-------
good air pollution control practice for
minimizing emissions during these pe-
riods Emissions in excess of the level of
the standard durliiR periods of startup,
shutdown, nnd malfunction nrc not to be
Included within the 1.5 percent.
(Bees. Ill, 114, and 301 (a) of the Clean Air
Act as amended (42 U.6.C. 1857c-«, 1857C-B.
1857g(a)).)
References:
60.2
60.7
60.8
60.11
60.13
Reference Methods 6,
Specifications 1, 2
-------
•ufapart Q—Standard* of Performance for
Primary Zinc Smelters
160.170 Applicability and designation
of affected facility.
(a) The provisions of this iubpart are
applicable to the following affected facili-
ties In primary dncsmeltera: roaster and
mlT\tfr\nf TTIflfhlnf
. (b) Any facility under paracraph (a)
of this lection that commences construc-
tion or modification after October 14.
1974. is subject to toe requirement* of
ubpart
f 60.171 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.
(a) "Primary zinc smelter" means any
installation engaged in the production, or
any intermediate process in the produc-
tion, of line or einc oxide from due sul-
flde ore concentrates through the use
of pyrometallurgical techniques.
.
(2) Sulfur dioxide. Any two-hour pe-
riod, as described in paragraph (b) of
this section, during which the average
emissions of sulfur dioxide, as measured
by the continuous monitoring system in-
stalled under paragraph (a) of this sec-
tion, exceeds the standard under { 60.173.
(••c. 114 of UM d*M Air Act at
(41 O.8.C. 1M7C-*).).
References:
60.2
60.7
60.8
60.11
60.13
Reference Methods 6,
Specifications 1. 2
111-20
-------
•ubpart R—Standard* of Performance tar
Primary Lead Smelters
| 60.180 Applicability mm
•f affected faellilr-
(a) Th« provision* 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-
Deratory furnace, electric smelting fur-
nace, and converter.
-------
Subpart T—Standards of Performance for
the Phosphate Fertilizer Industry: Wat-
Process Phosphoric Acid Plants
§60.200 Applicability and designation
of affected facility.
<•>> Tha affected facility to which the
provisions of this aubpart apply Is *mch
wet-prooau phosphoric acid plant For
tha 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
32, 1874, Is subject to the requirements
of fln^t
160.201 Definition*.
As used In this subpart. all terms not
defined herein shall have the meaning
given them in the Act and in Bubpart A
of this part.
(a) "Wet-process phosphoric acid
plant" means any facility manufactur-
ing phosphoric acid by reacting phos-
phate rock and acid.
(b) "Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods specified
In J 60.204, or equivalent or alternative
methods.
(c) "Equivalent PiOi feed" means tha
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the proc-
| 60.203 Monitoring of operation*.
(c) The owner or operator of any wet-
process phosphoric acid subject to the
provisions of this part shall Install, cali-
brate, maintain, and operate a monitor-
ing device which continuously measures
and permanently records the total pres-
sure drop across the process scrubbing
system. The monitoring device shall have
an accuracy of ±5 percent over Its op-
erating range.
(•ec 114 at th» OMB Air Act a*
-------
Subpart U—Standards of Performance for
the Phosphate Fertilizer Industry. Super-
phosphoric Acid Plants
1 60.210 Applicability and designation
of affected facility.
(») The affected facility to which the
provision* of this subpart apply IB each
•uperphosphoric acid plant For the
purpose of this subpart, the affected
facility includes any combination of:
evaporators, hotwells. acid sumps. and
cooling t-"-1"^"
(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
| 60.211 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.
(a) "Superphosphoric acid plant"
means any facility which concentrates
wet-process phosphoric acid to 66 per-
cent or greater PiO. content by weight
for eventual consumption as a fertilizer.
(b) "Total fluorides" means elemen-
tal fluorine and all fluoride compounds
as measured by reference methods spe-
cified in 5 60.214, or equivalent or alter-
native methods.
(c) "Equivalent P.O. feed" means the
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the
process.
( 60.213 Monitoring of operation*.
(c) The owner or operator of any
superphosphoric acid plant subject to the
provisions of this part shall install, cali-
brate, maintain, and operate a monitor-
ing device which continuously measures
and permanently records the total pres •
sure drop across the process scrubbing
system. The monitoring device shall have
an accuracy of :t 6 percent over its
operating range.
(8«c 114 of tba ClMA Air Act M
(41 O.S.C. 1U7C-9).).
References:
60.2
60.7
60.8
60.11
60.13
111-23
-------
•ubpart V—Standards of Performance for
tht Phosphate Fartlllzar Industry. Dtanv
monium Phosphate Plants
160.220 Applicability *M
of affaded facility.
(*> The affected facility to whteh «he
provisions of this subpart apply is wen
granular dtammonlum phosphate plant.
For the purpose of this aubpart, the Af-
fected facility includes any combination
of: reactors, granulaton. dryers, coolers.
aereena, 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
thiesubpart.
f 60.221 Definition*.
As used in this subpart. all terms not
defined herein shall have the meaning
liven them in the Act and in Subpart A
of this part
(a) "Granular diammonium phos-
phate plant" means any plant manu-
facturing granular diammonium phos-
phate by reacting phosphoric acid with
ammonia.
(b) "Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods speci-
fied in 160.224, or equivalent or alter-
native methods.
"Equivalent P.O. feed" means the
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the proc-
160.223 Monitoring of operation.
(c) The owner or operator of any
granular diammonium phosphate plant
subject to the provisions of this part shall
Install, calibrate, maintain, and operate
a monitoring device which continuously
measures and permanently records the
total pressure drop across the scrubbing
system. The monitoring device shall have
an accuracy of ±5 percent over its op-
erating range.
(Bee. 114 of th« data Air An a*
-------
Subpart W—Standards of Performance for
the Phosphate Fertilizer Industry: Triple
Superphosphate Plants
| 60.230 Applicability aad 4e*i*-nalVun
of affected facility.
(»> The affected facility to which the
provisions of this subpert apply Is eech
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-plle 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 requlremente of
thisiubpart.
§60.231 Definition*.
As used In this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Triple superphosphate plant"
means any facility manufacturing triple
superphosphate by reacting phosphate
rock with phosphoric acid. A run-of-plle
triple superphosphate plant Includes
curing and storing.
(b) "Run-of-pile triple superphos-
phate" means any triple superphosphate
that has not been processed In a granu-
lator and is composed of particles at
least 25 percent by weight of which
(when not caked) will pass through a 16
mesh screen.
"Total fluorides" means ele-
mental fluorine and all fluoride com-
pounds as measured by reference
methods specified in i 60.234. or equiva-
lent or alternative methods.
§ 60.233 Monitoring of operation*.
(c ) The owner or operator of any triple
superphosphate plant subject to the pro-
visions of tills part shall install, calibrate,
maintain, and operate a monitoring de-
vice which continuously measures and
permanently records the total pressure
drop across the process scrubbing system.
