have been incorporated into the Utah Air
Conservation Regulations: Fossil-Fuel Fired
Steam Generators (40 CFR Subpart D),
Incinerators (40 CFR Subpart E), Portland
Cement Plants (40 CFR Subpart F), Nitric
Acid Plants (40 CFR Subpart G), sulfuric Add
Plants (40 CFR Subpart H), Asphalt Concrete
Plants (40 CFR Subpart I). Petroleum
Refineries (40 CFR Subpart I), Storage
Vessels for Petroleum Liquids (40 CFR
Subpart K). Secondary Lead Smelters (40 CFR
Subpart L), Secondary Brass. Bronze and
Ingot Production Plants (40 CFR Subpart M),
Iron and Steel Plants (40 CFR Subpart N). and
Sewage Treatment Plants (40 CFR Subpart
O). Authority to implement and enforce these
revisions to NSPS is hereby delegated to the
State of Utah.
A notice announcing this delegation will be
published in the Federal Register. Since this
delegation is effective immediately, there is
no requirement that the State notify EPA of
its acceptance. Unless EPA receives written
notice of any objections within 10 days of
receipt of this letter, the State will be deemed
to have accepted all of the terms of this
delegation.
As you know, the Clean Air Act give*
primary responsibility for control of air
pollution to the states, and thus It is EPA's
policy to delegate programs such as the New
Source Performance Standard* to state*
whenever possible. We look forward to
working with the State of Utah in the
implementation of the Clean Air Act and
other environmental legislation In the
challenging days ahead.
Sincerely yours,
Steven J. Durham,
Regional Administrator.
Copies of the request for delegation of
authority and the Regional
Administrator's letter of delegation are
available for public inspection at the
following addresses: Utah Air
Conservation Committee, State Division
of Health. 44 Medical Drive. Salt Lake
City, Utah 84113; Environmental
Protection Agency. Region VTIL
Enforcement Division, I860 Lincoln
Street, Denver, Colorado 80295;
Environmental Protection Agency.
Division of Stationary Source
Enforcement, Waterside Mall, Room
3202, 401 M Street. S.W., Washington,
D.C. 20460.
This Notice is issued under the
authority of sections 111 and 112 of the
Clean Air Act as amended (42 U.S.C.
1857, et aeq.) and places the public on
notice of the Regional Administrator's
delegation which took effect on
November 23,1981.
Dated: November 30,1881.
Steven J. Durham.
Regional Administrator. Region VUI.
|FR Doc. a-aen? FIM u~n-ei:»« am]
138
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[A-10-FRL 2006-6]
Standards of Performance for New
Source Performance Standards;
Subdelegation of Authority to •
Washington Local Agency
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: EPA is today approving a
request dated September 23,1981, from
the Washington Department of Ecology
for subdelegation to enforce the New
Source Performance Standards to the
Benton-Franklin-Walla Walls Counties
Air Pollution Control Authority.
EFFECTIVE DATE: November 9,1981.
ADDRESSES: The related material in
support of this subdelegation may be
examined during normal business hours
at the following locations:
Central Docket Section (10A-81-4),
West Tower Lobby, Gallery I.
Environmental Protection Agency, 401
M Street SW., Washington, D.C. 20460
Air Programs Branch, Environmental
Protection Agency, Region 10,1200
Sixth Avenue, Seattle, Washington
98101
State of Washington, Department of
Ecology, 4224 Sixth Avenue. SE..
Lacey, Washington 98503
The Office of the Federal Register. 1100
L Street, NW.. Room 8401.
Washington, D.C.
FOR FURTHER INFORMATION CONTACT
George C. Hofer. Air Programs Branch,
Environmental Protection Agency, 1200
Sixth Avenue. M/S 625, Seattle.
Washington 98101, Telephone: (206) 442-
1352, 399-1352 (FTS).
SUPPLEMENTARY INFORMATION: Pursuant
to section 112(d) of the Clean Air Act, as
amended, the Regional Administrator of
Region 10, Environmental Protection
Agency (EPA), delegated to the State of
Washington Department of Ecology on
February 28,1975, the authority to
implement and enforce the program for
New Source Performance Standards
(NSPS). The delegation was announced
in the Federal Register on April 1,1975
(40 FR 14632).
On September 23,1981, the
Washington State Department of
Ecology requested EPA's concurrence in
the State's subdelegation of the NSPS
program to the Benton-Franklin-Walla
Walla Counties Air Pollution Control
Authority. After reviewing the State's
request, the Regional Administrator
determined that the subdelegation met
all the requirements outlined in EPA's
delegation of February 28,1975.
Therefore, the Regional Administrator
on November 9,1981, concurred in the
subdelegation to the local agency listed
below with the stipulation that all the
conditions placed on the original
delegation to the State shall also apply
to the subdelegation to the local agency
(except fossil fuel-fired steam
generators). EPA is today amending 40
CFR 60.04 to reflect the State's
subdelegation.
The amended § 60.04 provides that all
reports, requests, applications,
V-515
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Federal Register / Vol. 46, No. 251 / Thursday, December 31, 1081 / Rules and Regulations
nnfi cnmniiininfl tionH PCQuiPAo I w 7 ._ _. _. _ _ _ . .» **. _ . . * ... «.«
submlttals and communications required
pursuant to Part 61 which were
previously to be sent to the Director of
the Washington Department of Ecology
will now be sent to the Benton-Fratiklin-
Walla Walla Counties Air Pollution
Control Authority. The amended section
is set forth below.
This rulemaking is effective
immediately and is issued under the
authority of section 112 of the Clean Air
Act, as amended (42 U.S.C. 1857c-7).
Dated: November 20,1981.
John R. Spencer,
Regional Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
In § 60.4, paragraph (b) is amended by
adding paragraph (WW)(viii):
{60.4 Address.
* • • * *
(b) * ' *
(WW)* * *
(viii) Benton-Franklin-Walla Walla
Counties Air Pollution Control
Authority. 650 George Washington Way,
Richland, Washington 99352.
*****
Incorporation by reference of the
State Implementation Plan for the State
of Washington was approved by the
Director of the Office of Federal Register
on July 1.1961. .
(FT) Doc. 81-38315 Filed 12-23-11: »:45 im|
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
(AEN-5FRL 1991-8]
Interim Enforcement Policy for Sulfur
Dioxide Emission Limitations In
Indiana
AGENCY: Environmental Protection
Agency.
ACTION: Policy concerning the
enforcement for sulfur dioxide emissions
limitations.
SUMMARY: The United States
Environmental Protection Agency (U.S.
EPA) is announcing a policy concerning
enforcement of sulfur dioxide emission
limitations contained in the State
Implementation Plan for Indiana.
The promulgated sulfur dioxide
implementation plan is APC-13, as
approved by U.S. EPA on May 14,1973
(38 FR 12698) and August 24, 1976 (41 FI?
35676). These regulations require subject
sources to achieve specific emission
limitations and demonstrate compliance
using test methods specified in 40 CFR
Part 60. U.S. EPA has initiated a review
of its policies and procedures for
regulating sulfur dioxide emissions from
coal-fired plants and has addressed the
question of sulfur variability in that
context. As part of this review, U.S. EPA
has announced its intention to propose
policy and regulatory changes which
would permit states to analyze the air
quality impact of variable sulfur
emissions in their attainment
demonstrations. Since changes to the
rules and policies are required for the
new evaluation technique, a final •
determination on its acceptability can
only be made after public comments on
the policies are reviewed and final
decisions are published.
In the interim, while the sulfur
variability issue is under review, the
Agency will focus its enforcement
resources on those plants which present
the greatest environmental threat. While
the State of Indiana is reevaluating the
emission limitations in a manner
consistent with U.S. EPA's proposed
policy, U.S. EPA will give enforcement
priority to those plants in Indiana which
fail to meet the conditions which afk
listed below.
FOR FURTHER INFORMATION CONTACT:
Louise C. Gross at (312) 886-6844.
SUPPLEMENTARY INFORMATION: The
United States Environmental Protection
Agency (U.S. EPA) is announcing a
policy concerning enforcement of sulfur
dioxide emission limitations contained
in the State Implementation Plan for
Indiana.
The promulgated sulfur dioxide
implementation plan is APC-13, as
approved by U.S. EPA on May 14,1973
(38 FR 12698) and August 24.1976 (41 FR
35676). These regulations require subject
sources to achieve specific emission
limitations and demonstrate compliance
using test methods specified in 40 CFR
Part 60. U.S. EPA has initiated a review
of its policies and procedures for
regulating sulfur dioxide emissions from
coal-fired plants and has addressed the
question of sulfur variability in that
context. As part of this review, U.S. EPA
has announced its intention to propose
policy and regulatory changes which
would permit states to analyze the air
quality impact of variable sulfur
emissions in their attainment
demonstrations. Since changes to the
rules and policies are required for the
new evaluation technique, a final
determination on its acceptability can
only be made after public comments on
the policies are reviewed and final
decisions are published.
In the interim, while the sulfur
variability issue is under review, the
Agency will focus its enforcement
resources on those plants which present
the greatest environmental threat. While
the State of Indiana is reevaluating the
emission limitations in a manner
consistent with U.S. EPA's proposed
policy, U.S. EPA will give enforcement
priority to those plants in Indiana which
fail to meet the conditions which are
listed below.
1. The facility is meeting the currently
applicable, promulgated SO2 emission
limit applied as a 30-day rolling,
weighted average.1
2. The facility obtains information on
SO> emissions as follows and makes this
information available to the State and
U.S. EPA upon request:
a. Coal-fired facilities with greater
than 1000 million BTU per hour of heat
input capacity must conduct daily fuel
sampling analysis for each boiler or
install continuous SO2 monitoring
equipment.
b. Coal-fired facilities with greater
than 100 million BTU per hour of heat
input but less than 1000 million BTU per
hour of heat input capacity perform
monthly composite coal samples for
each boiler.
c. Coal-fired facilities with less than
100 million BTU per hour of heat input
capacity but greater than 10 million BTU
1 Facility, as defined in this proposal, refers to the
combined aggregate of all fossil fuel-fired sources
under common ownership or operation within the
plant boundaries. The 30-day period rufrrs to 30
consecutive operating days.
V-516
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Federal Register f Vol. 46. No. 251 / Thursday. December 31, 1981 / Rules and Regulations
per hour of heat input capacity, must
obtain a monthly average coal analysis
based on coal supplier analyses for all
shipments received during the calendar
month.
d. Coal-fired facilities with less then
10 million BTU per hour of heat input
may obtain a monthly average coal
analysis based on coal supplier analyses
for all shipments received during the
calendar month or utilize other
appropriate procedures approved by the
Indiana Air Pollution Control Division.
3. The facility must maintain records
on the coal consumption for each boiler
(daily for sources with a heat input
capacity of 1000 million BTU or more,
monthly for others). The facility must
calculate its emission rates on an as-
burned basis, in pounda of SOi per
million BTU of heat input These records
should be retained for a minimum of two
years. In addition, sources should
submit quarterly reports to the State of
Indiana in which the required daily or
monthly fuel information is provided.
4. All coal sampling and analysis
should be performed in conformance
with 40 CFR Part 60, Appendix A,
Method 19.
Whether sampling is done as a 30-day
rolling weighted average, a monthly
weighted composite or a vendor
certification, the underlying policy will
be to proceed with enforcement against
any sources which exceed the SIP
emission limitation on a 30-day rolling
weighted average basis. Thus, U.S. EPA
or the State of Indiana could do its own
sampling to establish such a violation. It
should also be emphasized that this
policy is intended to serve solely as a
screening process for the selection of the
highest priority cases in need of Federal
enforcement action. It does not modify
the applicable State Implementation
Plan limits for any source of sulfur
dioxide emissions. Thus, any faculty in
violation of the policy's conditions
would be subject to'enforcement of the
Plan as originally promulgated. Finally,
this policy does not apply to facilities
subject to emission limitations under tht
Clean Air Act's various new source
requirements, e.g., the Federal rules for
the Prevention of Significant
Deterioration (40 CFR 52.21) or the New
Source Performance Standards (40 CFR
Part 60).
Pursuant to the provisions of 5 U.S.C.
605(b), I hereby certify that this policy
does not have a significant economic
impact on a substantial number of small
entities. The policy is merely an option
for sources who wish to avail
themselves of U.S. EPA's enforcement
discretion priorities. The policy does not
impose any additional requirements
beyond those previously required by the
SIP unless a source chooses to comply
with the option.
The information collection
requirements contained in this notice
have been cleared by the Office of
Management and Budget under the
authority of the Paperwork Reduction
Act.
Under Executive Order 12291, U.S.
EPA must judge whether a regulation is
"major" and therefore, subject to the
requirement of a regulatory impact
analysis. This determination is not
"major" as defined by Executive Order
12291, because this action imposes no
new requirements on any source. Any
source may opt to continue compliance
with the existing SIP requirements as
approved.
This determination was submitted to
the Office of Management and Budget
(OMB) for review as required by
Executive Order 12291.
Dated: September 24,1981.
Valdas V. Adamkus,
Acting Regional Administrator.
[PR DOC. n-mao nitd iz-ao-ai: MS m)
140
40 CFR Part 60
Revision* to the Priority Ust of
Categories of Stationary Sources
(AD-fRL-1990-51
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: On May 13.1981. revisions
were proposed (46 FR 28SO1) to the
priority list of major categories of air
pollution sources for which standards of
performance are to be developed under
Section 111 of the Clean Air Act. The
revisions Included the deletion of 12
categories and a title change for one
category. This action promulgates the
revisions as proposed.
EFFECTIVE DATE January 8,1982. Under
section 307(b)(l) of the Clean Air Act,
judicial review of this rule is available
only by the filing of a petition for review
in the U.S. Court of Appeals for the
District of Columbia Circuit within 60
days of today's publication of this rule.
ADDRESSES: Docket. The Docket
number A-80-23, containing all the
information that EPA considered in
revising the priority list 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
(A-130), West Tower Lobby. Gallery 1,
Waterside Mall, 401 M Street. SW.,
Washington, D.C. 20460. A reasonable
fee may be charged for copying.
Source Category Survey Reports. The
reports listed below may be obtained
from the Library Services Office; MD-35,
Environmental Protection Agency,
Research Triangle Park. North Carolina
27711. telephone (919) 541-2777.
Bonn and Bone Acid Industry..
Rafnctory Industry _
Acnmng Industry
Secondary Ztnc Smelting end R«-
•Mnf industry.
Industrial li'icincislDrs—~™—~_
Ammonia Manutacturtno. Industry.....
Animal Fwd DeOuonnMon Indus-
•y
Mnm Wool Manufacturing Indus-
try
Csnmic Clay Industry
Thsfmal Pfowss Phosphoric Acid
Manutacturtng Industry
DMsfoanl fiduBry
. B>A-4SO/3-BU-004
. EPA-450/3-»0-006.
EPA-«SO/VeO-011.
EPA-450/3-80-012.
. EPA-450/S-M-O13.
. EPA-450/3-80-014
et>A-4SO/3-8O-O15
EPA-450/3-SO-OW
EPA-4SO/S-6O-O17.
EPA-4SO/3-BO-Oie.
EPA-450/MO-030
A screening study of the potash
industry may be obtained from the
contact listed below.
FOR FURTHER INFORMATION CONTACT:
Mr. Gene W. Smith, Standards
Development Branch, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency. Research Triangle Park. North
Carolina 27711, telephone (919) 541-
5624.
SUPPLEMENTARY INFORMATION:
Background
Section lll(b)(l)(A) of the Clean Air
Act requires the Administrator to list
those categories of stationary sources
that "* * ' in his judgment * * *
cause{ ]< or contribute! ] significantly to,
_air pollution which may reasonably be
anticipated to endanger public health or
welfare." A category of sources that
V-517
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Federal Register / Vol. 47. No. 5 / Friday, January B. 1982 / Rules and Regulations
meets this criterion is referred to as a
"significant contributor." See, National
Asphalt Pavement Association, v. Train,
539 F.2d 775 (D.C. Cir. 1976).
In 1977, Congress amended the Ad to
require, under Section lll(f)> that the
Administrator promulgate regulations
listing every category of "major"
stationary sources that met the
significant contributor test of Section
lll(b)(l)(A) and that had not already
been listed. A "major" source under the
Act is one that has the potential to emit
100 tons per year of any air pollutant.
Section 302(j]. On August 21,1979, the
Administrator promulgated the list of
significant contributors required by
Section lll(f) (44 FR 49222, 40 CFR
60.16).
Section lll(f) requires the
Administrator to promulgate new source
performance standards (NSPS) for these
additional source categories by 1982,
and to determine priorities for doing so.
Therefore, the August 21,1979
regulations were promulgated as a
"Priority List."
On May 13,1981, an amendment to
the priority list was proposed to take
account of new information developed
by the Agency during studies of the
listed source categories. The results of
these studies indicate that for 12
categories there will be little or no
growth through 1985. In the
Administrator's judgment, Congress did
not intend that source categories
showing insignificant growth should be
listed under the significant contributor
test of section lll(b)(l)(A). Therefore,
the Administrator proposed the deletion
of the following 12 categories from the
priority list.
No. 8 Mineral Wool
No. 12 Incineration: Non-Municipal
No. 15 Secondary Copper
No. 31 Potash
No. 36 Secondary Zinc
No. 39 Ammonia
No. 47 Ceramic Clay Manufacturing
No. 49 Castable Refractories
No. SO Borax and Boric Acid
No. 55 Phosphoric Acid: Thermal Process
No. 57 Animal Feed Defluorination
No. 59 Detergent
In addition, the Administrator also
proposed to change the title of the
source category originally listed as
"Sintering: Clay and Fly Ash" (No. 32 on
the priority list) to "Lightweight
Aggregate Industry: Clay, Shale, and
Slate." The new title more accurately
represents the scope of the source
category for which standards are being
developed.
Comments
Ten comment letters were received
during the public comment period which
extended from May 13,1981, to July 13,
1981. Nine of the ten commenters
expressed concerns that did not directly
pertain to the revisions that were the
subject of the proposed action. The
other commenter recommended that,
rather than change the title of the
Sintering: Clay and Fly Ash category,
the category should be dropped from the
list because no new plant growth is
projected for the industry through 1985.
The results of EPA's study of the
Sintering: Clay and Fly Ash category
indicate that growth in the lightweight
aggregate industry will result from
expansions at existing plants and not
from the construction of new grass roots
plants. Information obtained from
contacts with plants and the Expanded
Shale, Clay, and Slate Institute (ESCSI)
support this projection.
In the preamble to the proposed
revisions, EPA stated that the reason for
deleting the 12 categories was that the
Administrator had concluded that these
categories are not significant
contributors because little or no new
plant growth is projected for these
categories. As explained later in the
proposal preamble, the Administrator's
determination that each of the 12
categories is not a significant
contributor was not based solely on the
fact that there are no new grass roots
plants expected, but also on the
projection that there w".l be no
expansions, modifications, or
reconstructions of facilities at existing
plants. Since facilities comprising
expansions, modified facilities, and
reconstructed facilities at existing plants
would be new sources of air pollution,
these sources must also be considered in
a determination of whether a category is
a significant contributor. Because of the
expected expansions in the lightweight
aggregate industry, the Administrator.
believes that this category should
remain listed as a significant contributor
on the priority list.
For the most part, the remaining nine
commenters recommended that EPA
further revise the priority list by deleting
other categories, in addition to those
that were proposed for deletion. Each of
these comment letters is being
considered by EPA. If, after
investigating the concerns expressed in
these letters, the Administrator
determines that additional source
categories are not significant
contributors, EPA will propose to revise
the priority list again.
For the present, since no comments
were received that objected to the
proposed category deletions and title
change, these revisions are promulgated
today as proposed.
Miscellaneous
Under Executive Order 12291, EPA
must judge whether a regulation is
"major" and therefore subject to the
requirement of a Regulatory Impact
Analysis. This regulation is not major
because it will not have an annual effect
on the economy of $100 million or more,
it will not result in a major increase in
costs or prices, and there will be no
significant adverse effects on
competition, employment, investment,
productivity, innovation, or on the
ability of United States-based
enterprises to compete with foreign-
based enterprises in domestic or export
markets.
Pursuant to the provisions of 5 U.S.C
605(b), I hereby certify that this rule will
not have a significant economic impact
on a substantial number of small
entities. The rule will not impose
burdens on any person.
Dated: December 31,1981.
John W. Hernandez, Jr.,
Acting Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
by revising § 60.16 of 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 emissions •ources
(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 solvent
6. Graphic Arts
7. Polymers and Resins: Acrylic Resins
8. Mineral Wool (Deleted)
9. Stationary Internal Combustion Engines
10. Industrial Surface Coating: Fabric
11. Fossil-Fuei-Fired Steam Generators:
Industrial Boilers
12. Incineration: Non-Municipal (Deleted)
13. Non-Metallic Mineral Processing
14. Metallic Mineral Processing
15. Secondary Copper (Deleted)
16. Phosphate Rock Preparation
17. Foundries: Steel and Gray Iron
18. Polymers and Resins: Polyethylene
19. Charcoal Production
' Low numbers have highest priority, e.g.. No. 1 is
high priority. No. 59 is low priority.
V-518
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Federal Register / Vol. 47, No. 10 / Friday, January 15, 1982 / Rules and Regulations
20. Synthetic Rubber
(H) Tire manufacture
(b) SBR production
21. Vegetable Oil
22. Industrial Surface Coating: Metal Coil
23. Petroleum Transportation and Marketing
24. By-Product Coke Ovens
25. Synthetic Fibers
26. Plywood Manufacture
27. Industrial Surface Coating: Automobiles
28. Industrial Surface Coating: Large
Appliances
29. Crude Oil and Natural Gas Production
30. Secondary Aluminum
31. Potash (Deleted)
32. Lightweight Aggregate Industry: Clay,
Shale, and Slate *
33. Glass
34. Gypsum
35. Sodium Carbonate
36. Secondary Zinc (Deleted)
37. Polymers and Resins: Phenolic
38. Polymers and Resins: Urca-Melamine
39. Ammonia (Deleted)
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 (Deleted)
48. Ammonium Nitrate Fertilizer
49. Castable Refractories (Deleted)
50. Borax and Boric Acid (Deleted)
51. Polymers and Resins: Polyester Resins
52. Ammonium Sulfate
53. Starch
54. Perlile
55. Phosphoric Acid: Thermal Process
(Deleted)
56. Uranium Refining
57. Animal Feed Defluorination (Deleted)
58. Urea (for fertilizer and polymers)
59. Detergent (Deleted)
Other Source Categories
Lead acid battery manufacture *
Organic solvent cleaning *
Industrial surface coating: metal furniture '
Stationary gas turbines '
(Section 111, 301 (a), Clean Air Act as
amended (42 U.S.C. 7411, 7001))
|FR Doc 82-181 Filed 1-7-81 845 >m|
Ml ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[AEN-FRL-2031-8]
Waiver From New Source Performance
Standard for Homer City Unit No. 3
Steam Electric Generating Station;
Indiana County, Pennsylvania;
Correction
AGENCY: Environmental Protection
Agency.
ACTION: Technical correction.
SUMMARY: On November 13,1981, the
United States Environmental Protection
Agency (EPA) published a final rule
granting an innovative technology
waiver under section lll(j) of the Clean
Air Act to Homer City Steam Electric
Generating Station Unit No. 3, Indiana
County, Pennsylvania. 46 FR 55975. In
footnote 6, 46 FR at 55977, EPA stated its
interpretation of the 24-hour National
Ambient Air Quality Standard as a
rolling average, based on 40 CFR Part 58,
Appendix F, § 2.12. That regulation has
been remanded to EPA by the Court of
Appeals. PPG Industries v. Costle,
F. 2d (D.C. Cir. 1981). EPA therefore
withdraws footnote 6 in its entirety,
pending further agency action.
DATES: Effective January 12,1982.
FOR FURTHER INFORMATION CONTACT
Edward E. Reich, Director, Division of
Stationary Source Enforcement, U.S.
Environmental Protection Agency, EN-
341, 401 M Street. SW., Washington,
D.C. 20460, (202) 382-2807.
Dated: January 12,1982.
Richard D. Wilson,
Acting Assistant Administrator for Air, Noise
and Radiation,
|FR Doc. 82-1178 F!l*d 1-14-82; MS im]
V-519
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Federal RogistOT / Vol. 47, No. 18 / Wednesday, January 27. 2882 / Rules and Regulations
142
40 Cm Part SO
Standards of Pertomane© tor Ktera
Stationary Sources; Stationary ©as
Turtoinss-
flGewev: Environmental Protection
Agency (EPA).
aerjow: Final rule.
8UC3K1AI3V: On September 10, 1879. EPA
promulgated a new source performance
standard (NSPS) limiting atmospheric
emissions of NOn from stationary gas
turbines (44 FR 52792). On April 15. 1981.
as a result of petitions for
reconsideration submitted by Dow
Chemical Company, PPG Industries,
Inc.. and Diamond Shamrock
Corporation (Dow, et al.), EPA proposed
(46 FR 22005) to revise the standard for
stationary gao turbines by rescinding the
NO, emission limit for large gas turbines
in Industrial use and pipeline gas
turbines (used in oil Mid gas
transportation or production) located in
metropolitan statistical areas (MSA's).
As a result of public comments, EPA
is rescinding the NOn emission limit for
large (>30 MW) industrial gas turbines
and is including an NOa emission limit
of 150 ppm based on the use of dry
control technology for gas turbines in
industrial use and pipeline gas turbines
of 30 MW or less for which construction,
reconstruction, or modification is begun
after today's date. This notice also adds
an exemption from the 150 ppm NOE
emission limit for regenerative cycle gas
turbines with a heat imput less than
107.2 gigajoules per hour (100 million
Btu/hr) and an exemption for all gas
turbines when they are using an
emergency fuel.
EFFECTIVE ©ATS: January 27, 1982.
Under section 307(b)(l) of the Clean
Air Act, judicial review of this revision
of a new source performance standard
can be initiated only by the filing of a
petition for review in the U.S. Court of
Appeals for the District of Columbia
Circuit within GO days of today's
publication of this rule. Under section
307(b)(2) of the Clean Air Act, the
subject of today's notice may not be
challenged later in civil or criminal
proceedings brought by EPA to enforce
these requirements.
A03E2SS: Docket A docket, number A-
81-10, containing information used by
EPA in development of the promulgated
revision 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), West
Tower Lobby, Gallery 1. Waterside
Mall, 401 M Street. SW., Washington,
D.C. 20460. A reasonable fee may be
charged for copying.
F0K FUHTMEB ICaFORKIflTrHQKl ©©OTA©?:
Mr. Doug Bell, Standards Development
Branch, Emission Standards and
Engineering Division (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone (919) 541-557&
The Standards
The proposed revision to the new
source performance standard published
in the April 15, 1981 Federal Eegisteir
would have rescinded the NOE emission
limit of 75 ppm promulgated in the
September 10, 1979, Fodairsi! HegJstei? for
(1) industrial gas turbines having a heat
input greater than 107.2 gigajoules per
hour (100 million Btu/hr or
approximately 7.5 MW), and (2) pipeline
gas turbines in metropolitan areas with
a heat input greater than 107.2 gigajoules
per hour. Industrial gas turbines are
characterized as having less than one-
third of their rated electrical output sold
to a utility power"distribution system.
The 75 ppm standard was based on the
use of wet controls to reduce NOB
emissions.
This promulgation rescinds the NO,
emission limit for industrial and pipeline
turbines with a base load (normal
operating load as opposed to peak load)
greater than 30 megawatts (MW) and
revises the NOB emission limit from 75
to 150 ppm for the turbines mentioned
above with a base4oad equal to or less
than 30 MW. This promulgation also
exempts turbines subject to the 150 ppm
limit from the NOE standard when
emergency fuel is used and also exempts
all regenerative cycle gas turbines
having a heat input less than or equal to
107.2 gigajoules per hour (ICO million
Btu/hour) from the 150 ppm NOB
standard. The rationale for these
changes to the proposed revision is
contained in the section of this preamble
entitled Significant Comments and
Changes to the Proposed Revision.
The revision was proposed April 15,
1981. in the Federal Register. The
proposed revision requested public
comments and also provided the
opportunity for a public hearing. The
public comment period extended from
April 15,1981, to May 15,1981.
Twelve comment letters were
received, but a public hearing was not
requested. These comments have been
carefully considered; and where
determined to be appropriate by the
Administrator, changes have been made
to the standards of performance.
Significant Comments and Changes to
Comments on the proposed revision to
the standard were received from electric
utilities, chemical companies, oil and
gas producers, gas turbine
manufacturers, and private citizens.
One commenter stated that since
pipeline turbines operate continuously
regardless of location, the NOn emission
limit should be rescinded for all such
turbines.
The standards of performance as
promulgated on September 10,1979,
required pipeline turbines operated in
metropolitan areas to meet an NO»
emission limit of 75 ppm (based on wet
controls) and permitted the same
V-520
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lor / Vol. 47, No. 18 / Wednesday, January 27, 1982 / Rules and Regulations
urbines operated outside metropolitan
'areas to meet an NO, emission limit of
150 ppm (based on dry controls}. The
difference in emission limits was
intended to accommodate a potential
lack of water for wet controls on
pipeline turbines in rural areas.
The April 15,1981, proposed revision
to the standard would have rescinded
the 75 ppm NOn emission limit for all
industrial turbines and pipeline turbines
located in metropolitan areas. The
proposed rescission had been based on
uncertain and possible adverse
economic consequences of using wet
control systems on turbines with long-
term continuous operating requirements
at or near maximum capacity. Dow et al.
claimed that operation at or near
maximum capacity foe one year or more
between internal inspections is required
in industrial applications. They also
claimed that shutdown several times a
year for inspection or maintenance
causes unacceptable economic
consequences. These considerations
also apply to pipeline turbines.
There was no suggestion in the
comments received, nor is there any
reason to believe, that the use of dry
controls (which requires a different
combustor design) would have any
adverse impact on the maintenance of
industrial or pipeline turbines. Dry
control systems have achieved an NOn
emission limit of 150 ppm on turbines of
a size less than 30 MW and would add
little to the capital and operating costs if
required for all turbines in this size
range. The 150 ppm emission limit on
these turbines with dry control
technology is supported by data
contained in the original standard
support and environmental impact
statement (EPA-450/2-77-017a), by
recent information obtained from gas
turbine manufacturers, and by recent
emission tests of turbines in the field. In
the tests five gas turbines, ranging in
size from about 9 to 16.5 MW and using
dry controls, emitted approximately 40
to 80 ppm NOn.
The Agency has no test data showing
that the 150 ppm NOX emission limit has
been achieved by dry controls when
installed on industrial turbines greater
than 30 MW and for that reason did not
propose an NOa emission limit of 150
ppm based on dry controls in the April
notice.
EPA did not propose an NOE emission
limit of 150 ppm for industrial turbines
less than 30 MW or pipeline turbines
less than 30 MW in metropolitan areas
in the April notice. This created an
inconsistency, based on location of the
turbine, which is no.t justifiable.
Accordingly, the standard is being
promulgated to require all industrial and
pipeline turbines with outputs less than
30 MW to achieve an NOa emission limit
of 150 ppm.
Since industrial and pipeline turbines
in MSA's were required by the
September 10,1979, promulgation to
apply water injection technology, some
operators may have to equip these
turbines with new combustore if they
want to discontinue water injection and
still meet the 150 ppm NOn standard
now required. Because of the potentially
high cost of new combustors, this
promulgated revision exempts from
complying with an NO, emission limit
all pipeline turbines inside MSA's and
industrial turbines less than or equal to
30 MW, which were constructed,
modified, or reconstructed between
October 3,1977 (the proposal date of the
original standard), and today's date.
Turbines in this size range constructed,
modified, or reconstructed after today's
date must achieve an NO0 emission limit
of 150 ppm.
The standards of performance for gas
turbines as promulgated required all gas
turbines between 10.7 and 107.2
gigajoules per hour that were
constructed, modified, or reconstructed
after October 3,1982, to achieve an NOn
emission limit of 150 ppm. Today's
promulgated revision has no impact on
this requirement.
One commenter felt that if nitrogen
oxide controls are not required for large
industrial turbines, which operate
continuously at or near maximum
capacity, then they should not be
required for electric utility turbines,
which operate less and emit less
nitrogen oxides. The commenter stated
that if nitrogen oxide controls were not
needed on a full-time turbine, then there
appears to be even less need for use on
a part-time turbine.
The 75 ppm NOn emission limit for
industrial and pipeline turbines inside
MSA's was not rescinded because of the
lack of environmental benefit from
controlling them. Instead, the rescission
was based on the uncertain impacts on
maintenance of the turbines and
possible adverse economic
consequences.
The NOn emission limit was not
rescinded for utility gas turbines
because wet control systems have been
demonstrated to achieve the 75 ppm
NOa emission limit and because utilities
do have the opportunity to shut down
their turbines several times a year for
inspection and maintenance.
Another commenter stated that base
load utility gas turbines should be
exempted from having to meet an NOn
emission limit since these turbines may
be required to operate for one year or
more between internal inspections.
The EPA position is that unlike utility
turbines, industrial turbines in some
instances may represent the sole
primary energy source for a major
industrial process. Such a turbine could
not be shut down more frequently
without an unacceptable economic
consequence. The unacceptable
economic consequence could be that an
entire plant or process depends on the
continuously running gas turbine. This is
not the case for utility turbines,
however, since other electric generators
on the grid can restore lost capacity
caused by turbine down time. Inspection
and maintenance can be scheduled for a
low load period when full generating
capacity is not needed. Since inspection
and maintenance of continuously
running utility turbines is not
economically unreasonable, the NO,
emission limit for these turbines has not
been rescinded.
Another commenter stated that the
action to rescind the NO, emission limit
is not consistent with section III and
section 307(d) of the Clean Air Act, in
that the notice of April 15,1981 (46 FR
20005), did not state the proposed rule's
basis and purpose.
The basis of the April revision was
the lack of data concerning the use of
wet control systems on turbines
operating continuously at or near
maximum capacity and possible
unreasonable economic impacts.
Because of this lack of data, EPA is not
concluding that wet control systems are
best demonstrated technology for
control of NO, emissions from these gas
turbines. The purpose of the April 15
proposal and today's promulgation is to
make the standard consistent with this
conclusion. The April 15 proposal was
consistent with this conclusion in that it
rescinded the 75 ppm NO, limit based
on wet control systems. Today's
promulgation is also consistent with this
conclusion in that the 150 ppm NO, limit
now required for industrial and pipeline
turbines less than or equal to 30 MW is
based on dry controls rather than wet
controls. It is also consistent with this
conclusion in that industrial turbines
greater than 30 MW are no longer
required to meet an NOa emission limit
and therefore do not have to use wet
controls.
One commenter also stated that Dow
et al. offered no evidence to support
their claim that industrial gas turbines
must operate for long periods of time.
Dow et al. did supply information to
the Agency in letters requested to be
held confidential and included in the
docket (11-33 (a), (b). (c)) that indicates
that operation at or near maximum
capacity for periods of a year or more is
V-521
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Federal Register / Vol. 47, No. IB / Wednesday, January 27, 1982 / Rules and Regulations
required of gas turbines in present use.
The data in these letters were
considered by the Administrator in
reaching the conclusions stated in the
preamble to the April 15 proposal.
A commenter also stated that the
revision should have been written to
include only continuously operating gas
turbines rather than all industrial and
pipeline gas turbines.
The Agency investigated the option of
establishing a minimum number of hours
to define "continuous operation" and
using this definition to determine which
industrial and pipeline turbines would
be impacted by this revision. The
Agency determined that to include only
those turbines running continuously,
some arbitrary number of hours would
have to be included in the standard to
define continuous running. The owners
or operators of these gas turbines would
then be required to project the number
of hours per year their turbine would
operate to determine their operating
category. The actual operating times
could vary considerably from the
projections because some unexpected
circumstances may occur, such as
curtailment of plant operation,
unforeseen plant maintenance, or any
other unforeseen circumstances that
have nothing to do with the ability of the
turbine to operate continuously. If the
number of hours projected is less than
the actual number of hours operated,
those turbines that did not operate as
projected for one year could not be
expected to install wet control systems.
In the very next year they may be able
to meet the operating time projection.
Industrial turbines usually run more
hours after initial 1 to 2 year break-in
periods. Since defining "continuous
operation" and projecting exactly how
many hours a turbine will operate is
difficult and since most of the turbines
affected by the revision operate
continuously, the Administrator decided
not to attempt to restrict this revision to
continuously operating industrial and
pipeline gas turbines.
Several commenters stated that the
Agency's definition of electric utility gas
turbine should be made consistent with
the "Power Plant and Industrial Fuel
Use Act of 1978" (FUA) and the "Public
Utility Regulatory Policies Act of 1978"
(PURPA) to allow one half of the electric
output capacity of a cogeneration unit to
be sold to a utility power distribution
system.
The Acts mentioned by the
commenters were designed to encourage
cogeneration. The new source
performance standard for stationary gas
turbines is not intended to encourage or
discourage cogeneration, but is designed
to distinguish between electric utility
gas turbines and industrial gas turbines.
Specifically, in the context of this
revision the definition distinguishes
between those gas turbines that can be
shut down for maintenance without
resulting in shutdown of a dependent
industrial process and those turbines
without backup. For a turbine operating
as part of a cogeneration system and
selling up to 50 percent of its electrical
output to a utility grid, PURPA requires
the utility to sell back-up power to
qualifying cogeneration facilities when
needed. Consequently, the definition of
electric utility gas turbine has not been
revised to allow for a gas turbine selling
up to 50 percent of its power to a utility
power distribution system.
Another commenter pointed out that
some models of pipeline turbines used
outside of MSA's cannot meet the 150
ppm emission limit with the current
combustor design (dry control) without
also using wet control systems. The
commenter suggests that the category of
sources including pipeline turbines
outside MSA's be exempt from meeting
an NO, emission limit.
A new source performance standard,
as required by section 111 of the Clean
Air Act, must reflect "the degree of •
emission reduction achievable through
the application of the best system of
continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction and
any nonair quality health and
environmental and energy requirements)
the Administrator determines has been
adequately demonstrated." Those
models of pipeline turbines that cannot
meet the 150 ppm limit with their current
combustor design (dry control) do not
reflect best technology. There are other
models of pipeline turbines that can
meet the 150 ppm limit using dry
controls without any unreasonable
impacts. Also, these turbines can
perform the same function as those
models that cannot meet the 150 ppm
limit. Therefore, the fact that some
models within a category of gas turbines
cannot meet a standard is not sufficient
reason to exempt the entire category,
especially when turbines capable of
performing the same function while at
the same time complying with the
standard are available. There is no
provision in the gas turbine standard,
however, that prevents an owner or
operator from using wet controls to
comply with the 150 ppm limit if he so
chooses.
One commenter stated that small (less
than 107.2 gigajoules/hour) regenerative
cycle gas turbines should be exempted
from the 150 ppm NO, emission limit.
According to the commenter, dry
controls that can meet the 150 ppm level
have not been developed for these sma
regenerative cycle gas turbines, and the
cost to do so would be exorbitant
because these turbines are only a small
portion of the small gas turbine market.
(These turbines are currently not
required to meet the 150 ppm NO,
emission limit until October 3,1982.)
Because of the exorbitant cost
associated with developing dry controls
for small regenerative cycle gas
turbines, manufacturers would
discontinue these turbines from their
product line rather than develop the dry
control. Small regenerative cycle gas
turbines compete with stationary
internal combustion (I.C.) engines; and,
if these turbines are dropped from
product lines, I.C. engines would be sold
in their place rather than small simple
cycle turbines. Since controlled I.C.
engines emit between two to four times
as much NO, as do uncontrolled small
regenerative cycle gas turbines, the net
effect of requiring small regenerative
cycle gas turbines to meet the 150 ppm
NO, emission limit would be an increase
in NO, emissions.
Additional investigation of small
regenerative cycle gas turbines revealed
the commenter's assessment of the
situation to be correct. Consequently,
the standard is being revised to exempt
regenerative cycle gas turbines of less
that 107.2 gigajoules/hour from
complying with the 150 ppm NO,
emission limit.
Another commenter stated that many
gas turbines that normally operate on
natural gas can be operated on distillate
oil when natural gas is unavailable.
These turbines can meet a 150 ppm NO,
emission limit when operating on
natural gas, but not when they are
operating on distillate oil. The
commenter felt, therefore, that gas
turbines should be exempt from
complying with the standard during
periods when an emergency fuel is being
used.
Upon further investigation, the
Agency learned that many turbine
models can meet the 150 ppm NO,
emission limit only when operating on
natural gas, which is almost always
available. Since operation with an
emergency fuel is expected only rarely
and dry controls would continue to
reduce the emissions during periods
when distillate oil is fired, gas turbines
operating on an emergency fuel are
being exempted from the 150 ppm NO,
emission limit. The exemption will not
apply if the emergency fuel is fired
solely because it is less costly than
natural gas.
This revision was submitted to the
Office of Management and Budget
V-522
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Federal Register / Vol. 47. No. 18 / Wednesday. January 27, 1982 / Rules and Regulations
(OMB) for review as required by
Executive Order 12291. Any comments
from OMB to EPA and any EPA
response to those comments are
included In docket number A-tl-10. Tba
docket is available for public inspection
at EPA's Centra) Docket Section. West
Tower Lobby, Gallery 1, Waterside
Mall, 401M Street SW. Washington,
D.C. 20460.
Under Executive Order 12291, EPA is
required to Judge whether a regulation is
a "major rule" and therefore subject to
certain requirements of the Order. The
Agency has determined that this
revision to the standard would result in
none of the adverse economic effects set
forth in section 1 of the Order as
grounds for finding a regulation to be a
major rule. In fact since this revision
consists of a relaxation of the standard
originally promulgated, it wiO result in
less costs. Some turbines covered by the
original standard will now be exempt
Others will be required to meet a less
restrictive standard based on less
expensive dry controls rather than wet
controls. The Agency has therefore
concluded that this regulation is not a
"major rule" under Executive Order I
12291. /
The Administrator certifies that a
regulatory flexibility analysis under 5
U.S.C. 601 et seq. is not required for this
rulemaking because the rulemaking
would not have a significant impact on a
substantial number of small entities.
Dated: January 22,1962.
Anne M. Gorcuch,
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
For the reasons set out in the
preamble, Part 60 of Chapter I Title 40,
Subpart GG, Code of Federal
Regulations is amended as shown.
1. In { 60.331, paragraphs (q), (r), and
(s) are added to read as follows:
$60.331 Definitions.