The monitoring device shall have an ac-
curacy of ±5 percent over its operating
range.
(Bee. 114 at th* duo Air Act «
(41 UAC. l«B7o-B).).
References:
60.2
60.7
60.8
60.11
60.13
ITT-25
-------
Subpart X—Standards of Performance for
the Phosphate Fertilizer Industry: Gran-
ular Triple Superphosphate Storage Fa-
cilities
160.240 Applicability and dmlgnalloii
•f affected facility.
<•> Hie affected facility to which the
provisions of this sUbpart apply is each
granular triple superphosphate storage
facility, for the purpose of this subpart,
the affected facility include* any combi-
nation of: iterate or curing piles, con-
veyors, elevators, screens, and mills.
"Equivalent PiO* stored" means
the quantity of phosphorus, expressed as
phosphorus pentoxlde, being cured or
stored in the affected facility.
(d) "Fresh granular triple superphos-
phate" means granular triple superphos-
phate produced no more than 10 days
prior to the date of the performance test
| 60.243 Monitoring of operation*.
*****
-------
Subpart Y—Standards of Performance (or
Coal Preparation Plants
| 60.250 Applicability and designation
of affected facility.
(a) The provision* of Uiis cubpart ere
applicable to any of the following af-
fected facilities in coal preparation
plants which process more than 200 tone
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.
(to) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 24,
1974, is subject to the requirements of
tfclssubpart.
8 60.251 Definition*.
As used in this subpart, all terms not
defined herein nave the meaning given
them In the Act and In Subpart A of this
part
(a) "Coal preparation plant" means
any facility (excluding underground
mining operations) which prepares coal
by one or more of the following proc-
esses: breaking, crushing, screening, wet
or dry cleaning, and thermal drying.
(b) "Bituminous coal" means solid fos-
sil fuel classified as bituminous coal by
AJB.TM. Designation D-388-66.
, (c) "Coal" means all solid fossil fuels
classified as anthracite, bituminous, sub-
bituminous, or lignite by A.S.T.M. Des-
ignation D-388-66.
(d) "Cyclonic flow" means a splrallng
movement ot exhaust gases within a duct
or stack.
(e) "Thermal dryer" means any fa-
cility in which the moisture content of
bituminous coal Is reduced by contact
with a heated gas stream which Is ex-
hausted to the atmosphere.
(f) "Pneumatic coal-cleaning equip-
ment" means any facility which classifies
bituminous coal by size or separates bi-
tuminous coal from refuse by application
of air stream(s).
(g) "Coal processing and conveying
equipment" means any machinery used
to reduce the size of coal or to separate
coal from refuse, and the equipment used
to convey coal to or remove coal and
refuse from the machinery. This In-
cludes, but is not limited to, breakers,
crushers, screens, and conveyor belts.
(b) "Coal storage system" means any
facility used to store coal except for open
storage piles.
(1) "Transfer and loading system"
means any facility used to transfer and
load coal for shipment.
| 60.253 Monitoring of operation*.
(a) The owner or oi>erator of any ther-
mal dryer ihall Install, calibrate, main-
tain, and continuously operate monitor-
ing devices as follows:
(1) A monitoring device for the meas-
urement of the temperature of the gas
stream at the exit of the thermal dryer
on a continuous basis. The monitoring
device is to be certified by the manu-
facturer to be accurate within ±3* Fahr-
enheit.
(2) For affected faculties that use ven-
turi scrubber emission control equip-
ment:
(1) A monitoring device for the con-
tinuous measurement of the pressure loss
through the venturl constriction of the
control equipment. The monitoring de-
vice is to be certified by the manufac-
turer to be accurate within ±1 inch
water gage.
(11) A monitoring device for the con-
tinuous measurement of the water sup-
ply pressure to the control equipment.
The monitoring device Is to be certified
by the manufacturer to be accurate with-
in ±5 percent of design water supply
pressure. The pressure sensor or tap must
be located close to the water discharge
point. The Administrator may be con-
sulted for approval of alternative loca-
tions.
(b) All monitoring devices under para-
graph (a) of this section are to be recali-
brated annually In accordance with pro-
cedures under S 60.13(b) (3).
(8*c. 114 of th* CUan Air Act a>
(41 0.3 C. 1881&-*).).
References:
60.2
60.7
60.8
60.11
60.13
111-27
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•ubpart Z—Standards of Performance tor
ferroalloy Production Facilities
160.260 Applicability
of affected facility.
<•>) 111* provision* of this subpart are
applicable to the following affected fa-
eUHles: electric •Ubmerged arc furnaces
which produce silicon metal, ferroslllcon,
calcium etlioon, sUicomanganeee slrtxm-
ium, ferrachrome elllcon, gllvery
Iron, high-carbon ferrochrome, charge
obrome, standard ferromaDganeae, elll-
eomanganeae, ferromanganeae illicon, or
calcium oarbide; and dust-handling
equipment.
(to) Any facility under paragraph (a)
of this eection that commence! construc-
tion or modification after October 21.
1074. U subject to the requirement* of
160.261 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.
(a) "Electric submerged arc furnace"
means any furnace wherein electrical
energy is converted to heat energy by
transmission of current between elec-
trodes partially submerged in the furnace
charge.
(b) "Furnace charge" means any ma-
terial introduced into the electric sub-
merged arc furnace and may consist of.
but is not limited to, ores, slag, carbo-
naceous material, and limestone.
(e) "Product change" means any
change in the composition of the furnace
charge that would cause the electric sub-
merged arc furnace to become subject
to a different mass standard applicable
under this subpart.
"Slag" means the more or less
completely fused and vitrified matter
separated during the reduction of a
metal from its ore.
(e) "Tapping" means the removal of
slag or product from the electric sub-
merged arc furnace under normal op-
erating conditions such as removal of
metal under normal pressure and move-
ment by gravity down the spout into the
ladle.
70 percent by weight
chromium, 5 to 8 percent by weight car-
bon, and 3 to 6 percent by weight silicon.
(s) "Silvery iron" means any ferro-
sllicon, as denned by A.S.T.M. designa-
tion 100-69, which contains less than
30 percent silicon.
(t) "Ferrochrome silicon" means that
alloy as denned by AJ3.TJH. designation
A482-66.
(u) "Sillcomanganese zirconium"
means that alloy containing 60 to 65 per-
cent by weight silicon, 1.5 to 2.5 percent
by weight calcium, 5 to 7 percent by
weight zirconium, 0.75 to 1.25 percent by
weight aluminum, 5 to 7 percent by
weight manganese, and 2 to 3 percent by
weight barium.
(v) "Calcium silicon" means that
alloy as denned by A.S.T.M. designation
A495-44.
(w) "Perroslllcon" means that alloy as
defined by A.S.T.M. designation A100-69
grades A, B, C, D, and E which contains
50 or more percent by weight silicon.