* * • • •
(q) "Electric utility stationary gas
turbine" means any stationary gas
turbine constructed for the purpose of
supplying more than one-third of its
potential electric output capacity to any
utility power distribution system for
sale.
(r) "Emergency fuel" is a fuel fired by
a gas turbine only during circumstances,
such as natural gas supply curtailment
or breakdown of delivery system, that
make it impossible to fire natural gas in
the gas turbine.
(s) "Regenerative cycle gas turbine"
means any stationary gas turbine that
recovers thermal energy from the
exhaust gases and utilizes the thermal
energy to preheat air prior to entering
the combustor.
2. Section 00.332 is amended by
revising paragraphs (a), (b), and (d), and
adding paragraphs (j), (k), and (1) to read
as follows:
J 60333 Standard tor nitrogen oilde*.
(a) On and after the date of the
performance test required by 160,8 is
completed, every owner or operator
subject to the provisions of this tnbpart
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), (I), 0). (k). and
(1) of this section.
• * • • •
(b) Electric utility stationary gas
turbines with a heat input at peak load
greater than 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
8 60.332(a)(l).
*****
(d) Stationary gas turbines with a
manufacturer's rated base load at ISO
conditions of 30 megawatts or less
except as provided in 8 6U332(b) shall
comply with 8 60.332(a)(2).
*****
(j) Stationary gas turbines with a heat
input at peak load greater than 107.2
gigajoules per hour that commenced
construction, modification, or
reconstruction between the dates of
October 3,1977, and January 27.1962,
and were required in the September 10,
1979, Federal Register (44 FR 52792) to
comply with 5 60.332f a)(l). except
electric utility stationary gas turbines,
are exempt from paragraph (a) of this
section.
(k) Stationary gas turbines with a heat
input greater than or equal to 10.7
gigajoules per hour (10 million Btu/hour)
when fired with natural gas are exempt
from paragraph (a)(2) of this section
when being fired with an emergency
fuel.
(1) Regenerative cycle gas turbines
with a heat input less than or equal to
107.2 gigajoules per hour (100 million
Btu/hour) are exempt from paragraph
(a) of this section.
3. Section 60.334 is amended by
adding paragraph (c)(4) as follows:
S6O334 Monitoring of operations.
* • * • •
(c) • • •
(4) Emergency fuel. Each period
during which an exemption provided in
8 60.332(k) is in effect shall be included
in the report required in 8 60.7(c). For
each period, the type, reasons, and
duration of the firing of the emergency
fuel shall be reported.
(Sec. 114 of the Clean Air Act at amended (42
U.S.C. 16570-fl))
(FR Doc. B-au PI ted !-»-•* (41 »m|
V-523
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Federal Register / Vol. 47. No. 35 / Monday. February 22. 1982 / Rules and Regulation*
143
40 CFR Part 60
[A-«-FRL-2055->]
Delegation of Authority to the State of
Louisiana for New Source
Performance Standards (NSPS)
AGENCY: Environmental Protection
Agency (EPA).
ACTION; Final rule.
SUMMARY: EPA, Region 6. has delegated
the authority for implementation and
enforcement of NSPS to the Louisiana
Department of Natural Resources
(LDNR), Air Quality Division. Except as
specifically limited, all of the authority
and responsibilities of the Administrator
or the Regional Administrator which are
found in 40 CFR Part 60 are delegated to
the LDNR. Any of such authority and
responsibilities may be redelegated by
the Department to its Director or staff.
EFFECTIVE DATE: January' 25.1982.
ADDRESS: Copies of the State request
and State-EPA agreement for delegation
of authority are available for public
inspection at the Air Branch,
Environmental Protection*Agency.
Region 6, First International Building,
28th Floor. 1201 Elm Street, Dallas,
Texas 75270.
FOR FURTHER INFORMATION CONTACT:
William H. Taylor, Air Branch,
Environmental Protection Agency,
Region 6, First International Building.
28th Floor. 1201 Elm Street Dallas,
Texas 75270: (214) 767-1594 or (FTS)
729-1594.
SUPPLEMENTARY INFORMATION: On
December 17.1981. the State of
Louisiana submitted to EPA, Region 6, a
request for delegation of authority to the
LDNR for the implementation and
enforcement of the NSPS program. After
a thorough review of the request and
information submitted, the Regional
Administrator determined that the
State's pertinent law* and the rules and
regulations of the LDNR were found to
provide an adequate and effective
procedure for the implementation and
enforcement of the NSPS program.
The Office of Management and Budget
has exempted this Information notice
from the requirements of Section 3 of
Executive Order 12291.
Effective immediately, all information
pursuant to 40 CFR Part 60 by the
sources locating In the State of
Louisiana should be submitted directly
to the State agency at the following
address: Louisiana Department of
Natural Resources, Air Quality Division.
P.O. Box 44086. Baton Rouge, Louisiana
70804.
(Sec. Ill of the Clean Air Act, tt amended
(42 U.S.C. 7411))
Dated: February 8.1862.
France! E. Phillips.
Acting Regional Adau'niitrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter 1, Title 40 of the
Code of Federal Regulations is amended
as follows:
Section 60.4 paragraph (b) is amended
by revising subparagraph (T) to read as
follows:
{.60.4 Address.
(b)* ' '
(A)-(S)
(T) State of Louisiana, Program
Administrator, Air Quality Division,
Louisiana Department of Natural
Resources, P.O. Box 44066, Baton Rouge,
Louisiana 70804.
[FR Doc. 12-4702 Filed l-W-tt Mi un|
BILUNQ CODE (540-M-M
40 CFR Parts 60 and 61
[A-6-FRL-2057-1]
New Source Performance Standards
•nd National Emission Standards for
Hazardous Air Pollutants; Delegation
of Authority to the State of Arkansas
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: EPA has delegated the
authority for implementation and
enforcement of New Source
Performance Standards (NSPS) and
National Emission Standards for
Hazardous Air Pollutants (except
demolition and renovation of buildings
containing asbestos) to the Arkansas
Department of Pollution Control and
Ecology (ADPCE). The State specified in
its request that delegation of authority
for demolition and renovation of
buildings containing asbestos, would not
be accepted. Except as specifically
limited, all of the authority and
responsibilities of the Administrator or
the Regional Administrator which are
found in 40 CFR Part 60 and 40 CFR Part
61 are delegated to the ADPCE. Any of
such authority and responsibilities may
be redelegated by the Department to its
Director or staff.
EFFECTIVE DATE: September 14.1981.
ADDRESS: Copies of the State request
and State-EPA agreement for delegation
of authority are available for public
inspection at the Air Branch,
Environmental Protection Agency.
Region 6, First International Building,
28th Floor, 1201 Elm Street Dallas.
Texas 75270; (214) 767-1594 or (FTS)
729-1594.
FOR FURTHER INFORMATION CONTACT.
William H. Taylor, Air Branch, address
above. Telephone: (214) 767-1594 or
(FTS) 729-1594.
SUPPLEMENTARY INFORMATION: On July
1,1981, the State of Arkansas submitted
to EPA. Region 6, a request for
delegation of authority to the ADPCE for
the implementation and enforcement of
the NSPS and NESHAP programs
(except demolition and renovation of
buildings containing asbestos). After a
thorough review of the request and
information submitted, the Regional
Administrator determined that the
State's pertinent laws and the rules and
regulations of the ADPCE were found to
provide an adequate and effective
procedure for implementation and
enforcement of the NSPS and NESHAP
programs.
Under Executive Order 12291. EPA
must judge whether a publication is
"major" and therefore subject to the
requirements of a regulatory impact
analysis. The delegation of authority is
not "major", because it is an
administrative change, and no
additional burdens are imposed on the
parties affected.
The delegation letter to Arkansas was
submitted to OMB and determined not
to be a major rule under E.0.12291.
Effective immediately, all information
pursuant to 40 CFR 60 and 61 by sources
locating in the State of Arkansas should
be submitted to the State agency at the
following address: Arkansas
Department of Pollution Control and
Ecology, 8001 National Drive, Little
Rock, Arkansas 72209.
V-524
-------
(Sec*. 101 end 301 of the dean Air Act a»
amended (42 U.S.C. 7401 and 7601))
Dated: February 2, 1982.
Frances E. Phillip*,
Acting Regional Administrator.
PART 60— STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter 1. Title 40 of the
Code of Federal Regulations is amended
as follows:
Section 80.4 paragraph (b) is amended
by revising subparagraph (E) to read as
follows:
§60.4 Addrts*.
(E) State of Arkansas. Program
Administrator. Air and Hazardous Material*
Division. Arkansas Department of Pollution
Control and Ecology. 8001 National Drive.
Little Rock. Arkansas 72209.
144
40 CFR Parts 60 and 61
[A-4-FRL-2080-3]
Standards of Performance for New
Stationary Sources National Emission
Standards for Hazardous Air
Pollutants; Mississippi: Delegation of
Authority
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The amendments institute
certain address changes for reports and
applications required from operators of
certain sources subject to Federal
regulations. EPA has delegated to the
State of Mississippi authority to review
new and modified sources. The
delegated authority includes the review
under 40 CFR Part 60 for the standards
of performance for new stationary
sources and review under 40 CFR Part
61 for national emission standards for
hazardous air pollutants. A notice
announcing the delegation of authority
was published in the Notices section of
the March 22,1982 issue of the Federal
Register. These amendments provide
that all reports, requests, applications,
Bubmittals, and communications
previously required for the delegated
reviews will now be sent to the Bureau
of Pollution Control, Department of
Natural Resources, P.O. Box 10385,
Jackson, Mississippi 39209.
IFFECTIVE DATE: November 30,1981.
FOR FURTHER INFORMATION CONTACT:
Ms. Denise W. Pack, Air Programs
Branch, Environmental Protection
Agency, Region IV, 345 Courtland Street,
N.E., Atlanta, Georgia 30365, phone 404/
881-3286.
SUPPLEMENTARY INFORMATION: The
Regional 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 November
30,1981. and it serves no purpose to
delay the technical change of this
addition of the state address to the Code
of Federal Regulations.
The Office of Management and Budget
has exempted this regulation from the
OMB review requirements of Executive
Order 12291 pursuant to Section 3(b) of
that order.
(Sees. 101.110. 111. 112. 301. Clean Air Act. as
amended. (42 U.S.C. 7401. 7411. 7412. 7601))
Dated: March 3.1982.
Charles R. Jeter.
Regional A dministrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter I. Title 40. Code of
Federal Regulations, is amended as
follows:
In § 60.4. paragraph (b)(Z) is added as
follows:
560.4 Address.
(b) * * *
(Z) Bureau of Pollution Control.
Department of Natural Resources, P.O. Box
10385. Jackson. Mississippi 39209.
V-525
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Federal Register / Vol. 47. No. 74 / Friday. April 16.1982 / Rules and Regulations
145
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
(AD-FRL 1718-2]
Standards of Performance for New
Stationary Sources; Lead-Acid Battery
Manufacture
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which limit
atmospheric emissions of lead from
new, modified, and reconstructed
facilities at lead-acid battery plants. The
standards implement Section 111 of the
Clean Air Act, and are based on the
Administrator's determination that lead-
acid battery manufacturing facilities
contribute significantly to air pollution,
which may reasonably be anticipated to
endanger public health or welfare. The
intended effect of this regulation 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
promulgated.
EFFECTIVE DATE: April 16,1982.
Under Section 307(b)(l) of the Clean
Air Act, judicial review of this new
source performance standard is
available only by the filing of a petition
for review in the United States Court of
Appeals for the District of Columbia
Circuit within 60 days of today's
publication of this rule. Under Section
307(b)(2) of the Clean Air Act, the
requirements that are the subject of
today's notice may not be challenged
later in civil or criminal proceedings
brought by EPA to enforce these
requirements.
ADDRESSES:
Background Information Document.
The Background Information Document
(BID) for the promulgated 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
"Lead-Acid Battery Manufacture,
Background Information for
Promulgated Staff dards," EPA-450/3-
79-028b.
Docket. Docket No. OAQPS-79-1.
containing supporting information used
in developing Ihe promulgated
standards, 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,
West Tower Lobby, Gallery 1,
Waterside Mall, 401 M Street SW.,
Washington, D.C. 20460. A reaonable fee
may be charged for copying.
FOR FURTHER INFORMATION CONTACT:
Mr. Gene W. Smith, Standards
Development Branch, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5624.
SUPPLEMENTARY INFORMATION:
The Standards
The promulgated standards will limit
atmospheric lead emissions from new,
modified, or reconstructed facilities at
any lead-acid battery manufacturing
plant which has the design capacity to
produce in one day batteries which
would contain, in total, an amount of
lead equal to or greater than 5.9 Mg (6.5
tons). The facilities which are affected
by the standards and the emission limits
for these facilities are listed below:
Fac«tir
God casting
Thre*-pr
Lead recUmMlon
Other toad emitting
(ten*.
oper-
LBSO ocntssion BmN
S.O mg/kg (0.010 fc/ton).
0.40 mg/dKrn (0.00018 gr/
(tec()>
1.00 mg/dscni (0.00044 gr/
dscf).
1.00 mg/dscm (0.00044 gr/
dscf).
4.50 mg/dtcm (0.001M gr/
dscf).
1.00 mg/dacm (0.00044 gr/
dscf).
The emission limit for lead oxide
production is expressed in terms of lead
emissions per kilogram of lead
processed, while the limits for other
facilities are expressed in terms of lead
concentrations in exhaust air.
A standard of 0 percent opacity Is
promulgated for emissions from lead
oxide production, grid casting, paste
mixing, three process operation, and
"other lead-emitting" facilities. A
standard of 5 percent opacity is
promulgated for lead reclamation
facilities. The promulgated standards
also require continuous monitoring of
the pressure drop across any scrubber
used to control emissions from an
affected facility to help insure proper
operation of the scrubber. Performance
tests are required to determine
compliance with the promulgated
standards. A new reference method.
Method 12, is to be used to measure the
amount of lead in exhaust gases, and
Method 9 is to be used to measure
opacity. Process monitoring is required
during all tests.
In the preamble to the proposed
regulation, the decision by the
Administrator not to propose standards
for sulfuric acid mist emissions from the
formation process was discussed. The
public was specifically invited to submit
comments with supporting data on this .
issue. Only one comment addressing
this issue was received and, while the
commenter suggested that acid mist
emissions need EPA attention, no
specific information was provided to
refute the basis for the Administrator's
decision not to regulate. Therefore, the
Administrator does not plan to take any
further action regarding acid mist
emissions from lead-acid battery
manufacture at this time. EPA is
required to review new source
performance standards four years from
the date of promulgation, and if
appropriate, revise them. The decision
not to regulate acid mist emissions may
be reconsidered at that time.
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 above
the small size cutoff. 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).
In general, States do not currently
regulate atmospheric lead emissions
from lead-acid battery plants. However,
State implementation plan (SIP)
particulate regulations generally require
some control of these emissions. The
average degree of control required by
SIP regulations was used as a baseline
for the assessment of the environmental
and economic impacts of the new source
performance standards for lead-acid
battery manufacture. At some existing
plants, emissions are controlled to a
greater extent than is required by
typical State particulate regulations. In
addition, States are developing
implementation plans to insure the
attainment and maintenance of the
national ambient air quality standard
(NAAQS) for lead, which was
•promulgated in December 1977 (42 FR
63076). The State implementation plans
for lead are expected to include
regulations which will require more
control of atmospheric lead emissions
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than is currently required under typical
State particulate regulations.
New facilities and facilities
(undergoing modification and
reconstruction in the United States over
the next 5 years would emit about 95 Mg
(103 tons) of lead to the atmosphere in
the fifth year, if their emissions were
controlled only to the extent required by
current State particulate regulations.
The promulgated standards will reduce
potential lead emissions from new,
modified, and reconstructed facilities to
about 3.1 Mg (3.4 tons) in the fifth year.
The promulgated standards will also
result in decreased nonlead particulate
emissions from affected facilities, since
equipment installed for the purpose of
controlling lead-bearing particulate
emissions will also control nonlead-
bearing particulate emissions.
For a new or completely reconstructed
plant using impingement scrubbing to
control lead emissions from the grid
casting and lead reclamation facilities
and fabric filtration to control emissiono
from all other affected facilities, the
fractional increase in the lead content of
plant wastewater attributable to the
(standards will be about 0.3 percent. It is
anticipated that, in early 1681, EPA's
Office of Water and Waste Management
will propose a regulation which would
require zero lead discharge in the
wastewater from grid casting and lead
reclamation facilities. In order to
achieve zero discharge from these
facilities, scrubber effluent would have
to be clarified and recycled. Although
not directly attributable to the
promulgated NSPS for air emissions, the
costs of clarifying and recycling
blowdown from scrubbers controlling
grid casting and lead reclamation
emissions has been considered in the
development of the promulgated NSPS.
The ennualized cost of controlling water
omissions from grid casting and lead
reclamation facility scrubbers would be
Isoo than 1 percent of the costs
attributable to the promulgated
standards for a completely modified or
reconstructed 2000 battery-per-day
plant. The promulgated NSPS will not
have a significant impact on emissions
of solid waste.
The energy needed to operate control
equipment required to meet the
promulgated standards at a new plant
will be approximately 2.7 percent of the
total energy needed to run the plant. The
incremental energy demand resulting
from the application of the promulgated
Qtandards to new, modified, and
reconstructed facilities over the next
five years will be about 2.8 gigawatt
hours of electricity in the fifth year. The
fifth-year increase in demand for heat
energy resulting from the promulgated
standards will be about 50 PJ/yr (48 X
10° BTU/yr), or the equivalent of about
8.1 thousand barrels of oil per year.
The capital cost of the installed
emission control equipment necessary to
meet the promulgated standards on all
new, modified, and reconstructed
facilities during the first five years of the
standards will be approximately §8.2
million. The total ennualized cost of
operating this equipment in the fifth
year of the standards will be about $3.9
million.
These costs and energy and
environmental impacts are considered
reasonable, and are not expected to
prevent or hinder expansion on the lead-
acid battery manufacturing industry.
Economic analysis indicates that, for
plants with capacities larger than the
small size cutoff, the costs attributable
to the standards can be passed on with
little effect on sales. The average
incremental cost associated with the
promulgated standards will be about 30$
per battery. This is about 1.3 percent of
the wholesale price of a battery.
Prior to proposal of the standards,
interested parties were advised by
public notice in the Federal Register of Q
meeting of the National Air Pollution
Control Techniques Advisory
Committee to discuss the standards
recommended for proposal. This meeting
was held September 27-28,1977. The
meeting was open to the public and each
attendee was given ample opportunity
to comment on the standards
recommended for proposal. The
standards were proposed in the Federal
2780). Public comments were solicited at
that time and, when requested, copies of
the Background Information Document
(BID) were distributed to interested
parties. To provide interested persons
the opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards, a public hearing
was held on February 13,1980, at
Research Triangle Park, North Carolina.
The hearing was open to the public and
each attendee was given an opportunity
to comment on the proposed standards.
The public comment period extended
from January 14,1980 to March 14,1980.
Twenty-one 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.
to
Comments on the proposed standards
were received from industry
representatives, Stale air pollution
control agencies, and two Federal
agencies. Detailed discussion of these
comments can be found in Volume II of
the Background Information Document
(BID). The major comments can be
combined into the following areas:
general, emission control technology,
economic impact, legal considerations,
test methods and monitoring, reporting
and recordkeeping, and other
considerations.
Facilities at any plant with a
production capacity of less than 500
batteries per day (bpd) were exempted
under the proposed standards. Some
commenters felt that the number of
batteries which can be produced at a
plant was not the appropriate criterion
on which to base the size cutoff. It was
pointed out that lead-acid batteries are
produced in a variety of sizes, and that
emissions from battery production are
probably related more to the amount of
lead used to produce batteries than to
the number of batteries produced.
These are considered to be reasonable
comments. Economic impacts of
standards as well as emissions are
expected to be related to the amount of
lead used in a particular battery
production operation rather than to the
number of batteries produced. At the
time of proposal, it was estimated that
odd-sized lead-acid batteries
represented a very small share of the
lead-acid battery market; however, the
comments received on the proposed
standards indicated that a significant
number of odd-sized batteries are
produced. Industrial lead-acid batteries,
which can be as much as 50 times larger
than automobile batteries, are estimated
to represent about 7 percent of total U.S.
lead-acid battery production.
Therefore, the small size cutoff for the
promulgated regulation is expressed in
terms of lead throughput. The
promulgated standards will affect new,
modified, and reconstructed facilities at
any plant with the capacity to produce
in one day batteries which would
contain, in total, an amount of lead
greater than or equal to 5.9 Mg (8.5 tons).
This cutoff is equivalent to the 500 bpd
cutoff for plants producing typical
automobile batteries. The level is based
on an average battery lead content of
11.8 kg (23 Ib) of lead per battery.
One commenter questioned whether
plant capacity is to be determined based
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Federal Register / Vol. 47. No. 74 / Friday, April 16. 1982 / Rules and Regulations
on the maximum demonstrated
production rate or the estimated
maximum production rate, for the
purposes of the small size cutoff.
For the purposes of the small size
cutoff, the parameter to be used to
determine the production capacity of a
plant is its design capacity. The design
capacity is the maximum production
capability of the plant and can be
determined using the design
specifications of the plant's component
facililties. taking into account the
facility with the smallest rated
production capacity. The design
capacity of a plant can be confirmed by
checking production records. The figure
cited as a plant's production capacity
should not be less than the maximum
production rate in the plant's records.
Several commenters felt that the 500
bpd cutoff should be raised to 2000 bpd.
This contention was based on the fact
that the Federal regulations which set
minimum standards for State
implementation plans (SIPs) for the lead
national ambient air quality standard do
not require ambient air quality
monitoring or atmospheric dispersion
analyses for plants smaller than 2000
bpd (40 CFR 51.80(a)(l) and 51.84(a)).
The commenters considered these
cutoffs to be indicative of a decision by
EPA that battery plants smaller than
2000 bpd are not material contributors to
lead air pollution.
It should be noted that the Federal
regulations to which the commenters
referred only set minimum standards for
a lead SIP. Also, as discussed In the
Legal Considerations section of this
preamble, the regulatory approach for
NAAQS regulations promulgated under
Section 109 of the Clean Air Act differs
from that for standards of performance
promulgated under Section 111 of the
Act. The small size cutoff for the
standards of performance for lead-acid
battery manufacture is based on a
thorough analysis of the economic
impacts of these standards. The analysis
indicated that the economic impact of
standards on plants smaller than about
250 bpd could be severe, but showed
that the economic impact would be
reasonable for plants with capacities
greater than or equal to 500 bpd. None of
the commenters submitted information
indicating that the ecomomic impact of
standards might be severe for plants in
the 500 to 2000 bpd size range.
Therefore, although the small size cutoff
is now expressed in terms of lead
throughput rather than battery
production, the level of the cutoff
remains at the lead throughput capacity
which corresponds to a production
capacity of 500 bpd.
Several commenters contended that
the proposal of a 0 percent opacity
standard for all affected facilities was
impractical. These commenters were
concerned that emissions from facilities
which emit fine particles would exceed
0 percent opacity. Also, some were
concerned that emissions from facilities
controlled by fabric filters would exceed
0 percent opacity during fabric filter
cleaning. However, one commenter
stated that the 0 percent opacity
standard appears achievable for all
affected facilities.
The 0 percent opacity standard for
lead oxide manufacturing, grid casting,
paste mixing, three-process operation
and "other lead-emitting" facilities is
considered reasonable. Lead oxide
manufacturing, grid casting, paste
mixing, and three-process operation
facilities were observed by EPA to have
emissions with 0 percent opacity for
periods of 3 hours and 19 minutes, 7
hours and 16 minutes, 1 hour and 3O
minutes, and 3 hours and 51 minutes,
respectively. Under the promulgated
standards, compliance with the opacity
standard is to be determined by taking
the average opacity over a 6-minute
period, according to EPA Test Method 9,
and rounding the average to the nearest
whole percentage. The rounding
procedure is specified in order to allow
occasional brief emissions with
opacities greater than 0 percent which
may occur during fabric filter cleaning.
For grid casting, the observations were
made at a facility controlled by an
impingement scrubber. For lead oxide
production and three-process operation
facilities, the observation periods
included fabric filter cleaning phases.
The opacity standard for lead
reclamation has been changed to 5
percent in the promulgated standards. A
standard of 0 percent opacity was
originally proposed for lead reclamation,
although emissions with opacities
greater than 0 percent were observed
from the facility tested by EPA. The 0
percent opacity standard was
considered reasonable, because the
facility tested by EPA was controlled by
an impingement scrubber and the .
proposed emission limit for lead
reclamation was based on transfer of
fabric filtration technology. As noted in
the CONTROL TECHNOLOGY
discussion, the final emission limit for
lead reclamation is based on the
demonstrated emission reduction
capabilities of the impingement scrubber
on the facility tested by EPA. The final
opacity standard of 5 percent is baaed
on observations at this facility.
Emissions from this facility were
observed for 3 hours and 22 minutes.
The highest 6-minute average opacity
during the 3 hour 22 minute observation
period was 4.8 percent. Therefore, the 5
percent opacity standard for lead
reclamation is considered achievable.
Under the general provision*
applicable to all new source
performance standards, the operator of
an affected facility may request the
Administrator to determine the opacity
of emissions from the affected facility
during the initial performance test (40
CFR 60.11). If the Administrator finds
that the affected faculty is in
compliance with the applicable
standards for which performance tests
are conducted, but fails to meet an
applicable opacity standard, the
operator of the facility may petition the
Administrator to make an appropriate
adjustment to the opacity standard for
the facility.
Some commenters stated that EPA
should establish a relationship between
opacity and emissions before setting
opacity standards.
Opacity limits are being promulgated
in addition to mass emission limits
because the Administrator believes that
opacity limits provide the most effective
and practical method for determining
whether emission control equipment
necessary for a source to meet the mass
emission limits, is continuously
maintained and operated properly. It
has not been the Administrator's
position that a single, constantly
invariant and precise correlation
between opacity and mass emissions
must be identified for each source under
all conditions of operation. Such a
correlation is unnecessary to the opacity
standard, because the opacity standard
is set at a level such that if the opacity
standard is exceeded for a particular
facility, one would expect that the
applicable emission limitation will also
be exceeded. Furthermore, as noted
above, a mechanism is provided in the
general provisions whereby the operator
of a facility can request that a separate
opacity standard be set for that facility
if, during the initial performance test
the Administrator finds that the facility
is in compliance with all other
applicable standards but fails to meet
the respective opacity standard.
One commenter felt that additional
testing should be conducted before
standards are promulgated. The
commenter contended that the EPA data
base is narrow, and that tests should be
conducted to determine the variability
of the efficiency of emission control
devices.
The Administrator has determined
that the data base developed by EPA
provides adequate support for the
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:w I Vol. <37, No. 74 / Friday, April 18, 1882 / Rules and Regulations
promulgated new source performance
otandards. The promulgated standards
are based on tests of a total of eight
facilities which have been determined
by EPA to be well controlled and typical
of facilities used in the industry. As
noted by some commenters, EPA has not
tested emissions from facilities
producing maintenance-free or low-
maintenance batteries or Barton lead
oxide production facilities. Differences
between such facilities and the facilities
tested by EPA are discussed in detail
below and in the Emission Control
Technology section. These differences
are not expected to have a significant
effect on the controlled lead
concentrations achievable using the
emission control techniques tested by
EPA. Commenters did not refer to nor is
EPA aware of any other specific process
variations which might influence
emissions. The Agency has set the
promulgated lead emission limits above
the levels achieved in the EPA tests to
allow solely for variations caused by
factors that the Agency cannot identify
at this time.
Some commenters stated that changes
have occurred in the lead-acid battery
manufacturing industry, which may
influence emissions, since the EPA tests
were conducted. The changes cited by
the commenters were the production of
maintenance-free and low-maintenance
batteries, and the increasing of volumes
of air ventilated from facilities in order
to meet more stringent OSHA standards
regulating in-plant lead levels.
The commenters briefly described the
difference between maintenance-free or
low-maintenance batteries and normal-
maintenance batteries. The only
substantial difference is that a calcium-
lead alloy is used to make low-
maintenance and maintenance-free
batteries, while standard batteries are
made using an antimonial lead alloy.
This difference influences the grid
casting and lead reclamation facilities,
where molten lead is processed. The
major change is in the makeup of the
dross which must be removed from
molten lead in these facilities. For grid
casting, the calcium alloy also requires
the use of soot as a mold release agent.
For the antimonial lead alloy used in
standard batteries, either soot or sodium
silicate can be used.
The different makeup of dross in grid
casting and lead reclamation facilities
producing maintenance-free and low-
maintenance batteries is not expected
by EPA to cause noticeable differences
in lead emissions between these
facilities and facilities producing
standard lead-acid batteries. The
commenters did not give reasons why
this difference might be expected to
affect emissions and EPA is not aware
of any. Dross consists of contaminants
in the molten lead alloy which float to
the surface and must periodically be
removed. The presence of a dross layer
has an impact on emissions, in that the
dross layer serves to reduce fuming from
the molten lead. However, this will
occur regardless of the composition of
the dross layer. Also, because the dross
layer is made up chiefly of contaminants
from the lead, the entrainment of dross
particles in air exhausted from grid
casting or lead reclamation facilities will
not significiantly affect lead emissions.
Thus, the effect of the dross layer
composition on emissions is expected to
be much less than the effects of process
operation parameters, such as the
frequency of dross removal and the
temperature of the molten lead alloy.
The use of soot rather than sodium
silicate as a mold release agent in grid
casting will not affect uncontrolled lead
emissions from this facility. However,
the presence of entrained soot in
uncontrolled grid casting emissions may
require the use of scrubbers rather than
fabric filters to control these emissions.
This problem is discussed in detail in
the EMISSION CONTROL
TECHNOLOGY section.
The commenters stated that exhaust
volumes for lead-acid battery facilities
have been increased as a result of the
revised OSHA standards. One
commenter contended that this change
will increase the concentration of
uncontrolled emissions.
It is acknowledged that the exhaust
volumes at the facilities tested by EPA
may not have been sufficient for
attainment of the 50 ^g/ma OSHA in-
plant lead concentration standard. At
the time of the tests conducted by EPA
the OSHA standard was 200 fig/m3.
Among the practices that plants can
employ to meet the new standard are
general plant maintenance, employee
care, and local ventilation of in-plant
lead emission sources. EPA recognizes
that if ventilation rates significantly
higher than those used at the facilities
tested by EPA are used to meet the new
OSHA standard, additional lead
particles will be drawn into the exhaust
streams. However, the exhaust volume
increase will be greater than the lead
weight increase by a margin sufficient
not only to prevent an increase in the
lead concentration in the exhaust, but
actually to decrease that concentration.
Also, the additional lead particles
captured as a result of the higher
exhaust volumes will consist mainly of
large particles which are readily
captured by control systems.
One commenter stated that there is a
trend in the lead-acid battery
manufacturing industry to the use of
finer lead oxide in battery pastes in
order to increase battery efficiency. The
commenter also contended that this
particle size change will influence the
collection efficiency attainable with
fabric filters.
Lead emissions from lead-acid battery
manufacture are generated by two
mechanisms. Lead oxide fumes are
produced in welding, casting, and
reclaiming operations, and to a certain
extent in lead oxide production.
Agglomerates of lead and lead oxide
particles are emitted from operations
involving the handling of lead oxide,
lead oxide paste, and lead grids. The
particles which are most difficult to
capture are the fume particles. The
emission rate and characteristics of the
fume particles are not dependent on the
size of the lead oxide particles used in
battery pastes, but on the temperature of
the lead during the operations from
which they are emitted. For these
reasons, trends in the industry to the use
of smaller lead oxide particles are not
expected to change the particle size
distributions of emissions in such a way
that collector performance will be
affected.
Emission Control Technology
Some commenters .thought that the
proposed standards would have
required the use of fabric filtration to
control emissions.
The proposed standards would not
have required that specific control
technology be used for any affected
facility, nor will the promulgated
standards require specific control
techniques. Rather, the standards set
emissions limits which have been
demonstrated to be achievable by the
use of the best control systems
considering costs, energy impacts, and
nonair quality environmental impacts.
The standards do not preclude the use
of alternative control techniques, as long
as the emissions limits are achieved.
The selection of fabric filtration as the
best system of emission reduction for
grid casting and lead reclamation
facilities was criticized by a number of
commenters. These facilities are
normally uncontrolled or controlled by
impingement scrubbers at existing
plants. The commenters pointed out that
only one grid casting facility uHhe
United States is controlled by a fabric
filtration system and that this system
has been plagued by fires. They
explained that the surfaces of exhaust
ducts for grid casting and lead
reclamation operations become coated
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with hydrocarbons and other flammable
materials. For grid casting, these Include
bits of cork from the molds, oils used for
lubrication, and soot, which is often
used as a mold release agent. For lead
reclamation, .hydrocarbons from plastic
and other contaminants charged with
lead scrap become entrained in exhaust
gases and deposit on the walls of
exhaust ducts. These materials are
readily ignited by sparks which, the
commenters contended, are
unavoidable.
The commenters stated that fires
started in the exhaust ducts will
generally propagate to the control
system. One commenter indicated that
problems caused by such fires are not
generally severe for scrubbers, but fires
would cause serious damage and
emissions excursions if fabric filters
were used. The commenters stated that
spark arresters would not solve the fire
problem, because they too would
become coated with flammable
materials which would be ignited by
sparks.
Apart from the problem of fires,
commenters contended that
contaminants present in the exhaust
gases from grid casting and lead
reclamation would cause frequent bag
blinding if fabric filters were applied to
these facilities. In addition to the
materials listed above, sodium silicate,
which is often used as a mold release
agent for grid casting, was cited by the
commenters as an extremely
hygroscopic compound which would
cause bag blinding. Commenters also
felt that the EPA particle size and
emissions test data did not support the
contention made by EPA that a fabric
filter could achieve 99 percent emission
reduction for emissions from grid casting
and lead reclamation.
The standards for grid casting and
lead reclamation have been changed.
Based on the information available
when standards for lead-acid battery
manufacture were proposed, EPA had
concluded that fabric filtration could be
used to control emissions from grid
casting and lead reclamation, and that
99 percent collection efficiency could be
attained. The proposed standards for
grid casting and lead reclamation were
based on tests of uncontrolled emissions
from these facilities, and on fabric filter
efficiencies demonstrated for the three-
process operations facility and for other
industries with emissions of similar
character to those from lead-acid
battery manufacture. The problem of
bag blinding can be avoided by keeping
the exhaust gases from these facilities at
temperatures above their dew points.
Also, it was thought that exhaust duct
fires could be prevented by the use of
spark arresters. In light of the point
made by commenters that spark
arresters would not prevent fires, EPA
has concluded that the standards for
grid casting and lead reclamation
facilities should not be based on fabric
filters.
The proposed emission limitations for
grid casting and lead reclamation might
be achieved using a high energy
scrubber such as a venturi; however,
because of the particle size of emissions
from these facilities, a scrubber pressure
drop of about 7.5 kPa (30 in. W.G.)
would be required. The energy
requirement to overcome this pressure
drop is not considered reasonable for
these facilities. The emissions limits for
paste mixing, three-process operation,
and other lead-emitting facilities are
based on the application of fabric filters
with average pressure drops of about
1.25 kPa (5 in. W.G.). Thus, the
electricity requirement per unit volume
of exhaust gas to operate venturi
scrubbers for the grid casting and lead
reclamation facilities would be roughly
six times the electricity requirement per
unit volume to control other plant
exhausts. It is estimated that standards
based on the application of impingement
scrubbers rather than venturi scrubbers
to grid casting and lead reclamation
facilities will result in a 50 percent
decrease in the total electricity
necessary to comply with the NSPS
while having only a slight effect on the
emissions reduction attributable to the
NSPS (from 97 percent reduction to 96.7
percent reduction from a typical new
plant).
The Administrator has therefore
determined that for the lead-acid battery
manufacturing industry, impingement
scrubbers operating at a pressure drop
of about 1.25 kPa (5 in. W.G.) represent
the best system of emission reduction
considering costs, nonair quality health
and environmental impact and energy
requirements for grid casting and lead
reclamation. Therefore, in the
promulgated standards, the emissions
limitations for grid casting and lead
reclamation have been raised to levels
which have been shown to be
achievable in tests of impingement
scrubbers controlling these facilities.
This change represents a change from
the regulatory alternative chosen for the
proposed standards. The environmental,
economic, and energy impacts of the
alternative which has been chosen for
the promulgated standards are
discussed in both Volumes I and II of
the BID.
EPA measured lead emissions from
two grid casting facilities. One of these
facilities was uncontrolled, and the
other was controlled by an impingement
scrubber. Average uncontrolled and
controlled lead emissions from the
scrubber controlled facility were 2.65
mg/dscm (11.6 x 10'4gr/dscf) and 0.32
mg/dscm (1.4 X 10~4gr/dscf).
respectively. The promulgated standard
for grid casting, 0.4 mg/dscm (1.76 x
KT4gr/dscf). is based on the controlled
lead emission rate for this facility. The
facility is considered typical of grid
casting facilities used in the lead-acid
battery manufacturing industry. EPA is
not aware of any process variations
which would result in a significant
increase in the emission concentration
achievable using a scrubber control
system. The Agency has set the
promulgated lead emission limit above
the level achieved in the EPA test to
allow solely for variations caused by
factors that the Agency cannot Identify
at this time.
Lead reclamation emissions were
measured by EPA for a facility
controlled by an impingement scrubber.
Average lead concentrations in the inlet
and outlet streams from the scrubber
were 227 mg/dscm (990 X 10"*gr/dscf)
and 3.7 mg/dscm (16 X 10'4gr/dscf).
The standard for lead reclamation, 4.5
mg/dscm (19.8 X 10~4gr/dscf), is based
on the controlled emission rate
measured for this facility. This facility is
considered typical of lead reclamation
facilities used in the lead-acid battery
manufacturing industry. EPA is not
aware of any process variations which
would result in a significant increase in
the emission concentration achievable
using a scrubber control system. The
Agency has set the promulgated lead
emission limit above the level achieved
in the EPA test to allow solely for
variations caused by factors that the
Agency cannot identify at this time.
Several commenters criticized the
choice of fabric filtration as the best
system of emission reduction for the
entire paste mixing cycle. The paste
mixing operation is a batch operation
consisting of two phases: charging and
mixing. The paste mixing facility is
generally controlled by impingement
scrubbing, although fabric filtration is
often used to control exhaust from the
charging phase. The commenters felt
that if fabric filtration were to be used
for the entire cycle, the moisture present
in the exhaust during the mixing phase
would cause bag blinding. Therefore.
they requested that the emission limit'
for paste mixing be raised to a level
achievable using impingement
scrubbers.
If fabric filters are used to meet the
emission limit bag bunding can be
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1962 / Rules and Regulations
prevented by keeping paste mixer
exhausts at temperatures above their
dew points. The energy which would be
required, to heat the exhaust gases and
the costs for providing insulation for
•ducts and fabric niters applied to paste
mixing facilities were taken into
consideration in the energy and
economic analyses for the new source
performance standards. These costs and
energy requirements are considered
reasonable. In addition, data submitted
by one commenter show that the
standard for paste mixing is achievable
using impingement scrubbers. Tests
were conducted of emissions from two
scrubber controlled paste mixing
facilities, using methods similar to
Method 12. These tests indicated
average controlled lead emissions of
0.04 mg/dscm (1.09 X 10"4 gr/dscf) and
0.07 mg/dscm (0.30 X 10~4gr/dscf) for
the two facilities. Both of these average
concentrations are well below the 1 mg/
dscm (4.4 x 10"4 gr/dscf) standard for
paste mixing.
Some commenters contended that
EPA test data did not adequately
support the statement that 99 percent
collection efficiency could be achieved
for paste mixing emissions using fabric
filter filtration. The commenters stated
that fabric cleaning periods should be
included in the calculation of fabric
filter efficiency.
The standard for paste mixing is
considered achievable. Emissions from a
paste mixing facility were tested by
EPA. The average uncontrolled lead
concentration from this facility was 77.4
mg/dscm (338xlO-4gr/dscf). Thus, the
promulgated regulation is expected to
require about 98.7 percent control of
lead emissions from paste mixing. EPA
tests of a fabric filtration system
controlling a three-process operation
showed an average lead collection
efficiency of 99.3 percent. This fabric
filtration system underwent bag
cleaning during testing. EPA tests and
statements made by several commenters
indicate that the particle size
distribution for paste mixing emissions
is similar to that for three-process
operation emissions. Emissions from
paste mixing arr made up of lead oxide
agglomerates, while emissions from
three-process operation facilities are
made up mainly of agglomerates > ith
some other large particles and sr IB
fumes. Because of the absence . ' imes
in paste mixing emissions, em-'sf i
reductions greater than those
demonstrated for the three-pro J.-JB
operation facility may be achievable for
paste mixing facilities. The above data
show that efficiencies greater than 98.7
percent can be achieved for paste
mixing emissions.
In addition. EPA tests of a controlled
paste mixing facility indicate that the 1
mg/dscm standard for paste mixing is
achievable. As noted earlier, paste
mixing is a batch process which can be
divided into a charging phase and a
mixing phase. Emission concentrations
are highest during the charging phase.
EPA conducted tests of a facility 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 charging
phase (the first 14 to 16 minutes of a
cycle) exhaust from the paste mixer was
ducted to a fabric filter which also
controlled emissions from the grid
slitting (separating) operation. During
the mixing phase (the remainder of the
cycle), 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/
dscm (5.5xlO'4gr/dscf). The average
lead content of exhaust from the
scrubber used to control mixing
emissions was 0.25 mg/dscm (1.1 X10~4
gr/dscf). The minimum time specified in
the standard for a test run, 60 minutes
(S 60.374(b)), exceeds the duration of a
mixing cycle. Thus, the emission
concentration used to determine
compliance with the paste mixing
standard would be the average of the
emission concentrations from charging
and mixing. The average lead
concentration in controlled emissions
from the facility discussed above was
about 0.9S mg/dscm (4.2X10~4 gr/dscf)
which is slightly below the proposed
emission limit of 1 mg/dscm (4.4X10"'
gr/dscf). A lower average emission
concentration could be achieved by
using fabric filtration, generally a more
efficient control technique than
impingement scrubbing, to control
emissions from all phases of paste
mixing.
Also, as noted earlier, one commenter
submitted data showing that the
standard for paste mixing is achievable
using impingement scrubbing to control
emissions from the entire cycle.