(x) "Silicon metal" means any silicon
alloy containing more than 96 percent
silicon by weight.
(y) "Ferromanganese silicon" means
that alloy containing 63 to 66 percent by
weight manganese, 28 to 32 percent by
weight silicon, and a maximum of 0.08
percent by weight carbon.
§ 60.262 Standard for paniculate mat-
ter.
(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 from any electric
submerged arc furnace any gases which:
(3) Exit from a control device and ex-
hibit 15 percent opacity or greater.
(b) On and after the date on which
the performance test required to be con-
ducted by i 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 dust-han-
dling equipment any gases which exhibit
10 percent opacity or greater.
§ 60.264 EmUiion monitoring.
(a) 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 8 60.7(c), the owner or op-
erator shall report as excess emissions
all six-minute periods in which the av-
erage opacity is 15 percent or greater.
§ 60.265 Monitoring of operation!.
(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 provided
under paragraph (e) of this section. The
owner or operator of an electric sub-
merged arc furnace that Is equipped with
a water cooled cover which is designed
to contain and prevent escape of the
generated gas and participate 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
111-28
-------
operator to demonstrate the accuracy of
the monitoring device relative to Meth-
ods 1 and 2 of Appendix A to 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 ?860262(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 How 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
temperature) and shall:
(1) Install, calibrate, maintain, and
operate a device to continuously measure
and record the power consumption of the
fan motor (measured In kilowatts), and
(2) Install, calibrate, maintain, and
operate a device to continuously meas-
ure and record the pressure drop across
the fan. The fan power consumption and
pressure drop measurements must be
synchronized to allow real time compar-
isons of the data. The monitoring de-
vices must have an accuracy of ±5 per-
cent over their normal operating ranges.
(f) The volumetric flow rate through
each fan of the capture system must be
determined from the fan power con-
sumption, fan pressure drop, and fan
performance curve specified under para-
graph (e) of thU section, during any per-
formance test required under 160.8
to demonstrate compliance with the
standards under 5560.262(a) (4) and
(5). The owner or operator shall deter-
mine the volumetric flow rate at a repre-
sentative temperature for furnace power
Input levels of 50 and 100 percent of the
nominal rated capacity of the electric
submerged arc furnace. At all times the
electric submerged arc furnace is op-
erated, the owner or operator shall main-
tain the fan power consumption and fan
pressure drop at levels such that the vol-
umetric flow rate is at or above the levels
established during the most recent per-
formance test for that furnace power in-
put level. If emissions due to tapping are
captured and ducted separately from
emissions of the electric submerged are
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 by the Administrator
to be unacceptable operation and main-
tenance of the affected facility. The own-
er or operator may request that these
flow rates be reestablished by conducting
new performance tests under J 60.8. The
Administrator may require the owner or
operator to verify the fan performance
curve by monitoring necessary fan oper-
ating parameters and determining the
gas volume moved relative to Methods 1
and 2 of Appendix A to this part.
(g) All monitoring devices required
under paragraphs (c) and (e) of this
section are to be checked for calibration
annually in accordance with the proce-
dures under }60.13(b).
(S*c. 114 of tb« Clnn Air Act M
(41 UA.C. »M7e-»).).
References:
60.2
60.7
60.8
60.11
60.13
111-29
-------
Subpart AA—-Standard* of Pwfofmane*
for StMl Hants: Etoelrie Are PurnaoM
60.272
ler.
Standard for paniculate
• 60.270 Applicability MM
of affected facility.
(a) The provisions of this atibprnrt are
applicable to the following affected fa-
cilities in steel plant*: electric mrc fur-
naces and duct-handling equipment.
(b) Any facility under paragraph <»)
of this section that commences construc-
tion or modification after October 21.
1974. is subject to the requirements of
Iblssubpart.
160.271 D«8nilioiu.
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 arc furnace" (EAF)
means any furnace that produces molten
steel and beats the charge materials
with electric arcs from carbon electrodes.
Furnaces from which the molten steel Is
cast into the shape of finished products.
such as in a foundry, are not affected fa-
cilities included within the scope of this
definition. Furnaces which, as the pri-
mary source of iron, continuously feed
prereduced ore pellets are not affected
facilities within the scope of this
definition.
(b) "Dust-handling equipment" means
any equipment used to handle parttcu-
late matter collected by the control de-
vice and located at or near the control
device tor an EAF subject to this sub-
part.
(c) "Control device" means the air
pollution control equipment used to re-
move paniculate matter generated by
an EAF(s) from the effluent gas stream.
(d) "Capture system" means the
equipment (including ducts, hoods, fans,
dampers, etc.) used to capture or trans-
port participate matter generated by an
EAF to the air pollution control device.
-------
Subpart BB—Standard* of Performance for
Kraft Pulp Mill.
60.!2HO Applicability a ml deHixiiiilion of af-
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 semichemical 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 semichemical
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-
trate tanks used to wash the pulp fol-
lowing the digester system.
(f) "Multiple-effect evaporator
Hystem" moans 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.
§ 60.282 Standard for\jiarticulate matter.
(a) On and after wie date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provj.-
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.
(ii) Exhibit 35 percent opacity or
greater.
(2) Prom 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 Honor .solids (dry weight)].
CD From uny lime kiln any KOHCH
which contain particulate matter In
excess of:
(1) 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 ot this subpart shall cause to be
discharged into the atmosphere:
(1) Prom 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
-------
{ 90.284 Monitoring of emtaioiu and op-
eration*.
(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(a)(D (ill) or
(Iv) apply. These systems shall be lo-
cated downstream of the control
device(s) and the span(s) of these con-
tinuous monitoring system(s) shall be
set:
(i) 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.
(ii) 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:
(DA 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 $60.283(a)(D(lii>
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:
(1) 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 ±600 pascals (ca. ±2
Inches water gage pressure).
(11) 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
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)(iv) or § 60.283(a)(4)
apply.
(1) Calculate and record on a dailv
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 daily
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 (c)(l) 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:
Cmrl = CmM.X(21 - X/21 ~ 10
where:
Crarl = the concentration corrected tor
oxygen.
Cn,.-»tric concentration unconnected (or
oxygen.
Jf-the volumetric oxygen concentration In
percentage to b<» corrected to (8 percent
for recovery furnaces and 10 percent for
lime kilns. 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:
(1) 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.
(ii) All 6-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
Above 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)(l) (1), (ii),
or (Iv) apply; or
(ii) 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
§60.283(a)(l)(il) apply.
(e) The Administrator 7/111 not con-
sider periods of excess emissions re-
ported under paragraph (d) of this sec-
tion to be indicative of a violation of
§60.11(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.
(ID 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 §60.8(b). shall be used to deter-
mine compliance with §60.282(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 § 60.282(a)(2), Method 2 for veloc-
ity and volumetric flow rate, k
(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 §60.282(a)(l)(i): Provided,
That a constant value of 0.009 g/dscm
(0.004 gr/dscf) is added to the results
of Method 17 and the stack tempera-
I11-32
-------
ture is no greater than 205" C (ca. 400°
P). 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.
E = ( C|1! 4-
-f C
„)
ex-
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-
Where:
E =« mass of TRS emitted per unity of black
liquor solids ..CQi.= average concentration of Na,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
111-33
-------
Subpart HH—Standard* of Perfor-
mance for Lime Manufacturing
Plant*
Sec.
60.340 Applicability and designation of af-
fected facility.
60.341 Definitions. •
60.342 Standard for partlculate matter.
60.343 Monitoring of emissions and oper-
ations.
60.344 Test methods and procedures.
AUTHORITY: Sec. HI and 301(a) of the
Clean Air Act. as amended (42 U.8.C. 7411.
7601), and additional authority as noted
below.
§60.840 Applicability anil 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 Definition*.
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. calcltlc 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 hydralor" means a unit
used to produce hydrated lime prod-
uct-
§ 60.342 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 -subpwt shall cause to be
discharged into the atmosphere:
(1) Prom any rotary lime kiln any
gases which:
(i) Contain partlculate matter in
excess of 0.15 kilogram per megagram
of limestone feed (0.30 Ib/ton).
(il) Exhibit 10 percent opacity or
greater.
(2) From any lime hydra tor 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.
kiln and the mass rate of lime feed to
any 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 subject
to paragraph (a) of this subpart is 10
percent or greater.
(a) The owner or operator subject to
the provisions of this subpart shall in-
-------
APPENDIX A - REFERENCE METHODS
The reference methods in this appendix are referred to in § 60.8 (Performance Tests) and
5 60.11 (Compliance With Standards and Maintenance Requirements) of 40 CFR Part 60, Subpart A
(General Provisions). Specific uses of these reference methods are described in the standards
of performance contained in the subparts, beginning with Subpart D.
Within each standard of performance, a section titled "Test Methods and 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 instructions (for example, establish sampling rates,
volumes, or temperatures) are to be used either in addition to, or as a substitute for proce-
dures 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 Appendix B.
Inclusion of methods in this appendix is not intended as an endorsement or denial of their
applicability to sources that are not subject to standards of performance. The methods are
potentially applicable to other sources; 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 reference 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 equip-
ment 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 recognized that alternative and equivalent methods exist. Section 60.8 pro-
vides authority for the Administrator to specify or approve (1) equivalent methods, (2) alter-
native methods, and (3) 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 disapproval
and retesting with approved methods.
Within the reference methods, certain specific equipment or procedures are recognized as
being acceptable or potentially acceptable and are specifically identified in the methods. The
items identified as acceptable options may be used without approval but must be identified in
the test report. The potentially approvable options are cited as "subject to the approval of
the Administrator" or as "or equivalent." Such potentially approvable techniques or alter-
natives 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 pro-
vided in the reference methods. Also, the potentially approvable options are not necessarily
acceptable in all applications. Therefore, an owner electing to use such potentially approvable
techniques or alternatives is responsible for: (1) assuring that the techniques or alternatives
are in fact applicable and are properly executed; (2) including a written description of the
alternative method in the test report (the written method must be clear and must be capable of
being performed without additional instruction, and the degree 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 Administrator's disapproval of the alternative.
111-35
-------
METHOD *—DITIIIMIK«TW>N or Svtnn
BsiiieiOM FBOM STATION*** 6uvK< i»
>• friactofc ana1 Amlittbttti
1.1 Principle. A gat temple U tslrarlr-d from the
•stapling point ID to* ttack. Tb« nilluiic acid mm
(including sulfur tnottdf) and tbt tulfur dlosjdt art
atparettd. Tbe euUnr Oloxide traction it measured by
UK barlum-tborln titration tnetbod.
1.3 Applicability. Thii method it applicable (or tbt
Aeur initiation o( tulfur dioxide emtatlont tram stationery
tources. Tht minimum detectable ItmJl ol UM mftbod
ha* bwo dcttrnilned to b» 1.4 niilligremii (nig) ol BCVm'
(tUXIO-' Ib'lt I). Alt bough DO upper limit bat been
eaiabliJhed, twu have ihown that ooncontrelloui at
high as 10,000 ingta* of SOi can b« collected ertidcntlj
io two midfft Imptngm, Moh containing 1.1 rulllu'ilm
•I 1 percent hydrogtn prroiidr. »1 * rate ol 1.0 Ipm lor
10 minute*. Beard on ibtorciK*) calculations. Ule upper
concentration Umlt In e 10-liter tamplt u about M4UU
•u'm>.
Possible InterftrtnU ere free ammonia water-eolublt
o»Uons, and BuoridM. Tlie cations and fluorides vr
remove. J by glass wool fillcrt and an l»oprop»nol bubblri,
•nd btncf do not eflfct the 8Oi analysis, w he n sampler
are brine taken Irom * fas it tram with uish conrtnln-
tlons ol very line metallic limits (nich as In Inlets to
control drTii'tel, a hich-flncifDcy glau ntitr filter muni
b* used lu plavt ol thf flaw wool plus (I.e., the one ID
thf prolfi to mnoTf thf ratiou inlcrdatntf.
Free ammonia initrltrft by reacting »ltl> 6O> lo form
MrtlculaK tulntr and by reacting wltb the Indicator.
u tin ammonia U preetnt (tblt can b« determined by
knowledge ol tht process and noticing white paniculate
Bat ur In th« prob* and teopropenol bubbler 1. alterna-
tive mulled*, auujivt to th* approval of tbf Aduiiuatra
<•, M.S. Bnviroimii nlal Protection Agrnry, are
required.
11 Bampllng, Tbe tampling train U ebown In rTrurt
W, and component part* an dtacuxead below. Tbe
teller bat tbe option of nbnltutlng tampling equip-
ment described In Method 1 In place of tbe mldgtt 1m-
(anger equipment of Method 6. However, the Mftbod I
train mutt bt modified to Include a heeled filter between
the probe and laopropanol Implnger, and tbe •operation
cf tbe templing train and aunplt analysis must be at
the Bow ratal and solution volumes denned In Method 8.
The tetter alto be* tbe option of determining BO,
asxoultaneoutly with paniculate matter and moltturr
determinations by (l) replacing the water In a Method 6
Implnger eyiUm with I pcrwnt perioxldt aolntlon, or
Os) by replacing tbe Method 1 water Implnger eyitttn
with a Method I laopronnol-Blter-peroxIde lyitem. The
analysis for BOi mutt be consiitent with tbe procedure
ta Method 1.
11.1 Probe. BorofuiceUglajt, or stalnlaas tteel (other
snelarlalt of construction may be uted, tobject to the
approval of tht Administrator), approximately 6-rnm
tnalde diameter, wltb a beating system to prtvtnt water
anodenaetlon and a filter (either lo-etack or heated out-
ttack) to remove paniculate matter, Including lulluric
add mitt. A ping ol rlaat wool It e ettlalactory Blur.