Several commenters criticized the fact
that the standard for lead oxide
production is based on tests conducted
at a ball mill lead oxide production
facility, but will apply to Barton lead
oxide production facilities as well as
ball mill facilities. Some commenters
stated that the particle size of the oxide
to be collected depends on the type of
lead oxide produced. One commenter
stated that Barton facilities are more
commonly used to produce lead oxide
than ball mill facilities.
In both the ball mill process and the
Barton process, all of the lead oxide
product must be removed from an air
stream. In the ball mill process, 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 are then oxidized by the air
around them.
EPA tests on a Barton process
indicated that Barton and ball mill
processes have similar air flow rates per
unit production rate. Because these air
streams carry all of the lead oxide
produced, the concentrations of lead
oxide in the two streams must also be
similar. Data submitted by one
commenter indicate that the percentage
of fine particles in lead oxide produced
by the Barton process is similar to the
percentage of fine particles in lead oxide
produced by the ball mill process. The
similarities between the concentrations
and particle size distributions of the
oxide bearing air streams in the Barton
and ball mill processes support EPA's
contention that a similar level of
emission control could be achieved for a
Barton process as has been
demonstrated for the ball mill process. It
should be noted that the Agency has set
the promulgated lead emission limit
above the level achieved in the EPA test
to allow solely for variations caused by
factors that the Agency cannot identify
at this time.
Some commenters felt that the
standard for lead oxide production was
too stringent. One commenter stated
that the emission rate calculated for a
lead-oxide production facility controlled
by a cyclone and a fabric filter in series
is higher than the standard for lead
oxide production.
The emission limit for lead oxide
production of 5 milligrams of lead per
kilogram of lead processed is considered
achievable. The limit is based on the
results of a test of emissions from a ball
mill lead oxide production facility with a
fabric filter control system, which
showed an average controlled emission
rate of 4.2 mg/kg (8.4 Ib/ton) for this
facility. The comments on the lead oxide
standard were based on calculation and
not on emission testing. No reason was
given why the calculations might be
more reliable than the EPAjest data or
why the EPA test might "
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representative of the emission level
achievable for a well controlled lead
oxide production facility.
Several commenters stated that the
emission limit for the three-process
operation was not supported by the BID
for the proposed standards. However,
one commenter stated that the emission
limit appears achievable.
The limit for the three-process
operation is based on the results of EPA
tests conducted at four plants where
fabric filtration was used to control
three-process operation emissions. Each
of the sets of tests conducted by EPA
showed average controlled lead
concentrations below the promulgated
limit. The limit was set above the levels
shown to be achievable in the four EPA
tests to allow solely for variations
caused by factors that the agency
cannot identify at this time. Therefore,
the lead emission limit for the three-
process operation facility is considered
achievable.
Economic Impact
One commenter contended that new
source performance standards would
impose a substantial and burdensome
cost on the lead-acid battery
manufacturing industry. Another stated
that battery sales have fallen by 25
percent in recent years.
The economic impacts of new source
performance standards on the lead-acid
battery manufacturing industry are
analyzed and described in detail in
Volumes I and II of the BIO. These
impacts are summarized in the section
of this preamble entitled "SUMMARY
OF ENVIRONMENTAL. ENERGY, AND
ECONOMIC IMPACTS." The projected
economic impacts are considered
reasonable. The expected annualized
cost of compliance with the promulgated
standards at a typical affected plant is
expected to be about 1.6 percent of the
wholesale price of a battery; and the
economic impact analysis indicates that
this cost could be passed on with little
effect on sales.
The promulgated standards are new
source performance standards and will
only affect new, modified, and
reconstructed facilities. Existing
facilities are not covered by the
standards. The 25 percent drop in sales
cited by the second commenter results
from the recent decline in the production
of domestic automobiles. The low sales,
if they continue, would reduce growth in
the production capacity of the industry.
Hence, the number of new, modified,
and reconstructed facilities would be
reduced. Since the standards will affect
only these facilities, the low sales
should not increase the economic impact
of the standards on the industry as a
whole or on individual plants.
Several commenters contended that
the cost of compliance with OSHA
standards was not adequately
addressed in Volume I of the BID. The
commenters also felt that the OSHA
standards would require higher
ventilation rates than are currently
needed, and would thus cause the costs
of compliance with new source
performance standards to be higher than
the estimates made by EPA.
The OSHA compliance costs
presented in Volume I are based on the
capital and operating cost of controls
which were expected to be required to
meet the employee exposure standards
of 200 ;ig/m' originally proposed by
OSHA in 1975. The controls include
employee care, general plant
maintenance, and local ventilation of in-
plant lead emission sources. On
November 14,1978, OSHA promulgated
an employee exposure standard of 50
/ig/ms. However, the controls necessary
to comply with this standard are
expected to be similar to those which
would have been necessary for the
originally proposed 200 fig/m* standard.
In addition, the economic impact
projected for the OSHA standards in
Volume I may be higher than the actual
economic impact because, in a number
of cases, work practices may be used to
achieve the OSHA standard in place of
technological controls.
In volume I of the BID, the statement
is made that a change in the OSHA
standards could cause the control costs
for the new source performance
standards to increase substantially.
However, in light of data obtained in
recent investigations and discussed in
Volume n of the BED, it is not expected
that the change in OSHA standards will
have a significant effect on the results of
the economic impact analysis for the
NSPS. The facility exhaust rates used to
project the economic impacts of the
NSPS were not based on the exhaust
rates of facilities tested by EPA but
were set at levels which would provide
good ventilation for the facilities under
consideration. These exhaust rates are
higher than those which were used at
typical lead-acid battery plants before
the change in the OSHA standard, and
are thought to be sufficient for
compliance with the 50 pg/m'OSHA
standard.
Environmental Impact
A number of commenters contended
that, because lead-acid battery
manufacturer accounts for a small
percentage of total nationwide lead
emissions, new source performance
standards should not be set for this
source category. One commenter cited
data which indicate that lead emissions
from lead-acid battery manufacturer
accounted for only about 0.32 percent of
industrial lead emissions or about 0.014
percent of total nationwide lead
emissions in 1975.
It is acknowledged that lead-acid
battery plants account for a relatively
small share of total nationwide
atmospheric lead emissions. In 1975,
about 95 percent of U.S. lead emissions
resulted from the production of alkyl
lead gasoline additive, the burning of
leaded gasoline, and the disposal of
crankcase oil from vehicles which burn
leaded gasoline. These emissions will be
reduced substantially as the use of alkyl
lead gasoline additives is curtailed.
Another 1 percent of nationwide lead
emissions is from mining and smelting
operations, which are generally located
in remote areas. However, lead-acid
battery plants are generally located in
urban areas, near the markets for their
batteries. Ambient lead levels are
already high in many of these places,
often exceeding the NAAQS for lead. In
light of the dangerous levels of lead in
the ambient air surrounding many of the
projected sites for new, modified, and
reconstructed facilities, the Agency
believes that additional emissions from
lead-add battery manufacture are
significant As a result, lead emissions
from aggregated lead-acid battery
manufacture, though smaller than
emissions from some of the other
sources, do contribute significantly to
air pollution which may reasonably be
anticipated to endanger public health or
welfare. Therefore, the Administrator
considers the development of new
source performance standards for this
industry to be justified.
Several commenters recommended
that the grid casting facility be removed
from the list of affected facilities.
According to EPA estimates, grid casting
accounts for about 3.2 percent of overall
uncontrolled battery plant lead
emissions. The commenters stated that
it is unreasonable to require sources to
control facilities generating such a small
percentage of total plant emissions.
Lead-acid battery plants are major
lead emitters, and EPA dispersion
calculations show that the ambient lead
standard could be exceeded in the area
around a plant which controls emissions
to the extent required to meet typical
SEP particulate regulations. Grid casting,
while accounting for only about 5
percent of emissions for a plant with
such controls, can be controlled with
lead reclamation by available
technology at a cost which is similar to
the cost of controlling larger sources in
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the plant. Of the 30$ per battery cost
impact of the standards for a typical
plant, approximately 44 per battery can
be attributed to grid casting control.
Therefore, grid casting emissions are
regulated under the promulgated
standards.
Legal Considerations
Several commenters stated that
because a national ambient air quality
standard for lead has been established.
new source performance standards
regulating lead emissions would be
redundant and unnecessary.
It should be noted that the purposes of
standards of performance for new
sources promulgated under Section 111
of the Clean Air Act differ from the
purposes of national ambient air quality
standards, which are promulgated under
Section 109 of the Act National ambient
air quality standards establish ambient
pollutant concentration target ceilings
which are to be attained and maintained
for the protection of the public health or
welfare.
New source performance standards
promulgated under Section 111 of the
Clean Air Act are not designed to
achieve any specific air quality levels.
Congress clearly intended that new
source performance standards regulate
Section 108 pollutants in addition to
other air pollutants, since a key purpose
of Section 111 is to establish nationally
applicable emission limits for new
sources, thus preventing any state from
attracting industry by adopting lenient
environmental standards. Congress
expressed a number of other reasons for
requiring the setting of new source
performance standards. Because the
national ambient air quality standards
create air quality ceilings which are not
to be exceeded, new source
performance standards enhance the
potential for long term growth. Also,
new source performance standards may
help achieve long-term cost savings by
avoiding the need for expensive
retrofitting when pollution ceilings may
be reduced in the future. Finally, the
standard-setting process should create
incentives for improved technology.
Therefore, because the purposes of
ambient air quality standards are
different from the purposes of new
source performance standards.
promulgation of an NSPS to control
emissions from lead-acid battery plants
of a pollutant for which there exists an
NAAQS is neither redundant nor
unnecessary.
Test Methods and Monitoring
Reference Method 12—A number of
commenters felt that Reference Method
12 was cumbersome and recommended
the development of a simpler screening
method. The commenters stated that a
battery plant may have as many as two
dozen stacks and that at an average
cost of $8000 per stack test the cost of
testing an entire plant could be
extremely high.
Because controlled emission levels for
most facilities are expected to be near
the emission limits for facilities affected
by the regulation, a screening method
less accurate than Method 12 would
generally not be suitable for determining
compliance with the lead-acid battery
manufacture regulation. The cost of
compliance testing using Method 12 was
discussed in the BID for the proposed
standards and is considered reasonable.
For plants where a number of stacks
must be tested, the per plant costs of
conducting performance tests using
Method 12 are not expected to be as
high as the commenters anticipated.
Although existing plants often have a
large number of stacks, it is expected
that for newly constructed, modified, or
reconstructed plants or facilities
emissions will be ducted to a small
number of stacks. The estimate of $6,000
per stack for a compliance test applies
only for plants where a small number of
stacks are to be tested. For plants with a
large number of stacks, the cost per
stack could decrease significantly. In
addition, the general provisions
applicable to all new source
performance standards allow for the use
of an alternative method where the
Administrator determines that the
results would be adequate for indicating
whether a specific source is in
compliance (40 CFR 60.8(b)).
One commenter recommended that
the minimum sampling time for Method
12 be extended. Another stated that the
minimum sampling time for grid casting
in the proposed regulation was too long.
For tests with Method 12. the
mimimum amount of lead needed for
good sample recovery and analysis is
100 ng. The mimimum sampling rates
and times insure that enough lead will
be collected. For grid casting, the
minimum sampling time has been
changed from 180 minutes, in the
proposed regulation, to 60 minutes, in
the promulgated action. The change
reflects the alteration in the standard for
grid casting.
Reference Method 9—Two
commenters expressed concern that
Method 9 is not accurate enough to be .
used to enforce a standard of 0 percent
opacity. One commenter stated that it is
difficult to discern the difference
between 0 percent opacity and 1 percent
opacity for a given reading.
No single reading is made to the
nearest percent; rather, readings are to
be recorded to the nearest 5 percent
opacity and averaged over a period of 6
minutes (24 readings). For this
regulation, the 6-minute average opacity
•figure is to be rounded to the nearest
whole number. The opacity standard for
lead-acid battery manufacture is based
on opacity data taken for operating
facilities.
Reporting and Recordkeeping
A number of commenters contended
that the proposed pressure drop
monitoring and recording requirement
for control systems would not serve to
insure proper operation and
maintenance of fabric niters. The
commenters pointed out that a leak in a
fabric filter would not result in a
measurable difference in the pressure
drop across the filter. One commenter
suggested that the pressure drop
monitoring requirement be replaced by
an opacity monitoring requirement. -
Another commenter suggested that the
pressure drop requirement be replaced
by a requirement of visible inspection of
bags for leaks.
Based on the arguments presented by
these commenters, it is agreed that
proposed pressure monitoring
requirement for fabric filters would not
serve its intended purpose. This
requirement has been eliminated.
However, pressure drop is considered to
be a good indicator of proper operation
and maintenance for scrubbers.
Therefore the pressure drop monitoring
and recording requirement for scrubbers
has been retained.
The pressure drop monitoring
requirement for fabric filters has not
been replaced by another monitoring
requirement. The cost of opacity
monitoring equipment may in some
cases be comparable to the cost of
emission control systems for lead-acid
battery manufacturing facilities. This
cost is considered unreasonable.
Although periodic visual inspection of
bags would provide an indication of bag
integrity, visual inspection records
would not be useful to the EPA in the
enforcement of the promulgated
standards.
A number of commenters stated that
while pressure drop monitoring is useful
for scrubbers, continuous recording of
pressure drop would be unnecessary
and expensive. Some commenters
questioned whether a device which
cyclically monitors the pressure drop
across several emission control systems
would be considered a continuous
recorder for the systems. These
commenters also asked how often such
a recorder would have to monitor the
pressure drop across a particular control
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device to be considered a continuous
recorder for that device. One commenter
suggested the substitution of periodic
manual recording of pressure drop for
the continuous pressure drop recording
requirement. Another commenter
questioned the purpose of requiring
pressure drop monitoring and recording
without a requirement that action be
taken at certain pressure drop levels.
The purpose of pressure drop
recording requirements is to allow the
verification by EPA that emission
control systems are properly operated
and maintained. The costs of pressure
drop recording devices were analyzed
and are considered reasonable. The sort
of device that would satisfy the
recording requirement has been clarified
in the promulgated standards. It has
been determined that for the purposes of
these standards a device which records
pressure drop at least every 15 minutes
would accomplish the same purposes as
a continuous pressure drop recorder.
Manual pressure drop recording would
not insure proper operation and
maintenance of a control system.
Other Considerations
A number of commenters
recommended that the definition of the
paste mixing facility be expanded to
include operations ancillary to paste
mixing, such as lead oxide storage,
conveying, weighing, and metering
operations; paste handling and cooling
operations; and plate pasting, takeoff,
cooling, and drying operations. The
commenters stated that paste mixing
and operations ancillary to the paste
mixing operation are generally
interdependent, in that one operation is
not run without the others. Also,
emissions from paste mixing and
ancillary operations are often ducted to
the same control device. The
commenters were concerned that a
minor change made to a paste mixing
machine could cause the machine to be
affected by the promulgated standards
under the reconstruction provisions
applicable to all new source
performance standards. They stated that
the recommended change would avoid
this possibility.
These comments are considered
reasonable. The operations ancillary to
paste mixing were not intended to be
considered separate facilities; and the
definition recommended by the
commenters for the paste mixing facility
is considered an appropriate definition.
Therefore, the recommendation of the
commenters has been adopted in the
promulgated regulation. Because the
emission limit which was proposed for
paste mixing is identical to that which
was proposed for operations ancillary to
paste mixing ("other lead-emitting
operations"), this change is not expected
to affect the environmental impacts of
the standards.
Docket
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this 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 standards and EPA
responses to significant comments, the
contents of the docket will serve as the
record in case of judicial review
(Section 307(d)(7)(A)).
Miscellaneous
The effective date of this regulation is
April 16,1982. Section 111 of the Clean
Air Act provides that standards of
performance or revisions thereof
become effective upon promulgation and
apply to affected facilities, construction
or modification of which was
commenced after the date of proposal
(January 14.1080).
As prescribed by Section 111, the
promulgation of these standards was
preceded by the Administrator's
determination (40 CFR 60.18,44 FR
49222, August 21,1979) that these
sources contribute significantly to air
pollution which may reasonably be
anticipated to endanger public health or
welfare and by proposal of the
standards on January 14,1980 (45 FR
2790). In accordance with Section 117 of
the Act, publication of these
promulgated standards 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, 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 aa 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
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 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 (Sec. 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 189(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 any event, 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
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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 as
required by the Clean Air Act. This
review wiU include an assessment of
•uch factors as the need for integration
with other programs, the existence of
alternative methods, enforceability,
improvements in emission control
technology, and reporting requirements.
The reporting requirements in the
regulation will be reviewed as required
under EPA's sunset policy for reporting
requirements in regulations.
Under Executive Order 12291, EPA
must judge whether a regulation is
"Major" and therefore subject to the
requirement of a Regulatory Impact
Analysis. This regulation is not Major
because: (1) The national annualized
compliance costs, including capital
charges resulting from the standards
total less than $100 million; (2) the
standards do not cause a major increase
in prices or produr'.ion costs; and (3) the
standards do not ct-use significant
adverse effects on domestic competition,
employment, investment, productivity,
innovation or competition in foreign
markets. This regulation was submitted
to the Office of Management and Budget
(OMB) for review as required by
Executive Order 12291.
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 promulgated
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the promulgated
standards to insure that the standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment in
included in the background information
document.
List of Subjects in 40 CFR Part 60
Air pollution control, Aluminum,
Ammonium sulfate plants. Cement
industry, Coal, Copper, Electric power-
plants, Glass and glass products. Grains,
Intergovernmental relations, Iron. Lead,
Metals. Motor vehicles, Nitric add
plants. Paper and paper products
industry, Petroleum. Phosphate, Sewage
disposal, Steel, Sulfuric add plants.
Waste treatment and disposal Zinc.
Dated: April 9,1982.
Note.—The regulation does not involve •
"collection of information" u defined under
the Paperwork Reduction Act of 1980.
Therefore, the provisions of the Paperwork
Reduction Act applicable to collection* of
information do not apply to this regulation.
Anne M. Gonuch.
Administrator.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
40 CFR Part 60 is amended by adding
a new Subpart KK and by adding a new
reference method to Appendix A as
follows:
1. A new subpart is added as follows:
Subpart KK—Standards of
Performance for Lead-Add Battery
Manufacturing Plants
Sec.
00.370 Applicability and designation of
affected facility.
80.371 Definitions.
80.372 Standards for lead.
80.373 Monitoring of emissions and
operations.
80.374 Test methods and procedures.
Authority: Sec. 111. 3Ol(a) •* the 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-Add 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 produces or has the design capacity
to produce in one day (24 hours)
batteries containing an amount of lead
equal to or greater than 5.9 Mg (6.5 tons).
(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.
(c) Any facility under paragraph (b) of
this section the construction or
modification of which is commenced
after January 14,1980, is subject to the
requirements of this subpart.
$60.371 Deflnittona.
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 all lead melting
pots and machines used for casting the
grid used in battery manufacturing.
(b) "Lead-acid 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 a 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" means the
facility including lead oxide storage,
conveying, weighing, metering, and
charging operations; paste blending,
handling, and cooling operations; and
plate pasting, takeoff, cooling, and
drying operations.
(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 toad.
(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 0.40
milligram of lead per dry standard cubic
meter of exhaust (0.000176 gr/dscf).
(2) From any paste mixing facility any
gases that contain in excess of 1.00
milligram 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
V-535
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1982 / Rules and Regulations
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 4.50
milligrams of lead per dry standard
cubic meter of exhaust (0.00198 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 other
than a lead reclamation facility any
gases with greater than 0 percent
opacity (measured according to Method
9 and rounded to the nearest whole
percentage).
(8) From any lead reclamation facility
any gases with greater than 5 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, an equivalent
standard for the total exhaust from the
commonly controlled facilities shall be
deter ained as follows:
S.=
N
a=l
§60.374 T«tt method* and procedure.
(a) Reference methods in Appendix A
of this part, except as provided under
§ 60.8(b), shall be used to determine
compliance according to f 60.8 as
follows: °
(1) Method 12 for the measurement of
lead concentrations,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and
volumetric flow rate, and
(4) Method 4 for stack gas moisture.
(b) For Method 12, the sampling time
for each run shall be at least 60 minutes
and the sampling rate shall be at least
0.85 dscm/h (0.53 dscf/min), except that
shorter sampling nines, when
necessitated by process variables) or
other factors, may be approved by the
Administrator.
(c) When different operations in a
three-process operation facility are
ducted to separate control devices, the
lead emission concentration from the
facility shall be determined using the
equation:
Where:
S» = is the equivalent standard for the total
exhaust stream.
S.=is the actuall standard for each exhaust
stream ducted to the control device.
N=is the total number of exhaust streams
ducted to the control device.
Q«,='8 the dry standard volumetric flow
rate of the effluent gas stream from each
facility ducted to the control device.
QvtT = is the total dry standard volumetric
flow rate of all effluent gas streams
ducted to the control device.
§60.373 Monitoring of •mission* and
operation*).
The owner or operator of any lead-
acid battery manufacturing facility
subject to the provisions of this subpart
and controlled by a scrubbing system(s)
shall install, calibrate, maintain, and
operate a monitoring device(s) that
measures and records the pressure drop
across the scrubbing system(s) at least
once every 15 minutes. The monitoring
device shall have an accuracy of ±5
percent over its operating range.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
a=l
Where:
Cn^is the facility emission concentration
for the entire facility.