1.1.2 Bubbler and Implngen. One midget bubbler,
wltb medium-coarat glaas frit and borcalUcate or quart*
glees wool packed In top (tec Figure (-1) to prevent
enlfuric add mitt carryover, and three 10-ml mldgtt
teaplngrn Tbt babbler end midget Implngen matt be
aoaoecied In atriet wltb leak-fret glatt connecton. Bill-
cone mate may be need, If necessary, to prevent leakaf e.
At tbe option of tbe tetter, e midget Implnger may be
need in place of tbe midget bubbler.
Other collection absorbers and flow rates may be used,
Vat ere subject to the approval of tbt Administrator.
Alto, collection efficiency mutt be shown to be at leatt
N percent for each teat run and mutt bt documented In
the report If tbe efficiency U found to be acceptable after
a atriae of three tests, further documentation U not
required To conduct the efficiency tett, an extra ab-
aarbar mutt be added and analysed aeparately. This
aatn abaorber mutt not contain more than 1 percent of
the total BOi.
B.14 Qlaai Wool. BorotUloate or quarts.
1.1.4 Btopcock Oreaae. Acetone-Insoluble, beet-
gtablt tllicont greate may be uted. If naceewry.
1.1.6 Tamparatun Oaugt Dial tbarmometer. cr
equivalent, to measurt temperature ol gat leaving 1m-
•htar train to within 1' C Vft.)
ILl.e Drying Tube. Tube packed with 6- to Ift-memh
Indicating type dllea gel, or equivalent, to dry tbe get
1,1.10 Volume Meter. Dry gai meter, auffldently
aoourau to sneajurf thf aamplr volume within 2 percent.
eallbratn) at tht atlwted Bow ntr and condition.
actual)) eiioounterrd durtni eunplluf. and equipped
with a temperature (augt (dial thermometer, or equiv-
alent) capable ol meaturln| temperature to within
I*C («
tamplt and to protect tbe mater and pump, If tbe tjllac
nl ha. been utrd prevlouily, dry at 17t* C (U0> r) for
I noun. New allica |el may be tued u received. Alterna-
tively , other type* of dcalrcant* (equivalent or bett
•ay oe utad , tubject to approval of t be Administrator .
B.1.7 Value. Needle value, to rafulate eample |ai fl
tale.
S.1 J
Pomp. Leak-tree dJiphrafm pomp, or equiv-
, pull gti throuf b tbe train. IniiaU a amall tank
between tbe pump and rate meter to eliminate the
1.1.11 Barometer, Mercury, amerold, or other barom
eter oapablr of meanirlnf atmoiphertc preeturr lo within
14 mm H< (0 1 In HI) In many cam, thr baromttrtc
raadlni may bt obteJnud Irom a nearby national weather
•rvtoe tUtlon, In which caa* tht elation valur (which
• the abeoluu- baroinrtrlc praanirr) ehall bt rrqu«itrd
and an adluitment for eltvatlon dlflwtncr* bttwern
tbe weathnr nation end MmpMn* point ihall bt appllxd
at a rate of minus 2.S mm HI (0.1 In. Hi) per 80 m 000 ft)
elevation tncreaet or vice vena for eltTatlon decreaer
1.1.11 Vacuum Oauit. At lead 760 mm Bi (W In
Bf) lauff, to be need lor leak check of tbe eempUnt
train.
S.2 Bam pie Recovery.
1.1.1 Wash bottlee. Polyethylene or flaw, WO ml,
two.
1.2.X Btoraft Bottlet. Polyethylene, 100 ml, to ttort
Inplnier eamplee (ont per eample).
l.i Analysis.
14.1 Ptprtut. Volumetric typt, 6-ml, 10-ml (one per
eample), and 24-ml tU«>.
1.1.2 Volumetric Flaaki. 100-ml ilae (one per (ample)
and 100-ml tlae.
14.* Burettee. »- and 60-ml aliei.
14.4 Krlenmeyer Flaikt. 2M ml-elie (one for each
earn pit, blank, and itandard).
14.6 Dropplnt Bottle 126-ml iltt , to add Indicator.
I4.A Graduated Cylinder 100-ml all*.
t4.7 Bpectrophotometer. To meaeun abaorbance a
•U nanometen
TJrUec otberwlae Indicated, all reaffntt mutt conform
to the epoclncatloiu eatabllibrd by tbf Commlttrt on
Analytical Reaftnta of tbt American Chtmlcal Boclrt>
Where euch ipecl&catloni are not available, uae tbe best
avalUble fradt.
1.1 BampUnt.
1.1.1 Wettj/Df lonlied, dUtllled to conform to ABTM
epeclflcetion Dl 183-74, Typt 3. At tbf option ol tbr
analyit, tbf KMnOi teat for oilditablt ortanlc mattrr
may bt omltttid when high conccntratloiu of orgaiw
matter art not expected to ot prtw nt.
1.1.2 laopropanol, Kiptrctnt. Mu 80 ml of laopropanol
with 30 ml of delonlted. dlitlUrd water. Check each lot of
laopropanol for ptroiloV Impurltira as follows: lhakc 10
ml Of laopropanol with 10 ml of freshly prepared 10
percent potanlum Iodide eolution Prtpart a blank by
atmllarly treating 10 ml of distilled walfr. After 1 mlnutf ,
read tbf abaorhanct at Itl nanometers on a spectro-
pbotometer. If abeorbance eiceeds 0.1, rejfct alcohol for
net.
Peroxldts may be removed from Isopropenol by redis-
tilling or by panagt through a column of activated
alumina, nowtver, reagent gradt laopropanol with
anltably low prroilde Itveb may bt obtained from com-
mercial aouroM Rejection of contaminated lots may,
therefore, bt a more efficient prooedurr
1.14 E>drofrn Peroiidt, I Percent. DlluttSOptrccnt
hydrogen peroiide 1:» (v/v) with dtlonittd. diMiUfd
water (K ml Is nntdtd ptr aamplt). Prrparf frt»h dally
1.1.4 Potassium lodldt Solution, 10 Ptrcrnt. Diasolve
10.0 grams Kl In delonltrd, distilled water and dllut* to
100 ml. Prtpart when needed
1.2 Bamplt Recovery.
1.2.1 VYat«r. Dtlonlstd, dlftlUfd. as In 1 1.1.
1.2.2 laopropanol. Ml Perct nt Mil 80 ml ol iaopropanol
with X rol of drlonlted, distilled wattr
14 Analysis
«.» 1 Water Delonlied, distilled, as In 3.1.1.
14.2 laopropanol, 100 percent
144 Thorln Indicator. l-(o-arsonopbenylato)-Z
napbtho)-3,frdjjultenlc acid, djjodiujr, salt, or equiva-
lent. Olsaolve 0.20 g In 100 ml of delonised, distilled
water.
144 Barium Perchloratt Solution, 0.0100 N Dif
solve l.U g of barium perchloratt tribydrate [Ba(r lOili
IHrOI In aoo ml diiUUed water and dllut* to 1 Ul*r with
npropenol. Alumatlvely. I 22 1 of [BaClr2HiO| ma>
be need Instead of tbe peicbkirate Btandardite at In
Section 6.6.
14.6 Bulfuric Acid Standard, 00100 N. Purchase or
standardise to *0 0002 N against 0.0100 N NaOH which
bat previously bttn standardlted against potaeslum
add phthalate (primary standard grade)
polattloD effect of toe
of toe diaphragm pump on tht rotameter.
eter. Rotameter, or equivalent, capable
4.1 Sampling
4.1.1 Preparation of collection train. Meenire 16 ml of
K perctnt isopropenol Into the mlditet bubbler end 16
ml Ol 9 percent hydrogen peroildt Into each of the first
two mlagft Implngen Ltevt tht final midget Implnger
dry. Assemble the train es shown In Figure
-------
6.2 Thermometers, Calibrate afalnst
flu thermometan.
1.1 Rotameter. The rotametar need not b* calibrated
bat should be cleaned and maintained accordlnf to the
manufacturer'! InitrueUon.
i.4 Barometer. Calibrate afalnst a mercury baram-
•Ur.
»J Btrlum Pvchlorate Solution, Standardise tbt
barium pweblonu lolotlon anlnit 2} ml o( standard
ml/uric teld to which 100 ml of 100 percent unpropuol
hai b**0 added. ^^
* ?lf"»flf(flf
Carry ont calculations, retaining tt least on* utn
decimal flfun beyond that of the icqulnd data. Round
off Bfurw after final calculation.
t-1 Nomenclature.
Cm• Concentration of nlfur dioxide, dry bails
' eomcMd to tundard oondJUoru, mg/dMrn
. (Ib/daef).
N-Normality of barium ptrchlonu tltnnt,
mllllequlTalenti/inl.
Fk«>Btron»u1c prtosurt »t tbe ult ortfltn of tht
dry ni mttcr, nun Ii| (In. B|).
/>M4»8uniurd abwluu pnuurc, 760 nun Hf
(29.92In. H|).
r.-AT«r*|f dry |u meter kbeolutc Umpwmtnn,
•I (*R>.
Tiu-Bundvd »b«oluU UmperMnre, Vf K
(5»* R).
V.-Volomt ofMunple aliquot Utrmted, ml.
V»- Dry fie Tolnme at nuaeond by the dry t»
' , dem (dcf).
V.Ue)-Dry fas Totume meanirad by the dry fas
meter, oorrecud to standard conditions,
V«i.-Total Tolume of eolation In which tbe sulfur
dioxide sample Is contained. 100 ml.
Vi«Volume of barium pcrehlorale tllrant used
tor tbe sample, ml (aTerafe of repUeau
tltntlons).
Vi.-Volume of barium pareblonU tllrant uaed
for the blank, ml.
V- Dry fas meter calibration factor.
K.n- EqulValent wellht of sulfur dioxide.
13 Dry sample fas Tolume, corrected to standard
conditions.
/m\/p\ V P
V v " « i- • ' •"' > —v v " •"
'•(lld>~"»
KqoattoD (-1
If i-O BH •K/mm Hf tor mMrk onlu.
-17.M'R/ln. H« for EnfUih unit*.
<4 Bulfur dioxide eonotntimtkm.
wherf:
Jfi-12.03 mi/meq. tor metric unlU
-7.081X10-* lb/m*q. far Knf Uib onlu.
Iqoatloo »-3
I. Atmoipherlc Emlalora from Bulfurle Add Manu-
toeturtns ProcMM. U.S. DUf.W. PH8. DlTlilon of Air
Pollution. Public Health Serrlor Publication No.
9W-AP-I3. Cincinnati, Ohio. 1984
2. Corbrll, P. T. The Determination of BOi and BOi
In Flue Qaaw. Journal of the Institute of fuel.U 217-
1U, IM1.
«. Matty, R. E. and E. K. Dlehl. Measuring Flue-Oas
BOi and BOi Power. 101: tt-VI. NoTember 1M7.
4. Patton, W. F. and J. A. Brink. Jr. New Equipment
and TechnlquM for Sampllnf Chemical Procew (iasn.
I. Air Pollution Control Association IS 1«2. 1963.
I. Rom. J.;. Maintenance, CaUbralIon,and Operation
of laokirutlc Soune-Sampllnf Equipment. OfBce of
Air Protrrmms, Enrlronmental Protection Aiency.
Billlret Trtanfle Park, N.C. APTD-0676. March 1972.
(. Hamll, H. F. and D. E. Camann. CollaboratlTe
Study of Method for tht Detcrmlnal ion of Sulfur Dloilde
Emlssloru from Siallonary Source* (Fossil-Fuel Fired
Bteam Oenerators). EnTlronmental Prolecllon Afency,
Research Trlanfle Park, N.C. KPA-oM/*-7«-OM.
DMember 1971.
7. Annual Book of ABTM Standards. Part 11. Water,
Atmospheric Analysis. American Society for Tettlnf
•lid Materials. Philadelphia, Pa. 1974. pp. 40-13
I. Knoll, J. E. and M. R. Mldfelt. The Application of
EPA Method 8 to Hlfh Sulfur Dloiide Concentrations.
Knrlronmental Protection Afency. Reasarch Trlanile
Park, N.C. EPA-«00/4-76-OtB. July 1(T7».
PROBE (END PACKED
WITH QUARTZ OR
PVREX WOOL)
X
THERMOMETER
STACK WALL
MIDGET IMPINGERS
MIDGET BUBBLER
GLASS WOOL
SILICA GEL
DRYING TUBE
ICE BATH
THERMOMETER
RATE METER NEEDLE VALVE
PUMP
Figure 6-1. S02 sampling train.
SURGE TANK
111-37
-------
7—DmutnunoN or Nimoom Oxn>i
BnMONI FtOal frUTJOHABT SOWM
I* ftintlfti tut 4 fftififrffto
I.I Principle. A fr»b tampU li collected In »n ***oa-
•led Ouk oonUlnint t diluu wUurlo tcld-bydroten
pondd* abMrblru nluUon, tnd th* nitrogen oiimt,
•wpt oitroui end*. tr» measured oolorlmeUrlotlly
•tag th. phwtoldiiuUonle Mid procedure.
t J Applicability. Thb method li applicable to the
•MMurtmnt of rUtrojen oxide* emltud
Tbt ranee o/tb* method. hti bMB determined
to b* > to 400 mUUfnmf NO. (uNOi) par dry (Undard
•able motor, without hartal to dUnl* thetampta.