N=is the number of control devices to which
separate operation* In the facility are
ducted.
Cn,a=is the emission concentration from
each control device.
QM>=i8 the dry standards volumetric flow
rate of the effluent gas stream from each
control device.
0,4, = is the total dry standard volumetric
flow rate from all of the control devices.
(d) 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.
(e) Lead emissions from lead oxide
manufacturing facilities, expressed in
milligrams per kilogram of lead charged,
shall be determined using the following
equation:
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.
Qrt=is the dry standard volumetric flow rate
in dry standard cubic meters per hour as
determined according to paragraph (a)(3)
of mil section.
F=is the lead feed rate to the facility in
kilograms per hour as determined
according to paragraph (d) of this
section.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
2. Appendix A to Part 60 la amended
by adding new Reference Method 12 as
follows:
Appendix A—Reference Methods
Method 12. Determination of Inoiganic Lead
Emissions From Stationary Source*
1. Applicability and Principle.
1.1 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 isoklnetically from
the source and collected 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 Range. For a minimum analytical
accuracy of ±10 percent the lower limit of
the range i* 100 fig. 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 6.2
and 0.5 pig 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 (US percent
relative to a run-mean concentration. These
values were based on test* conducted at a
gray Iron foundry, a lead storage battery
manufacturing plant a secondary lead
smelter, and a lead recovery furnace of an
alkyl lead manufacturing plant. The
concentrations encountered during these
tests ranged from 0.61 to 123.3 mg Pb/m1.
2.4 Interferences. Sample matrix effects
may interfere with the analyst* for Pb by
flame atomic absorption. If this interference
is suspected, the analyst may confirm the
presence of these matrix effect* and
frequently eliminate the interference by using
the Method of Standard Additions.
High concentration* of copper may
interfere with the analysis of Pb at 217.0 nm.
This interference can be avoided by
analyzing the samples at 283.3 nm.
3. Apparatus.
3.1 Sampling Train. A schematic of the
sampling train is shown in Figure 12-1; it is
similar to the Method 5 train. The sampling
train consists of the following components:
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1982 / Rules and Regulations
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 S.
Sections 2.1.1 to 2.1.6 and 2.1.8 to 2.1.10.
. respectively.
3.1.2 Impingers. Four impingers connected
in series with leak-free ground glass fittings
or any similar leak-free noncontaminaling
fittings. For the first, third, and fourth
impingers, use the Greenburg-Smith design.
modified by replacing the tip with a 1.3 cm
(V> in.) ID glass tube extending to about 1.3
cm (V> 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.
MLUNO COOt «MO-fO-M
V-537
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en
TEMPERATURE SENSOR
_ PROBE
TEMPERATURE
SENSOR
HEATED AREA THERMOMETER
THERMOMETER
PITOT TUBE
PROBE
REVERSE-TYPE
PITOT TUBE
PITOT MANOMETER
ORIFICE
VACUUM
GAUGE
THERMOMETERS
MAIN VALVE
DRY GAS METER
AIRTIGHT
PUMP
Figure 12-1. Inorganic lead sampling train.
CHECK
VALVE
VACUUM
LINE
I
A
S.
50
z
o
D.
BJ
09
a
BILLINO CODE «S60-5(X
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Federal Register / Vol. 47. No. 74 / Friday. April 16, 1982 / Rules and Regulations
3.2 Sample Recovery. The following item
are needed:
3.2.1 Probe-Liner and Probe-Nozzle
Brushes, Petri Duties. Plastic Storage
Containers, and Funnel and Rubber
Policeman. Same as Method 5, Sections 2.2.1.
i2.4. z.E.6, and t2.7, respectively.
3.2.2 Wash Bottles, daw (2).
3.2.3 Sample Storage Container*.
Chemically resistant borosilicate glass
bottles, for 0.1 nitric acid (HNO,) impinger
and probe solutions and washes, lOOO-ml.
Use screw-cap liners that are either rubber-
backed Teflon* or leak-free and resistant to
chemical attack by 0.1 N HNCv (Narrow
mouth glass bottles have been farad 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 •
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.)
8.2.5 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. 125-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.
3J.6 Volumetric Flasks. 100-ml. 2SO-mL
andlOOO-mL
4. Reagents.
4.1 Sampling. The reagents used in
sampling are as follows:
4.1.1 Filter. Celman Spectro Grade. Reeve
Angel 934 AH. MSA 1106 BH, all with lot
assay forPb, or other high-purity glass fiber
filters, without organic'binder, exhibiting at
least 99.95 percent efficiency (
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1982 / Rules and Regulations
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 0.1 N
HNOi 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 protected from contamination.
After insuring that all joints are wiped
clean of silicone grease, brush and rinse with
0.1 N HNO, the inside of the front half of the
filter holder. Brush and rinse each suface
three times or more, if needed, to remove
visible sample matter. Make a final rinse of
the brush and filter holder. After all 0.1 N
HNO, washings end sample matter 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 Gel). 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 runnel 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
testt,.- may place the impinger solutions in
several containers. Clean each of the first
three impingers and connecting glassware In
the following manner
1. Wipe the impinger ball joints free of
silicone grease and cap the joints.
2. Rotate and agitate each impinger, so that
the impinger contents might serve as a rinse
solution.
3. Transfer the contents of the Impingers to
a 500-ml graduated cylinder. Remove the
outlet 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: hi steps 5 and 6 below, measure
and record the total amount of 0.1 N HNO,
used for rinsing. Pour approximately 30 ml of
0.1 N HNO, into each of the first three
impingers and agitate the impingers. Drain
the 0.1 N HNO, through the outlet arm of
each Impinger into Container No. 4. Repeat
this operation • second time; inspect the
impingers for any abnormal conditions.
6. Wipe the ball joints of the glassware
connecting the impingers free of silicone
grease and rinse each piece of glassware
twice with 0.1 N HNO,; transfer this rinse
into Container No. 4. (Do not rinse or brush
the glass-fritted filter support] Mark the
height of the fluid level to determine whether
leakage occur* during transport Label the
container to clearly identify its contents.
5.2.5 Blanks. Save 200 ml of the 0.1 N
HNO, used for sampling and cleanup a* a
blank. Take the solution directly from the
bottle being used and place into a glass
sample container labeled "0.1 N HNO,
blank."
5.3 Sample Preparation.
5.3.1 Container No. 1 (Filter). Cut the filter
into strips and transfer the strips and all
loose participate matter into a 125-ml
Erlenmeyer flask. Rinse the petri dish with 10
ml of 50 percent HNO, to insure a
quantitative transfer and add to the flask.
(Note: If the total volume required In Section
5.3.3 is expected to exceed 80 ml, use a 250-ml
Erlenmeyer flask in place of the 125-ml flask.)
5.3.2 Containers No. 2 and No. 4 (Probe
and Impingers). (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 bad
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 No. 4 and take to dryness on a hot plate.
5.3.3 Sample Extraction for lead. Based on
the approximate stack gas particulate
concentration and the total volume of stack
gas sampled, estimate the total weight of
particulate sample collected. Then transfer
the residue from Containers No. 2 and No. 4
to the 125-ml Erlenmeyer flask that contains
the filter using rubber policeman and 10 ml of
50 percent HNO, for every 100 mg of sample
collected in the train or a minimum of 30 ml
of 50 percent HNO, whichever is larger.
Place the Erlenmeyer flask on a hot plate
and beat with periodic stirring for 30 min at a
temperature just below boiling. If the sample
volume falls below 15 ml, add more 50
percent HNO,. Add 10 ml of 3 percent H,O,
and continue heating for 10 min. Add 50 ml of
hot (80'C) deionized distilled water and heat
for 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 with
deionized distilled water.
5.3.4 Filter Blank. Determine a filter blank
using two filters from each lot of filters used
in the sampling train. Cut each filter into
strips and place each filter in a separate 125-
ml Erlenmeyer flask. Add 15 ml of 50 percent
HNO, and treat as described in Section 5.3.3
using 10 ml of 3 percent H,O, and 50 ml of
hot, deionized distilled water. Filter and
dilute to a toal volume of 100 ml using
deionized distilled water.
5.3.5 0.1 N HNO, Blank. Take the entire
200 ml of 0.1 N HNO, to dryness on a steam
bath, add 15 ml of SO percent HNO,, and treat
as described in Section 5.3.3 using 10 ml of 3
percent H,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
spectrophotometer as described in Section 62
and determine the absorbance for each
source sample, the filter blank, and 0.1 N
HNO, blank. Analyze each sample three
times in this manner. Make appropriate
dilutions, as required, to bring all sample Pb
concentration* 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 bring 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
compositon 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 matrices will be encountered. Thus,
check (mandatory) at least one sample from
each source 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 must reanalyze all samples
from the source using the Method of
Additions procedure.
5.4.3 Container No. 3 (Silica Gel). The
tester may conduct this step in the field.
Weigh the spent silica gel (or silica gel plus
Impinger) to the nearest 0.5 g; record this
weight
6. Calibration.
Maintain a laboratory log of all
calibrations.
B.1 Sampling Train Calibration. Calibrate
the sampling train components according to
the indicated sections of 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 the Metering System
(Section 5.6); and Barometer (Section 5.7).
6.2 Spectrophotometer. Measure the
absorbance of the standard solutions using
the instrument settings recommended by the
spectrophotometer manufacturer. Repeat
until good agreement (±3 percent) is
obtained between two consecutive readings.
Plot the absorbance (y-axls) versus
concentration in >ig Pb/ml (x-axis). Draw or
compute a straight line through the linear
portion of the curve. Do not force the
calibration curve through zero, but if the
curve does not pass through the origin or at
least lie closer to the origin than ±0.003
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1982 / Rules and Regulations
•baotbance 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(Mt>. 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
V.(M4> 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 VB<.u>) and the
moisture content B., 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 HNO, blank. Use the
calibration curve and this corrected
absorbance to determine the |*g Pb
concentration in the sample aspirated into
the spectrophotometer. Calculate the total Pb
content C'n, (in fig) in the original source
sample; correct for all the dilutions that were
made to bring the Pb concentration of the
•ample into the linear range of the
spectrophotometer.
7.4 Lead Concentration. Calculate the
stack gas Pb concentration CT» In mg/dscm
as follows:
Where:
K =0.001 mg/fig for metric units.
=2.205 Ib/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 2-0 of
Method 2 and the data from this field test.
8. Alternative Test Methods for Inorganic
Lead
8.1 Simultaneous Determination of
Particulale and Lead Emissions. The tester
may use Method 5 to simultaneously
determine Pb provided that (1) he uses
acetone to remove paniculate from the probe
and inside of the filter holder as specified by
Method 5. (2) he uses 0.1 N HNO. in the
impingers. (3) he uses a glass fiber filter with
a low Pb background, and (4) 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.
i 8.3 In-slack 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 HNO,. after
the in-stack filter and (2) he recovers and
analyzes the probe and impinger contents for
Pb. Recover sample from the nozzle with
acetone if a particulate analysis is to be
made.
9. Bibliography
B.I 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. Hach. Standard
Additions—Uses and Limitations in
Spectrophotomciric Analysis. Amer. Lab.
ft21-27.1977.
9.4 Mitchell, W.J. and M.R. Midgett.
Determining Inorganic and Alkyl Lead
Emissions from Stationary Sources. U.S.
Environmental Protection Agency, Emission
Monitoring and Support Laboratory. Research
Triangle Park. N.C. (Presented at National
APCA Meeting. Houston. June 26,1978).
9.5 Same as Method 5, Citations 2 to 5
and 7 of Section 7.
* • • • •
(Sees. Ill, 114. and 301 (a) of the Clean Air
Act as amended (42 U.S.C. 7411. 7414. and
7801(a)))
|FR Doc. U-104m Filed 4-15-Si MS ami
MUJNOCOOC tWO-SO-M
V-541
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Federal Register / Vol. 47, No. 74 / Friday, April 16. 1982 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[AD-FRL 1782-1]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: Standards of performance for
phosphate rock plants were proposed in
the Federal Register on September 21,
1979 (44 FR 54970). This action finalizes
standards of performance for phosphate
rock plants. These standards implement
the Clean Air Act and are based on the
Administrator's determination that
emissions from phosphate rock plants
contribute significantly to air pollution
which may reasonably be anticipated to
endanger public health or welfare. The
intended effect of the standards is to
require the application of the best
demonstrated systems of continuous
emission reduction to new. modified, or
reconstructed phosphate rock dryers,
calciners, grinders, and ground rock
storage and handling systems at
phosphate rock plants. The designated
best demonstrated systems of
continuous emission reduction were
determined considering costa and nonair
quality health and environmental and
energy impacts.
EFFECTIVE DATE: April 16,1982.
Judicial Review: Under Section
307(b)(l) of the Clean Air Act judicial
review of this new source performance
standard is available only by the filing
of a petition for review in the United
States Court of Appeals for the District
of Columbia Circuit within 60 days of
today's publication of this rule. Under
Section 307(b)(2) of the Clean Air Act,
the requirements that are the subject of
today's notice may not be challenged
later in civil or criminal proceedings
brought by EPA to enforce these
requirements.
ADDRESSES: Background Information
Document. The background information
documents for the proposed and final
standards are available on request from
the U.S. EPA Library (MD-35), Research
Triangle Park, North Carolina 27711,
telephone number (919) 541-2777 or
(FTS) 629-2777 or (FTS) 629-2777. Please
refer to "Phosphate Rock Plants,
Background Information for Proposed
Standards, Volume I" (EPA-450/3-79-
017) and/or "Phosphate Rock Plants,
Background Information for
Promulgated Standards, Volume II"
(EPA-450/3-79-017b).
Docket. Docket No. OAQPS-79-6,
containing all supporting information
used by EPA in developing the
standards, is available for inspection
and copying during normal business
hours Monday through Friday at EPA's
Central Docket Section, West Tower
Lobby, Gallery 1, Waterside Mall, 401 M
Street SW., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
John D. Crenshaw, Emission Standards
and Engineering Division (MD-13). U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711. telephone number (919) 541-5624
or (FTS) 629-5624.
SUPPLEMENTARY INFORMATION:
Background
Standards of performance for new,
reconstructed or modified phosphate
rock plants were proposed on
September 21,1979. The proposed
standards would have limited
particulate emissions to 0.02 kilogram
(kg) per megagram (Mg) of feed rock
(0.04 Ib/ton) from dryers, 0.055 kg/Mg
(0.11 Ib/ton) from calciners and 0.006
kg/Mg (0.012 Ib/ton) from grinders. ,
Visible emission limits for these affected
facilities were proposed at zero percent
opacity. A zero percent opacity limit
was also proposed for ground rock
handling and storage systems.
During the public comment period, a
total of 16 comment letters were
received. Several commenters
questioned the proposed emission limits.
They argued that the particulate and
opacity limits for both dryers and
calciners were too stringent. After •
reviewing these comments, EPA
concluded that the data base supporting
the proposed standards was incomplete
because it was not representative of all
combinations of control conditions that
are likely to recur. EPA requested and
received emission source test data from
both the industrial commenters and
several State air pollution control
agencies. Based on this additional data,
several changes were made to the
proposed standards. The most
significant changes were a relaxation of
the particulate emission limits for
calciners processing unbeneficiated rock
and for dryers. The opacity limits for
both dryers and calciners were also
revised.
Other changes were to exclude from
the standards facilities with a
production capacity less than 3.6 Mg/hr
(4.0 ton/hr) and to exempt ground rock
storage and handling systems from the
continuous monitoring requirements.
Several wording and definition changes
were made to clarify the applicability of
the promulgated standards.
Standards of Performance
The promulgated standards apply to
new, modified, or reconstructed
phosphate rock dryers, calciners,
grinders, and ground rock handling and
storage facilities at phosphate rock
plants with a maximum production rate
greater than 3.6 megagrams of rock per
hour (4 tons/hr). The promulgated
standards will limit emissions of
particulate matter to 0.03 kilogram (kg)
per megagram (Mg) of rock feed (0.06 lb/
ton) from phosphate rock dryers, 0.12
kg/Mg (0.23 Ib/ton) from phosphate rock
calciners processing unbeneficiated rock
or blends of beneficiated and
unbeneficiated rock, 0.055 kg/Mg (0.11
Ib/ton) from phosphate rock calciners
processing beneficiated rock, and 0.006
kg/Mg (0.012 Ib/ton) from phosphate
rock grinders. Opacity levels from
grinders and ground rock storage and
handling systems are limited to zero
percent. Opacity levels from dryers and
calciners are limited to no more than 10
percent.
The emission limits are based on the
performance of baghouses or high
energy venturi scrubbers. Electrostatic
precipitators (ESP) are also capable of
meeting the standards. However,
because of the higher cost of ESP control
on phosphate rock applications, ESP's
were not designated as a basis for the
standard.
Compliance with the mass emission
limits is to be determined by source test
(EPA Method 5). Continuous monitoring
equipment will be required for dryers,
calciners, and grinders. However, when
scrubbers are used for emission control,
continuous opacity monitors would not
be required. Instead, the pressure drop
of the scrubber and the liquid supply
pressure will be monitored as indicators
of the scrubber performance.
Environmental, Energy, and Economic
Impacts
The promulgated standards would
reduce particulate emissions from
phosphate rock plants by about 99
percent from the levels that would occur
with no emission control, and by about
91 percent from the levels allowed by
typical State standards. These
reductions would reduce nationwide
particulate emissions allowed by State
Implementation Plan (SIP) regulations
by about 14,100 Mg (15,600 tons) per
year in 1985. However, the level of
control existing on many affected
sources is already more stringent than
that required by SIP regulations. For
example, many existing grinder facilities
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1982 / Rules and Regulations
are controlled by baghouses to prevent
the loss of valuable product rock. As a
result, the actual emission reduction
resulting from implementation of the
standard will be less than 14.100 Mg
(15,600 tons). The standards will cause a
reduction in participate matter
emissions from the level which would
occur with typical existing industry
control practices of about 3,300
megagrams (3,600 tons) in 1985 and 5,100
megagrams (5,600 tons) in 1990.
None of the alternative control
technologies required by these
standards (baghouse, scrubber) would
result in significant adverse
environmental impacts. If scrubbers are
used to meet the requirements of the
standard, there would be a small
increase in solid waste disposal and
water pollution. However, the
incremental increase (over the
prevailing controls) of solid materials
and wastewaters produced during
control of emissions is insignificant in
comparison with the large volume of
such wastes generated by production
processes. Baghouse technology is
marginally more environmentally
acceptable than other control
alternatives because it generates no
liquid effluents.
Compliance with the promulgated
standards will require additional
electrical energy above that required at
the SIP level of control. The incremental
increase in energy will depend on the
type of control system that is selected. If
high-energy yenturi scrubbers are used,
the total process energy requirements
will increase by 8 percent above the
energy required at the existing SIP level
of control. The incremental energy
increase above the SIP level would be 5
percent with baghouses.
The costs of operating control
equipment that would be needed to
attain the promulgated standards were
estimated using model plants. Phosphate
rock plants are concentrated primarily
in Florida. North Carolina, Idaho,
Wyoming, Utah and Montana.
Phosphate rock deposits in North
Carolina and Florida consist of a
consolidated mass of phosphate pebbles
and clays normally occurring below the
water table. Western deposits consist of
hard rock. Because of these processing
differences, costs were presented
separately for eastern and western
plants. A typical Florida plant was
selected as representative of eastern
facilities. The control costs per ton of
production are typically lower for
eastern plants because they have a
larger capacity than western plants.
The annualized cost of installing and
operating prevailing controls used to
meet existing State standards at typical
eastern phosphate rock plants is
estimated at $0.35 per megagram. The
additional cost of employing control'
technology to meet the promulgated
standards at a new eastern plant is
estimated at $0.02/megagram when
using baghouses and $0.07/megagram
for scrubbers.
The annualized control cost of
existing SIP standards at a typical new
western plant is $0.87/megagram. The
additional cost of using control
technology to meet the promulgated
standards at new western plants is
estimated at $0.08/megagram for
baghouse control and $0.28/megagram
for scrubbers.
The incremental cost of the
promulgated standards above SIP
control costs will have negligible
impacts on the profitability of the plant
and the future growth of the phosphate
rock industry. By the year 1985,
compliance with the standards would
increase the industry cost of production
of phosphate rock by 0.1 percent
(baghouse controls) to 0.2 percent
(scrubber controls) above the cost to
meet existing SIP regulations. A more
detailed discussion of the economic
analysis is discussed in the Background
Information Document for Proposed'
Standards. Volume I.
Public Participation
In accordance with Section 117 of the
Clean Air Act. proposal of the standards
was preceded by consultation with .
appropriate advisory committees,
independent experts, industry
representatives, and Federal
departments and agencies. The
proposed standards were published in
the Federal Register on September 21,
1979, with a request for public comment.
The public comment period was
extended to February 15,1980, to allow
interested persons to obtain and review
the proposed standards and the
background information document for
proposal. To provide interested persons
the opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards, a public hearing
was held on October 25,1979, at
Research Triangle Park, North Carolina.
The hearing was open to the public and
each attendee was given the opportunity
to comment on the proposed standards.
Significant Comments and Changes to
the Proposed Regulations
Many comment letters received by
EPA contained multiple comments. A
detailed discussion of these comments
and EPA's responses to them are
presented in the Background
Information for Promulgated Standards,
Volume II. The most significant
comments and changes made to the
proposed standards have been grouped
according to topic and are discussed
below.