II «t-'pl''!t (M Figure 7-1). Other |rmb tmmpllni
•yttomj or equipment, otpabt* of meaiurtng ttmpk
want to within atlO ptrerat and ooUecUng t lumelut
•tuple Tolumt to allow analytic*) raproduclbltlt* to
within *6 percent, will b» oootldared acceptable altar-
MtlTM, nibfoet to •pproTd of tb* AdmlnlttrMor, U.S.
Bo*lnanuoUI ProUcUoo Aftooy. Th« (oUowiof
•qalpmont U ai*d In »mpUof :
11.1 Prabt. BomlllokU flM toblni, niOelootly
hMt»d to pnriot wttar flond«n»Uon wd •qulppod
with to la-«Uek or oat^Uek UUr to r»mo« pwueubt*
mttUr (• Dlui of ilMi wool U MtUAetory for tUi
parpoM). BUlalMi I(M| or TtOon ' tublai BUT tl» b«
a*td far tb« prob*. B«ttn( U not UOMHIT
nnuUn* dry darlnc tb* paiftnf pviod.
UT tl» b«
UM ptob*
> Mutton of tnd* nuD« «iptalflo pndMto don not
tnoMtat* *odonuiMDt by th* lovlnaBooUl no-
11J Collection Fla*k. Two-liter boroalllcau. round
bottom na*k, with ihort neck and 24/40 ttandard taper
op*nlng,jprotwt*d again*! Implmion or breaker
II.) Flask Yalvr T-borr ilopcock connected to a
SV40 llandard Utprr Joint
11.4 Temprralurr Oaugr. DleHypr thermometer, or
other Umprraturr tauyr, capable of meanurlng 1* C
(t* F) Interval! from -t to M/ C (2A to US' F). .
II.t Vacuum Llnr Tubing capable of wUniUndlng
t vacuum of 76 mm 1U (3 In Hg)*n»olut* pn*jun,w1in
"T" connection and T-bort ttopcock
11.6 Vacuum O*u»r V-iuW manomeKir. I m*l«r
(M In.), with 1-mui (O.l-ln.) diTlaloru, or othrr
•tptblr of meaiurlog preaiure to within i.3.6 mm
(0.10 in. Hgi.
1.1.7 Pump. Ctpablr of eracnaUn! thr collection
flttk to a pratnir* equal to or lea than 74 mm Ug (1 In.
Hi) tbtolutr.
5.1.K Equmr Bulb .One-way.
1.1 V Volumrtnc Plprtu. 2& ml
11.10 Siopcock and Ground Joint Qraaar A high
vacuum, high irmprraturr chlorofluorocarboc grraar I*
required Halocarbori IViB hai b«rn found to be rflnctlTr.
ll.ll Baromrtir. Mercury, anrrold. or olhrr barom-
otor capablr of mraiurinj atinoephrrlc prraiurr to within
2.1 mm lie (0.1 In. He). In many caori, thr baromrlrtc
reading may br obtalnrd from a nearby national weatbrr
tamer niatlon. In which caer thr iletlon Talur (which U
the abnolutr barornrtrlc praaturi') (hall br requnt*d and
ao adliutmrnt for elrvatlon dlfTcrrnc«t between tbr
weatlirr dial ion and sampling polni ihall br appllrd at a
rau of minus 2.5 mm H( iO i in. URI prt w m (100 ft)
iteration Incretw, or Tier Trn* for rlrration decreaar.
12 Sample Rroovfn. Thr following equipment to
required for aamplr recovery:
1.2.1 Oraduatad Cyllndrr. M ml with l-ml dlTljloni
.1-3-2 Storaf' Containers. Leak trae polyetbylenr
IMtlet.
2.2.S Wub Bottlr Polyetbylenr or flaw
2.2.4 Olan BUrrlnf Rod.
1.2.5 Te>t Paper for Indlottlnl pH. To eorer tbe pR
natron to 14,
1.3 Analyilb For lh« antlyaU, tbe tollowlni eqnlp-
•ent li needed
1..V1 Voliunetrtr Plpettei Two 1 ml, two 2 ml, onr
I ml, one 4 ml, two 10 ml. tod onr 2A ml lor each aamplr
and etaodard.
U.J Poroelaln ETtpormtinf Dlihei 176- to 2AO-ml
oaparltf with Up for pourtnf, on' for each aamplr and
each nandard. Th' Coon No. 4.VXX, (ihallow-form. IU.'<
ml) ha» bern found to b» ntlifartory Alteniatl*cl),
polyrnrthyl pmlrnr beakm (Naif No I20.'l. 150 ml), or
flaaii ixvkrn (140 ml) may br tu«d. When flau beaker
•rr used, rtehint of thr rieakrn may cauv nr>lid matter
to br prmrnt In the analytical stru tbr aolldi abould b«
removed by filtration (eer Section 4.9).
2.* * Blf«m Bath Low-Umprralurr OT«ni or thermir
tutirally rontrollx) hot plain kept b«)ow 70* C (160* F)
air arx'fipubli' altrrnatlva.
l.X Dropping Plpriuor Droppn. Tbrer required
2J .•> Folyrthylrnr Pollorman. One for each aampk
and each rtandard
2.1
-------
Unless otherwise Indicated. It Is Intended that til
nsafents conform to the specifications established by the
Committee on Analytical Reagents ol the, American
Chemical Society, where such specl Bastions are avail
Able; otherwise, use thf bat available grade,
1.1 Sampling To prepare thf absorbing solution,
•MHIously add 28 ml concentrated HiSOi to 1 liter of
•Monitrd. distilled water. Mil well and add « ml ol 8
parcent hydrogen peroxide freshly prepared from M
perceni hydrogen peroxide solution The absorbing
solution should he used within I week of III preparation
Do not eipote u> rat/erne heal or direct tunllghl
•J Sample Recovery. Two reagents »r* required lor
sample recovery
•.2.1 Bodlum Hydroxide (IN) Dissolve 40 | NsOH
Is delonlied, distilled water and dilute to 1 liter
1,2.2 Water DeionlsecT distilled u> conform to A6TM
•pacification D11B3-74, Type I. At the opUon of the
analyst, the sTMNO, tact lor uldiiable OTimnlc matter
mij be omitted when high concentrations of organic
matter ire not expected to De present
S.J Analysis For the analysis, the following raatenlf
are required:
HI Fuming Bulfuric Acid. IS to J6 percent by weight
tr»* aulfur trioxide HANDLE WITH CAUTION
{.|.J Phenol Whit* solid.
.|.t Bulfunc Acid Concentrated, 85 percent mini-
pom assay HANDLE WITH CAUTION.
II 4 Potassium Nitrate Dried at 105 to 110° C (7»
to 230C F) for a minimum of 2 hours Just prior to prepara
tion of standard solution.