General
Several commenters were concerned
with the applicability of the proposed
standards. They questioned whether the
standard was intended to apply to
mining operations, elemental
phosphorus plants, and ground rock
transfer facilities at fertilizer plants.
The promulgated standard is not
intended to apply to crushing or mining,
beneficiation, thermal defluorination,
elemental phosphorus production or
ground rock handling at fertilizer plants.
The standards are intended to apply to
new, reconstructed, or modified
phosphate rock dryers, calciners,
grinders, and ground rock storage and
handling systems at phosphate rock
plants. There have been several wording
and definition changes in the standards
to clarify the applicability of the
promulgated standards.
Several commenters questioned the
need for a standard since some existing
facilities were not causing ambient air
quality violations.
The purpose of new source
performance standards is not limited to
ensuring compliance with ambient air
quality standards. The primary purpose
of new source performance standards is.
to prevent future air pollution problems
and to prevent costly retrofits of control
equipment that might result from such
problems. New source performance
standards will require the uniform
application of control requirements
nationwide and will prevent unfair
competition between States for
industrial development based on
varying environmental regulations.
As required by Section III of the Clean
Air Act, the Administrator has
published a list of categories of sources
which contribute significantly to air
pollution which may reasonably be
anticipated to endanger public health or
welfare (Section III(b)(l)(A)), and for
which new source performance
standards will therefore be developed
(40 CFR 60.16, 44 FR 49222. August 21.
1979). The proposed list was published
in the Federal Register with a request for
public comment. After review of the
comments, the list was published on
August 21,1979. The sources on this list
were selected and ranked according to
an established screening procedure.
Phosphate rock plants ranked according
to an established screening procedure.
Phosphate rock plants ranked 16th in
priority of the 59 sources on the list. In
the Administrator's judgment the
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/ Vol. 47, No. 74 / Friday, April 19. 1S82 / Rules and Regulations
revised estimate of emissions for this
category of sources still justifies the
conclusion that it contributes
significantly to air pollution which may
reasonably be anticipated to endanger
public health or welfare.
Several commenters questioned the
need for a standard because they felt
the environmental benefits presented
with the original proposal were
exaggerated. The commenters felt that
the emission reductions resulting from
implementation of the standard were
exaggerated because they were based
on outdated and excessive production
forecasts. These commenters argued
that EPA should use the most recent
production estimates from the Bureau of
Mines. In addition, several commenters
pointed out that existing sources were
controlled at a more stringent level than
actually required by existing State
Implementation Plan regulations, which
reduces the projected air quality
improvement resulting from
implementation of the standard.
EPA has reevaluated the
environmental benefits presented with
the original proposal. The revaluation
of environmental benefits as presented
in Section 2.1.2 of the "Background
Information for Promulgated Standards,
Volume II" indicates a significant
decrease in the environmental benefits
of the standards. However, in the
Administrator's judgement, the revised
estimates of environmental benefits still
justify the implementation of the
standards.
The environmental impacts presented
with the original proposal were based
on an expected 5-percent annual
increase in production. This expected
increase was based on actual yearly
production figures for 1950 compared to
those projected for 1SK9. The projected
production was based on data from the
Bureau of Mines (1971). However,
annual phosphate rock production has
been fluctuating recently. Therefore, the
most recent Bureau qf Mines (1979)
production forecast data were obtained
to more accurately project the impact of
the standards.
These Bureau of Mines production
forecast data show that U.S. phosphate
rock production will increase from 47.0
million megagrams in 1977 to 64.0
million megagrams in 1989, with a
decrease to 53.0 million megagrams in
1995. With the routine replacement of
existing equipment, approximately 23.3
million megagrams of phosphate rock
production will be subject to the
promulgated standards by 1985. This
figure was used as the basis for the
environmental benefits presented in this
notice in "Environmental, Energy and
Economic Impacts".
A lower size cutoff was requested to
exclude from the standards small pilot
scale and laboratory facilities used for
testing and research. Economic analysis,
presented in the "Background
Information for Promulgated
Standards." indicates that amisaiono
from facilities with low production
capacities are relatively small and ths
cost of controlling these emissions is
excessive. The Administrator, therefore,
has determined that an exemption for
small facilities is appropriate. Ths
promulgated standards apply only to
plants with a production capacity
greater than 3.6 megagrams per hour (0
tons/hr). This capacity is representative
of the upper limit of the size range for
testing and research facilities. There are
no existing production facilities with
capacities less than 3.3 mg/hr (4.0 tons/
hr).
Particulars Emission Limits
Several commenters indicated that the
proposed particulate matter emission
limits for phosphate rock dryers and
calciners were too stringent to be
achieved on a continuous basis. The
commenters contended that the
proposed emission limits from dryers
and calciners were not based on the
performance of control systems
operating on worst case particulate
emission conditions. One of ths
problems cited was that the Agency's
data base was outdated. In order to
evaluate the comments, EPA requested
source test data from the industrial
commenters. En cases where the
commenters could not supply data to
support their position, EPA solicited
data from State air pollution control
agencies. The evaluation of the revised
data base indicated that the proposed
emission limits for dryers and calciners
could not be achieved continuously
under all operating conditions which are
likely to recur. Therefore, the emission
limits for both calciners and dryers have
been revised.
The major variables that have the
potential to affect emission levels from
phosphate rock dryers and calciners ana
the type of feed rock and the type of
fuel. Industrial experience indicated that
the most important variable affecting
particulate matter emission levels from
dryers and calciners is the feed rock
characteristics. With residual oil or coal
firing, the process rock will account for
greater than 80 and 80 percent of the
uncontrolled emissions from dryers and
calciners, respectively. Feed rock varies
from mine site to mine site. Rock types
vary from coarse pebbles to fine
concentrates with many blends of rock
between these extremes. Surface
properties, organic content, level of
benefication, and residence time in ths
processing unit vary with rock type.
Beneficiation removes fines and
increases I
emissions. Smaller average particle siso
causes the moot difficult central
situations. Therefore, beneficiatioEB
reduces emission levels. Increased
residence time increases the volume off
air per unit of rock and, therefore,
increases the emission rate per unit of
rock. These variations can effect both
the particulate matter emission levels
and the particle size distribution of the
emissions. Florida coarse pebble rock
and unbeneficiated Western rock are
the least beneficiated and have longest
unit residence times. As a result, they
have the smallest average particle size
and highest emission levels of all the
phosphate rock types. Unbeneficiated x
Western rock, which has a slightly
higher percentage of fines and smaller
average particle size than coarse pebble,
is the most difficult control case.
The four combustion fuels used in
dryers and calciners are natural gas,
distillate and residual oil, and coal. The
particulate matter emissions resulting
from the combustion of natural gas and
distillate oil are insignificant, and will
not affect particulate emission levels or
the designated best control equipment
performance. However, the combustion
of both residual oil and coal produces
significant amounts of particulate
matter. Although coal usually produces
a greater mass of particulate matter,
residual oil combustion produces a
smaller average particle size that is
more difficult to control. An analysis of
control device performance indicates
that particulate levels after control
would be higher with residual oil firing
than with coal firing. Therefore, the
Administrator has determined that
residual oil-fired units represent the
most adverse control situation with
respect to fuel.
The data base of worst-case
conditions for dryers consisted of five
source tests from two dryer facilities
processing coarse pebble rock and firing
_residual oil. Because dryers are not used
"in conjunction with unbeneficiated
Western rock, these data represent the
most adverse control conditions for
dryers. An evaluation of the
performance of a high energy venturi
scrubber on these sources indicated an
achievable emission limit of 0.03 kg/Mg
(0.06 Ib/ton). Therefore, the particulate
matter emission limit for phosphate rock
dryers had been revised from the
proposed 0.02 kg/Mg (0.06 ib/ton) to 0.03
kg/Mg (0.03 Ib/ton).
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Additional source test data were
acquired for calciners processing
unbeneficiated Western rock. The data
acquired were from the only existing
facility calcining unbeneficiated
Western rock. The data were from a
natural gas-fired calciner controlled
with a high energy wet scrubber. During
the tests used as the basis for the
emission limit, the calciner was
processing a blend of unbeneficiated
and beneficiated rock. The highest
controlled emission level during the
tests was 0.11 kg/Mg (0.21 Ib/ton). The
analysis of the tests indicated that this
controlled emission level is
representative of the highest level that
would occur with any mix of
beneficiated and unbeneficiated rock.1
Although this unit is processing the
worst-case rock type, there is a potential
for residual oil or coal firing of new
units. An analysis of the impacts of
residual oil and firing indicate that
residual oil would have the greater
impact on controlled emission levels.
The analysis indicated that residual oil
firing could increase controlled
emissions by about 0.01 kg/Mg (0.02 lb/
ton). Therefore, a particulate matter
emission limit of 0.12 kg/Mg (0.23 lb/
ton) has been added to the standards for
calciners processing unbeneficiated rock
or blends of beneficiated and
unbeneficiated rock. Calciners
processing blends with a small
percentage of unbeneficiated rock could
probably comply with the proposed
emission limit of 0.055 kg/Mg (0.11 lb/
ton). However, existing data are
insufficient to determine a precise
relationship, between emission level and
blend ratios. The promulgated emission
limit, therefore, applies to all mixtures of
unbeneficiated and beneficiated rock.
Because the majority of new calciners
will process beneficiated rock only, an
emission limit for calciners based solely
on unbeneficiated rock would allow new
sources processing beneficiated rock to
comply with the emission limits with
less than the best demonstrated control
systems. Therefore, the originally
proposed particulate emission limit of
0.055 kg/Mg (0.11 Ib/ton) is retained for
facilities calcining beneficiated rock.
The potential impacts of residual oil or
coal firing are accounted for in this
emission limit.
A comment was also made that the
particulate matter emission limits could
not be achieved continuously because it
would require continuous operation of
the control equipment at the maximum
performance level. As required by the
Clean Air Act, the promulgated
particulate matter emission limits are
based on the performance of the best
available control equipment on the
worst case uncontrolled emission levels.
The best control systems have been
demonstrated to be continuously
effective. Therefore, there should be no
problems achieving the standards if the
control equipment is properly
maintained and operated. The costs of
operation and maintenance were
included in the economic analysis of the
standards and were concluded to be
reasonable.
' Phosphate Rock Planln. Background Information
for Promulgated Standards. Volume II. EPA-450/3-
7B-017b. p. Z-20.
Several commenters questioned the
need for opacity standards since
particulate matter emissions were also
subjected to mass emission limits.
Opacity limits are included in the
standards to lower compliance costs
and simplify enforcement procedures.
Effective enforcement includes initial
demonstration of compliance and
routine evaluation of control equipment
operation and maintenance. Compliance
with particulate mass emission limits
can only be demonstrated with EPA
Method 5 performance testa. However,
Method 5 tests are too expensive and
maintenance of emission control
equipment, which is the key factor in
continuous compliance with the
emission limit. In contrast, SPA Method
9 opacity tests are quicker, simpler, and
less expensive than EPA Method 5.
Therefore, opacity limits have been
adopted in the standards as an effective
tool to assure proper operation and
maintenance of control equipment. See
Clean Air Act, Section 3Q2(k). The
promulgated opacity limits have been
set at levels no more restrictive than the
particulate mass emission limits to
ensure that any observed violations of
the opacity standards accurately
indicate a violation of the particulate
mass emission limits. In addition the
United States Court of Appeals for the
District of Columbia Circuit has
specifically upheld the use of opacity
standards to aid in controlling mass
emission under NSPS. "Portland Cement
Association v. Train," 513F. 2d 508, 508
(1975).
In criticizing the opacity limits,
several commenters recommended that
the opacity limits for dryers and
calciners should be set at 5- or 10-
percent opacity. EPA has reevaluated
the proposed opacity standards,
considering the revisions in the
particulate emission limits, and has
revised the opacity limits for phosphate
rpck dryers and calciners to 10 percent.
Typically, visible emission standards
are based on opacity observations
collected simultaneously with the
particulate emission tests on which the
mass emission limits are based. In this
case, the source test data that were used
as the basis for the revised dryer and
calciner particulate limits did not
contain corresponding opactiy data. In
the absence of corresponding opacity
data, the visible emission limits for
dryers and calciners were based on
engineering evaluations.
The evaluations involved the use of
opacity observations from an ESP-
controlled phosphate rock dryer and an
empirical correlation between particle
concentration and opacity. Although
ESP's are not designated as a basis for
this standard, the visible emissions from
this unit are characteristic of any dryer
or calciner with a similar particle
concentration. The correlation of
concentration and opacity was taken
from an EPA study of an asphalt
aggregate dryer.9The use of the asphalt
study was judged reasonable because
asphalt aggregate dryers, phospate rock
dryers, and phospate rock calciners
have similar outlet particulate
concentrations and particle size
distributions.
The observed opacity from the ESP-
controlled dryer was 7.7 percent. This
level was corrected to 6 percent to
adjust for an over-designed stack.
Particulate mass emissions were 0.02
kg/Mg (0.039 Ib/ton) at the time of the
opacity observations, with a
corresponding particulate concentration
of 0.023 g/ms (0.010 gr/acf). The
emission test used as the basis for the
promulgated particulate emission limit
of 0.03 kg/Mg (0.08 Ib./ton) for
phosphate rock dryers had a
corresponding particulate concentration
of 0.037 g/ms (0.016 gr/acf). The asphalt
correlation was used to estimate the
impact of a 0.008 gr/acf increase on a
base of 6 percent opacity. Based on this
approach the opacity level expected at
0.037 g/m3 (0.016 gr/acf) would be
approximately 7 percent. Allowing for a
safety margin in the calculations, the
opacity limit for dryers was set at 10
percent.
The particulate concentration used as
the basis for the mass emission limit for
calciners processing unbeneficiated rock
was 0.08 g/ms (0.025 gr/acf). Based on
the same approach used for dryers, the
expected opacity at this concentration
would be appoximately 8 percent. The
particulate concentration used as the
basis for the mass emission limit for
2 In-Slack Transmisaometer Measurement of
Particulate Opacity and Mass Concentration. U.S.
Environmental Protection Agency. Publication No.
EPA-650/2-74-120. November 1974. p. 34-35.
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calciners processing beneficiated rock
was 0.073 g/m3 (0.032 gr/acf). However,
this unit was controlled by a 3.0 kPa (12
inches of water) pressure drop venturi
scrubber. If the pressure drop is
increased to the designated best level of
control at 7.5 kPa (30 inches of water],
the participate concentration should be
reduced to 0.23 g/m3 (0.010 gr/acf). At
this concentration an opacity level of
approximately 6 percent would be
expected. Allowing for a safety margin
in the calculations, a 10 percent opacity
standard was set for calciners
processing either beneficiated or
unbeneficiated rock.
Although the opacity limits for
calciners and dryers have been revised,
the proposed zero percent opacity limit
has been retained for grinders and
ground rock storage and handling
systems. Several comrnenters criticized
the concept of zero percent opacity.
They contended that any deviation of
opacity above zero percent would cause
the average for the observation period to
exceed zero percent and would prevent
compliance with the standards.
The zero percent opacity limit for
grinders and ground rock storage and
handling systems was retained because
all data base opacity observations of
well-controlled sources had zero percent
opacity. Method 9 procedures can allow
some visible emissions during a
demonstration of compliance with the
zero percent limit. Opacity readings are
recorded every 15 seconds for 6 minutes
(24 readings). These readings are
recorded in 5 percent increments (i.e., 0,
5,10, etc.). The arithmetic average of the
24 readings rounded off to the nearest
whole number (i.e., 0.4 would be
rounded off to 0) is the value of opacity
used for determining compliance with
the opacity standards. Consequently, a
zero percent opacity standard does not
necessarily mean there are never any
visible emissions. It means either that
visible emissions during a 6-minute
period are insufficient to cause a
certified observer to record them as 5
percent opacity, or that the average of
the twenty-four 15-second readings is
calculated to be less than 0.5 percent.
Therefore, although emissions released
to the atmosphere from a grinder or
ground rock handling and storage
system may be visible to a certified
observer, at some time during the
observation period, the source may still
be found in compliance with the zero
percent opacity standard.
The commenters also requested that
the standards contain site-specific relief
from the opacity limits in situations
where particulate emission limits were
being achieved while opacity limits
were violated. Such a provision is not
necessary. In specific cases where it can
be demonstrated that the opacity
standards are being violated while the
particulate mass emission limits are
being met, provisions for individual
review and site-specific relief are
included in the general provisions to
these regulations (40 CFR 60.11(e)).
Continuous Monitoring
Several comments indicated a
misunderstanding of the purpose and
requirements for continuous monitoring
equipment. The commenters felt that the
purpose of the continuous monitors was
to demonstrate compliance with the
opacity limits. They indicated that
continuous opacity monitors could not
be used to accurately determine
compliance with the opacity limits.
Continuous opacity monitors are not
intended for demonstration of
compliance with opacity or particulate
matter standards. Only EPA Reference
Methods can be used to demonstrate
compliance. The purpose of continuous
monitoring at phosphate rock plants is
to ensure that emission control
equipment is properly maintained and
operated continuously. Continuous
monitoring equipment has been
demonstrated to be accurate, reliable,
and suitable for purposes of monitoring
excess emissions. Without continuous
monitoring requirements there would be
no incentive for the proper operation
and maintenance of emission control
equipment except during performance
testing. Further, the United States Court
of Appeals for the District of Columbia
Circuit has specifically upheld the use of
continuous opacity monitors in
"National Lime Association v. EPA," 627
F. 2d 416. 450-451 (1980).
A comment was made that the
proposed requirement for continuous
monitoring equipment on ground rock .
storage and handling systems was
unreasonable. The commenter pointed
out that transfer points on ground rock
handling systems were often controlled
by small baghouses which were far less
expensive than continuous monitoring
equipment.
The requirement of continuous
monitoring equipment on ground rock
handling and storage systems has been
reconsidered and has been determined
to be unnecessary. The design of ground
rock storage and handling systems vary
greatly from plant to plant. Therefore, no
typical handling and storage system can
be defined. Most of the potential
emissions from storage and handling
systems are fugitive in nature and can
be prevented by proper operation and
maintenance. Because of the fugitive
nature of emissions, it is difficult to
define or predict specific emission
points and emission control equipment
requirements. Therefore, storage and
handling systems are subject only to
visible emission limits, compliance with
which can be routinely demonstrated
with Method 9. The annualized cost of a
typical opacity monitoring system is
about $12,500 per year (1978). The
absolute costs of continuous monitoring
systems is considered excessive relative
to the control costs. Therefore, the
requirement for continuous opacity
monitors on ground rock storage and
handling systems has been deleted.
Two commenters stated that an
opacity averaging period of 6 minutes
with overlapping time intervals would
produce an excessively large and
useless volume of paperwork.
The 6-minute opacity averaging
periods required of continuous opacity
monitors are discrete successive 6-
minute periods and are not composed of
overlapping time intervals. The general
provisions (40 CFR 60.13(e)(i)) state that
continuous opacity monitors shall
complete a minimum of one cycle of
sampling and analyzing for each
successive 10-second period and one
cycle for data recording for each
successive 6-minute period. Therefore,
the volume of data produced will not be
as large as stated by the commenters.
Emission Control Technology
Several commenters questioned the
designation of baghouses as best
available control technology. The
commenters stated that no baghouses
are in current use on existing dryers or
calciners, and that technological
problems associated with high
temperatures and moisture blinding of
bags would limit their use.
EPA agrees that there are no
baghouses currently in use on phosphate
rock dryers or calciners. However,
baghouses have been installed and art
operating effectively on similar
applications, including kaolin rotary kiln
dryers and asphalt aggregate dryers.
The control conditions in these
applications are more severe than those
typically occurring with phosphate rock
dryers or calciners. Baghouse .
manufacturers have stated that
baghouses could be applied successfully
to dryers and calciners. Design and
operational procedures are available
which prevent high temperature damage
and moisture blinding. These include
insulation of the baghouse and duct
work, high temperature bags and
preheating of the unit before cold start-
V-546
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up.'Furthermore, baghouses are not the
only technique that can be used to
comply with the promulgated emission
limits. If an operator believes that due to
site-specific circumstances, there is
economic risk in using a baghouse. then
a high energy venturi scrubber can be
used to comply with the standards.
The comment was made that Volume I
of the BID should not have contained
ESPs as a control technique because it
was stated in Volume 1 that ESPs were
not the best demonstrated system,
although they are equally efficient as
baghouses and high-energy venturi
scrubbers. The commenters further
questioned EPA's judgment that ESPs
were equally as efficient as baghouses
or high-energy venturi scrubbers on
dryers and calciners. The commenters
felt that the source test data base did
not support this judgment, and ESPs
should not be used as a basis for the
standards.
Alternative participate control
equipment options with control
efficiency levels in the range of, or
above, existing controls for phosphate
rock plants are baghouses, venturi
scrubbers, and ESPs. Therefore, ESPs
were analyzed in Volume I as a control
alternative. The level of control required
by the standards is-estimated to be
approximately 99.3 percent when
processing the worst-case rock types.
EPA agrees that the source tests of ESPs
presented in the BID, Volume I, do not
achieve this level of control. The ESPs
tested achieved efficiencies in the range
of 93 to 99 percent efficiency. However,
ESP efficiency is a direct function of the
collector plate area to gas volume ratio.
By increasing the collector plate area of
the tested ESPs, the efficiency can be
increased to 99.3 percent. The economic
evaluation of ESPs presented in Volume
I of the BID presented the cost of ESPs
at the increased plate area to gas
volume ratio necessary to achieve 99.3
percent control. Because the cost of
ESPs is primarily a function of collector
plate area, the larger plate area results
in significantly higher costs. The
annualized costs of an ESP on a model
dryer or calciner are 2 to 2.5 times
higher than high-energy venturi scrubber
or baghouse costs on the same source.
Because of these higher costs, ESPs
were not designated as a basis for the
standards. The promulgated emission
limits are based On the performance of
high-energy venturi scrubbers and
baghouses.
1 Phosphate Rock Plants. Background Information
for Promulgated Standards. Volume II. EPA-450/3-
79-017b. p. 2-26. 27.
Economic Impact
Several commenters stated that the
costs to control dryers and calciners to
the required level were underestimated,
because the costs were based on typical
uncontrolled emission rates rather than
worst case uncontrolled emission rates.
The promulgated emission limits
represent the level of control achievable
with the best demonstrated control
systems on worst case emission
conditions. The available control
options which are capable of achieving
the promulgated emission limits are •
baghouses and high energy venturi
scrubbers. The reevaluation of worst
case emission levels caused a revision
in the achievable emission limits for
dryers and calciners processing
unbeneficiated rock. These revisions
were caused by changes in the inlet
loadings and particle size distributions
to the control device. However, there
was no change in the design or
operating parameters of the designated
best emission control systems.
Therefore, there is no change in the
costs of the control alternatives from
those presented in the analysis for the
proposed standard.
Other commenters stated that the
control cost estimates should be higher
for Western plants since unbeneficiated
Western rock contains a higher
percentage of fines. Unbeneficiated
Western rock does have a typically
higher percentage of fines than Eastern
rock. However, the analysis of control
costs for the proposed standard
included the economic analysis of a
typical Western plant. The economic
analysis of the standards presented in
Chapter 7 of the "Background
Information for Proposed Standards,
Volume I," indicates that, while control
costs may be higher for Western plants,
the control costs are not excessive.
The commenters also felt that control
costs for Western plants were
underestimated because no phosphate
rock dryer had been costed for the
typical model Western plant. EPA also
agrees that the addition of a dryer to a
model Western rock processing facility
will result in increased annual control
costs for typical Western plants.
However, existing SIP regulations
already require dryer emissions control
usually achieved with wet scrubbers.
Based on industrial comments, industry
would probably install high-energy
venturi scrubbers as a means of
complying with the promulgated
standards. With implementation of the
promulgated standards, there would be
no significant increase in installation
costs, because scrubber installation
costs do not vary significantly at
different efficiency levels. There would.
however, be an increase in operating
costs for the higher energy venturi
scrubber. For a typical 160-ton/hr dryer,
the increased annualized cost of the
promulgated standard above the
existing level of control would be
approximately $0.08 (1978) per
megagram ($0.07/ton) of product rock.
The price of phosphate rock under the
promulgated standard would increase
from $24.53 per megagram ($22.25/ton)
to $24.61 per megagram ($22.32/ton) in
1978 dollars. Therefore, there would be
no significant change in the economic
impact of the promulgated standard with
the addition of a dryer facility at a
Western plant.
The commenters also questioned the
costs of applying a baghouse to
phospate rock dryers or calciners. The
commenters stated that an auxiliary
heat source would be necessary to
maintain the required temperature
differential necessary to prevent
condensation of moisture on the bags.
An auxiliary heat source for baghouses
on phosphate rock dryers and calciners
was not costed or addressed because it
should be unnecessary. The temperature
differential necessary to prevent
condensation can be maintained by
properly insulating the baghouse and all
ductwork to prevent heat loss. During
start-up, the baghouse can be heated to
operating temperature by operating the
burners at low fire with no rock in the
dryer or calciner. Baghouses are
operating on similar applications such
as asphalt dryers and kaolin dryers
without auxiliary heat sources.
The commenters also argued that
baghouse costs for calciners had been
underestimated because the air flow
that was costed for the model facility
was too low. However, as pointed out in
Volume I of the BID, calciner air flows
for typical 45.4 Mg/hr (50 ton/hr) units
range from 850 to 1,700 standard m'/min
(30,000-60,000 scfm). At a typical
exhaust temperature of 120° C, these
figures would present an air flow range
of 1,160 to 2,310 actual ms/min (40,800 to
81,600 acfm). The air volume costed for
the model calciner facility was 2,930
actual m3/min (103,460 acfm) for a 54
Mg/hr (60 ton/hr) unit. Therefore, the air
flow costed is representative of the
upper range of air flows and does not
cause an underestimation of control
costs.
Commenters also questioned the cost
effectiveness of continuous monitoring
equipment. They felt that the costs
associated with continuous monitoring
had not been adequately evaluated. The
cost to purchase, install, operate, and
maintain continuous opacity monitoring
V-547
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Federal Register / Vol. 47. No. 74 / Friday, April 16. 1982 / Rules and Regulations
equipment was addressed and
evaluated during the development of the
standards. The annualized cost of a
typical continuous opacity monitoring
system is about $12,500 (1978 dollars)
per year. This cost is relatively minor
compared to the annualized cost of the
emission control equipment required by
the promulgated standard (about 4.2
percent of a venturi scrubber on a 145-
Mg/hr dryer] and was concluded to be
reasonable.
The comment was also made that the
control costs required by the standard
were underestimated because the costs
required to install, calibrate, maintain,
and operate a device for measuring
phosphate rock mass feed to the
emission sources were not included in
the control costs.
The cost of rock feed rate (by weight)
measurement equipment was addressed
and considered during the economic
analysis of the standards. Rock feed
measuring equipment is normally
utilized at phosphate rock plants to
measure production process feed rates
and is not solely a part of control
requirements. The installed cost of rock
feed measurement equipment is about
$14.000 (1978) for a facility processing
135 megagrams per hour (150 tons/hr) of
rock, and has an annualized cost of
about $3,500 (1978) per year. These costs
are insignificant (about 1.1 percent of
the annualized cost of a venturi
scrubber on a 145/Mg/hr dryer) when
compared to the control equipment costs
of the same facility.
Docket
The docket is an organized and
complete file of all the information
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 standards and EPA
responses to significant comments, the
contents of the docket will serve as the
record in case of judicial review
(Section 307(d)(7)(A)).
Miscellaneous
Standards of performance for new
sources established under Section 111 of
the Clean Air Act reflect the degree of
emission limitation achievable through
application of the best technological
system of continuous emission reduction
which (taking into consideration the cost
of achieving such emission reduction.
and nonair-quality health,
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 the 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 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 violates the National
Ambient Air Quality Standards
(NAAQS) must reduce emissions to a
level that 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 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 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 (SIPS) 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, improvements in
emission control technology and
reporting requirements. The reporting
requirements in this regulation will be
reviewed as required under EPA's
sunset policy for reporting requirements
in regulations.
Under Executive Order 12291, EPA
must judge whether a regulation is
"Major" and therefore subject to the
requirement of a Regulatory Impact
Analysis. This regulation is not Major
because: (1) The national annualized
compliance costs, including capital
charges resulting from the standards
total less than $100 million; (2) the
standards do not cause a major increase
in prices or production costs; and (3) the
standards do not cause significant
adverse effects on domestic competition,
employment, investment, productivity,
innovation or competition in foreign
markets. This regulation was submitted
to the Office of Management and Budget
(OMB) for review as required by
Executive Order 12291. The docket is
available for public inspection at EPA's
Central Docket Section. West Tower
Lobby, Gallery 1, Waterside Mall, 401 M
Street. SW., Washington. D.C. 20460.
Although no regulatory impact
analysis is required, an economic impact
assessment of alternative emission
standards has been prepared, as
required under Section 317 of the Clean
Air Act and is included in the
V-548
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/ Vol. 07, No. 74 / Friday. April 118, SS02 / Rules and Regulations
"Background Information Document for
Proposal for Phosphate Rock Plants.
Volume I." EPA considered all the
information in the economic impact
analysis in assessing the cost of the
otandard.
In addition to economics, the cost
effectiveness of alternative standards
was evaluated in order to determine the
least costly way to reduce emissions
and to assure that the controls required
by this rule are reasonable relative to
other regulations for particulate matter.
The cost per ton of pollutant removed
was computed for each process affected
by the standard, both on an average and
incremental basis. The incremental cost
ranged from $51 to S235 per ton of
particulate removed, which compares
favorably with particulate matter
control at other industrial sources where
costs typically range up to $1,000 per ton
and in certain cases may exceed $2,000
per ton. Additional detail on this
analysis can be found in the docket.
The information collection activity
contained in this Final Rule is not
covered by the Paperwork Reduction
Act (PRA) because there are fewer than
ten respondents.
Lac! of Subjects in 60 CFK Part SO:
Air pollution control, Aluminum,
Ammonium sulfate plants, Cement
industry, Coal, Copper, Electric power
plants, Glass and glass products, Grains,
Intergovernmental relations, Iron, Lead,
Metals, Motor vehicles. Nitric acid
plants, Paper and paper products
industry, Petroleum, Phosphate, Sewage
disposal, Steel, Sulfuric acid plants,
Waste treatment and disposal. Zinc.
Dated: April 9,1982.
Anne M. Gorsuch,
Administrator.
I?srf@irmaneQ tor Phoophote K@gb
literates
PlftFORMAMCE FOE! MEW
40 CFR Part 60 is amended"by adding
a new subpart as follows:
Sss&part CslN—Standardo of Performance for
KteopftQto Re-cti Ptonto
Sec.
(30.400 Applicability and designation of
affected facility.
30.001 Definitions.
£0.402 Standard for particulate matter.
£0.403 Monitoring of emiosiono and
operations.
80.404 Teot methoda and procedures.
Authority: Saco. Ill and 301(a) of the Clean
Air Act. as amended. (42 U.S.C. 7411.
?S01(a)), and additions! authority ao noted
below:
(a) The provisions of this subpart are
applicable to the following affected
facilities used in phosphate rock plants
which have a maximum plant
production capacity greater than 3.8
megagrams per hour (4 tons/hr): dryers,
calciners, grinders, and ground rock
handling and otorage facilities, except
those facilities producing or preparing
phosphate rock solely for consumption
in elemental phosphorus production.
(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.
§ 90.401 BoflnlSiono.
(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 all
material entering the process unit
including, moisture and extraneous
material as well as the following ore
minerals: Fluorapatite, hydroxylapatite,
chlorapatite, and carbonateapatite.
(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 pulverize dry phosphate rock to
the final product size used in the
manufacture of phosphate fertilizer and
does not include crushing devices used
in mining.
(f) "Ground phosphate rock handling
and storage system" means a system
which is used for the conveyance and
storage of ground phosphate rock from
grinders at phosphate rock plants.
(g) "Beneficiation" means the process
of washing the rock to remove
impurities or to separate size fractions.
§ 80.402 Standard for portteuGato tmoWor.
(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 0.030 kilogram per megagram
of phosphate rock feed (O.OS Ib/ton), or
(ii) Exhibit greater than 10-percent
opacity.
(2) From any phosphate rock calciner
processing unbeneficiated rock or
blends of beneficiated and
unbeneficiated rock, any gases which:
(i) Contains particulate matter in
excess of 0.12 kilogram per megagram of
phosphate jock feed (0.23 Ib/ton), or
(ii) Exhibit greater than 10-percent
opacity.
(3) From any phosphate rock calciner
processing beneficiated rock 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 10-percent
opacity.
(4) From any phosphate rock grinder
any gases which:
(i) Contain particulate matter in
excess of 0.008 kilogram per megagram
of phosphate rock feed (0.012 Ib/ton). or
(ii) Exhibit greater than zero-percent
opacity.
(5) From any ground phosphate rock
handling and storage system any gases
which exhibit greater than zero-percent
opacity.
9 G0.403 Monitoring of omloclons and
(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 paragraphs (b) and (c) of
this section, to monitor and record the
opacity of the gases discharged into the
atmosphere from any phosphate rock
dryer, calciner, or grinder. The span of
this system shall be set at 40-percent
opacity.
(b) For ground phosphate rock storage
and handling systems, continuous
monitoring systems for measuring
opacity are not required.
(c) 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 tne 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
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Federal Register / Vol. 47. No. 74 / Friday. April 16. 1982 / Rules and Regulations
scrubbing liquid supply pressure to the
control device. The monitoring device
must be accurate within ±5 percent of
design scrubbing liquid supply pressure.
(d) 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, or grinder. The
measuring device used must be accurate
to within ±5 percent of the mass rate
over its operating range.
(e) For the purpose of reports required
under § 60.7(c), periods of excess
emissions that shall be reported are
defined as all 6-minute periods during
which the average opacity of the plume
from any phosphate rock dryer, calciner.
or grinder subject to paragraph (a) of
this section exceeds the applicable
opacity limit.
(f) Any owner or operator subject to
the requirements under paragraph (c) 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 $ 604 in which the affected
facility demonstrated compliance with
the standard under $ 00.402.
(Sec. 114. Clean Air Act as amended (42
U.S.C. 7414))
§60.404 T«»t methods and procedure*.
(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 follow*:
(1) Method 5 for the measurement of
paniculate 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 have a minimum sampled volume of
O.S4 dscm (30 dscf). However, 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, the average
phosphate rock feed rate in megagrams
per hour shall be determined using a
device meeting the requirements of
S 60.403(d).
(d) For each run, emissions expressed .
in kilograms per megagram of pHosphate
rock feed shall be determined using the
following equation:
'(CsQ«)lQ-»
E M
where. E=Emitsions of participates in kg/Mg
of phosphate rock feed.
Cs = Concentration of participates in mg/
dscm as measured by Method 5.
Qs = Volumetric flow rate in dscm/hr as
determined by Method 2.
10"'= Conversion factor for milligrams to
kilograms.
M = Average phosphate rock feed rate in mg/
hr.
Note.—The reporting and recordkeeping
requirements in this section are not subject to
Section 3507 of the Paperwork Reduction Act
of 1980. 44 U.S.C. 3507. because these
requirements are expected to apply to fewer
than 10 persons by 1985.
(Sec. 114. Clean Air Act, as amended. (42
U.S.C. 7414))
|FRUoc B2-1M73 Fited 4-1S-S2 8*5 am)
BILUNO COM (StO-MMI
V-550
-------
A®GK©V: Environmental Protection
Agency (EPA).
Ag7C©Ki: Final rule.
v: EPA. Region 9, has delegated
the authority for implementation and
enforcement of New Source
Performance Standards (NSPS) and
National Emission Standards for
{Hazardous Air Pollutants to the
Oklahoma State Department of Health
(OSDH). Except as specifically limited.
all of the authority and responsibilities
of the Administrator or the Regional
Administrator which ere found in 40
(CFR Part 60 and 40 CFR Part 81 ere
delegated to the OSDH. Any of such
authority and responsibilities may be
redelegated by the Department to its
Director or staff.
! request
and State-EPA agreement for delegation
of authority are available for public
inspection at the Air Branch,
Environmental Protection Agency,
Region 6. First International Building.
23th Floor. 1201 Elm Street, Dallas.
Texas 75270; (214) 787-158$ or (FTS)
729-1594.
William H. Taylor, Air Branch, address
fflbova; (214) 787-158*6 or FTS 728-1584.
December 18, 1880, the State of
Oklahoma submitted to EPA, Region 3, a
request for delegation of authority to the
OSDH for the implementation and
enforcement of the NSPS and NESHAP
programs. After a thorough review of the
request and information submitted, the -
Regional Administrator determined that
ihe State's pertinent laws and the rules
and regulations of the OSDH were found
to provide an adequate and effective
procedure for implementation and
enforcement of the NSPS and NESHAP
programs.
The Office of Management and Budget
lias exempted this information notice
from the requirements of Section 3 of
Executive Order 12291.
Effective immediately, all information
pursuant to 40 CFR 00 and €0 CFR 91 by
sources locating in the State of
Oklahoma should bo submitted to the
Air Quality Ssrvice, P.O. Box 53551,
Oklahoma City. Oklahoma 73152.
This delegation io issued under the
authority of Sections 111 and 112 of the
Clean Air Act. as amended (42 U.S.C.
7411 and 7412).
Dated; April 7.1982.
Ei& Whittingtoa,
Regional Administrator.
©OTS April 27,1882.
IU
Part 60 of Chapter 1. Title 40 of the
Code of Federal Regulations is amended
as follows:
§ 80.4 is amended by revising
paragraph (b)(LL) to read as follows:
(b) * ° »
(LL) State of Oklahoma, Oklahoma State
Department of Health. Air Quality
Service, P.O. Box 53551, Oklahoma City,
Oklahoma 73152.
148
A©GK)@v: Environmental Protection
Agency (EPA).
Q@7!®RK Final rule.
OtsmAnv: This document amends EPA
regulations which state the address of
the Delaware Department of Natural
Resources and Environmental Control to
reflect delegation to the State of
Delaware of authority to implement and
enforce additional Standards of
Performance for New Stationary
Sources and National Emission
Standards for Hazardous Air Pollutants.
Laurence Budney (3AW12),
Environmental Protection Agency,
Region m, Curtis Bldg., 8th a Walnut
Sts., Philadelphia, PA 19103, Telephone:
(215) 597-2342.
On September 22,1881 and February
8,1882. John E. Wilson HI. Secretary of
the Delaware Department of Natural
Resources and Environmental Control,
submitted requests for delegation of
authority to implement and enforce
regulations for:
° New Source Performance Standards
(NSPS) for stationary gas turbines
° New Source Performance Standards
(NSPS) for petroleum refineries
° National Emission Standards for
Hazardous Air Pollutants (NESHAP)
for vinyl chloride
The request was reviewed and on
April 15,1882 a letter was sent to John E.
Wilson III, Secretary, Department of
Natural Resources and Environmental
Control, approving the delegation and
outlining its conditions. The approval
letter specified that if Secretary Wilson
or any other representatives had any
objections to the conditions of the
delegation they were to respond within
ten (10) days after receipt of the letter.
As of this date, no objections have been
received.
With respect to the authority
delegations referred to above, EPA is
today amending 40 CFR 80.4 and 61.04,
Address, to reflect these delegations.
The amended g 60.4 and g 81.04 which
state the address of the Delaware
Department of Natural Resources and
Environmental Control (to which all
reports, requests, applications,
oubmiUalo and communications to the
Administrator regarding this subpart
must be addressed), is set forth below.
The Administrator finds good cause to
make this rulemaking effective
immediately without prior public notice
since 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 April 15,1832.
This rulemaking is effective
immediately, end is issued under the
authority of Sections 111 and 112 of the
Clean Air Act, as amended.
V-551
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Federal Register / Vol. 47. No. 81 / Tuesday. April 27, 1982 / Rules and Regulations
The Office of Management and Budget
has exempted this action from Executive
Order 12291.
in. List of Subjects in 40 CFR Part 60
Air pollution control, Aluminum,
Ammonium sulfate plants. Cement
industry. Coal, Copper, Electric power
plants, Glass and glass products. Grains,
Intergovernmental relations. Iron, Lead,
Metals, Motor vehicles, Nitric acid
plants. Paper and paper products
industry, Petroleum, Phosphate, Sewage
disposal, Steel, Sulfuric acid plants,
Waste treatment and disposal, Zinc.
IV. List of Subjects in 40 CFR Part 61
Air pollution control, Asbestos,
Beryllium, Hazardous materials,
Mercury, Vinyl chloride.
(42 U.S.C. 7401 et seq.)
Dated: April IS, 1982.
Stephen R. Wassersug,
Director, Air & Waste Management Division.
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
In S 60.4, paragraph (b) is amended
by revising subparagraph (I) to read as
follows:
§60.4 Addrou.
*****
(b)"*
(AHH)' * '
(I) State of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants: asphalt concrete plants; storage
vessels for petroleum liquids; sulfuric acid
plants; sewage treatment plants; electric
utility steam generating units; stationary gas
turbines and petroleum refineries).
Delaware Department of Natural Resources
and Environmental Control. Tatnall
Building, P.O. Box 1401, Dover, Delaware
19901
V-552
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
2.
3. RECIPIENT'S ACCESSION NO.
EPA-340/1-82-005C
4. TITLE AND SUBTITLE
Standards of Performance for New Stationary
Sources - A Compilation as of May 1, 1982
Volume 3: Full Text of Revisions
5. REPORT DATE
June 1982
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
PN 3660-1-42
9. PERFORMING ORGANIZATION NAME AND ADDRESS
3EDCo Environmental, Incorporated
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-01-6310
Task No. 42
12. SPONSORING AGENCY NAME AND ADDRESS
J.S. Environmental Protection Agency
Stationary Source Compliance Division
Washington, D.C. . 20460
13. TYPE OF REPORT AND PERIOD COVERED
Compilation to May 1982
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 is a compilation of the New Source Performance Standards promulgated
under Section 111 of the Clean Air Act, represented in full as amended. The infor-
mation contained herein supersedes all compilations published by the Enviornmental
Protection Agency prior to 1982. Volume 1 contains Sections I through III including:
Introduction, Summary Table, and Regulations as amended. Volume 2 contains Section
IV, Proposed Regulations, and Volume 3 contains Section V, the full text of all regu-
lations promulgated since 1971.
7.
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
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
?O. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (t-7J)
•U.S. GOVERNMENT PRISTINC OFFICE: -.982—639-001/3009
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