IS', Standard KNOi BoluUon Dissolv* uactly
J-18S F of dried potassium nitrate (KNOii in drionited.
distilled water and dilute to 1 liter with deioruuid.
dlshlh ^ water in a 1,000-ml volumetric flask
S.J.8 Working Standard KNOi Solution Dilute 10
ml of ». t standard solution u> 100 ml with deionited
distilled'water. One mlUiliter of the working standard
aolution Is equivalent to 100 m nitrogen dioxide (NOi)
1.3.7 Water Deiomted, distilled as in Section 3.2.:
1.38 Pbenoldtsul/onic Acid Solution Dissolve 25 I
ol pure whit* phenol in ISO ml concentrated sulfurk
acid on a suam bath Cool, add 75 ml fuming sulfurir
acid, and beat at 100° C (212" F) lor 2 hours Store In
a dark, stoppered bottle.
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
pound glass Joints have been properly (Teased with a
high-vacuum, high-temperature chloroflnorocarbon-
Nued stopcock grease Turn -the flask Talve and the
pump valve to their "evacuate" positions Evacuate
the flask to 75 mm Hg (3 In Hg) absolute pressure, or
fens 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 nia-
nomeUr tor any pressure fluctuation (Any variation
greater than 10 mm Hg (0.4 In Hg) over a period of
1 niinuU 1» not acceptable, and the flask Is not to be
-used until the leakage problem It corrected. Pressure
In the flask is not to exceed 75 mro Hg (3 in Hg) absolute
at the time sampling is commenced.) Record the volume
of the flask and valve (V/), tbe flask temperature (7,1,
and tbe barometric pressure Turn the fla.sk valve
counterclockwise to Its "purge" position and do the
same with the. pump valve. Purge the probe and tbe
vacuum tube using tbe squeeie bulb If condensation
occurs in the probe and the flask Talve area, heat the
probe and purge until the condensation disappears
Kert, turn the pump valve to its "vent" position. Turn
the flJL'k valve clockwise to Its "evacuate position and
rrcord tbe difference in tbe mercury levels in the manom-
eter. Tbe absolute Internal pressure In tbe flask (/M
Is equal to the barometric pressure less the manometer
reading Immediately turn the flask valve to tbe "sam-
ple" position and permit the gas to enter tbe flask until
pressures In the flvk 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 samplmt is continued After
collecting the sample, turn the fla.'k valve to Its "purge"
position and disconnect the flask from the sampling
train Sbtke tbe flask for at least 5 minutes
4.1.2 I/ the gas being sampled contains Insufficient
oiygen for the conversion of NO to NOi (e.g , an ap-
plicable subpart of tbe standard may require taking a
sample of a calibration gas mixture of NO In Ni). then
oiygen shall be introduced into the flask to permit this
conversion Oxygen may be Introduced into tbe flask
by one of three methods, (1) Before evacuating the
sampling flask, flush with pure cylinder oxygen, then
•vamaie flask to 75 irun Hg (J in Hg) absolute pressure
or less, or (2) Inject oiygen into the flask afier sampllnc.
of C8) terminate sampling with a minimum of 60 mm
Hg (2 In Hg) vacuum remaining In tbe flask, record
this final pressure, and then vent tbe Bask to tbe at-
mosphere until tbe flask preasun Is almost equal to
atmospheric pressure.
4-2 Sample Recovery Let tbe flask set lor a minimum
af le hours and then snake the contents lor 2 minulee
Connect tbe flask to a mercury filled U-tub* manometer
Open the valve from the flask U> the manom«ter and
record the flask tomnmture (TV), the barometrir
pressure, tod tbe dlflerence between the mercury levels
D the manometer Tbe absolute Internal pressure In
UM flask (Pi) Is tbe barometric pressure less the man-
ometer reading Transfer the contents of the flask to a
ssak-free polyethylene bottle Rinse tbe flask twice
with 6-ml portions of deionited, distilled water and add
tbe rinse water te tbe bottle Adjust the pH U> between
I and 12 by adding sodium hydroxide (1 N), dropwlse
(about 25 to 15 drops) Check the pH by dipping a
stirring rod Into the solution and then touching the rod
totbepH 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 Identity IU
contents Beat tbe container lor snipping
4 J Analysis Note the level of tbe liquid In container
and confirm whether or not any sample was lost during
shipment; note this on thf analytical data sheet. If s
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 tbe
shipping container to a SO-ml volumetric flask, and
rinse the container twice with 6-ml portions of deionited,
distilled water. Add tbe rinse water to tbe flask and
dilute to tbe mark with deionited, distilled water; mix
thoroughly. Pipette a 25-ml aliquot Into tbe prooelain
evaporating dish. Return any unused portion of tbe
sample to the polyethylene storage bottle. Evaporate
tbe ZS-ml aliquot to dryness on a steam bath and allow
to cool Add 2 ml phenoldisulfonic acid solution to the
dried residue and triturate thoroughly with a povlethyl-
ane policeman. Make sure the solution contacts all the
reaidue. Add, 1 ml deionited, distilled water and four
drops of concentrated sulfunc acid. Heat the solution
on s steam bath for 3 minutes with occasional itirrtnf
Allow tbe solution to cool, add 2tJ ml deionited, distilled
water, mix well by stirring, and add concentrated am-
monium hydroxide, dropv/ise, with constant stirring.
until tbe pH Is 10 (as determined by pB paper). If tbe
sample contains sohds, these must be removed by
filtration (centrifugation Is an acceptable alternative.
subject to tbe approval of tbe Administrator), as follows
filter through Wbatman No. 41 filter paper Into a lOOml
volumetric flask: rinse the evaporating dish with three
6-ml portions of deionited, distilled water; filler these
three rinses Was)) tbe filter with at least three 16-ml
portions of deioniud. distilled water Add tbe filter
washings to tbe contents of the volumetric flask and
dilute to the mark with deionited, distilled water. If
solids are absent, the solution can b« transferred directly
to the 100-ml volumetric flask and diluted to tbe mark
with deionitrd distilled wales. Mix the contents of the
flask thoroughly, and measure tbe absorbanoe at tht
optimum wavelength used for tbe standards (Section
6 J.I), using the blank solution as a tero reference Dilute
tbe sample and tbe blank with equal volumes of delon-
Ised, distilled wster if the absorhance exceeds A., the
absorbance of the 400 |ig N Oi standard (set Section 5.2.2) .
t Ckilbrtltm
II Flask Volume Tbe volume of the collection flasl
flask valve combination must be known prior to sam-
pling Assemble the flask and flask valve and fill will
water, to the stopcock Measure the volume of water to
±10 ml Record this volume on tbe flask.
£.2 Bpectrophotometer Calibration.
s.S.l Optimum Wavelength Determination. For both
filed and variable wavelength spectrophotomelers.
calibrate against standard certified wavelength of 410
nm, every t months Alternatively, for variable wave
length spectrophotometprs. scan the spectrum between
400 and 416 nm using a ZOnjig NOt standard solution (see
Section 6,2.2) If a peak does not occur, tbe spectropho-
tometer Is probably malfunctioning, and should be re-
paired When a peak It obtained within the 400 to 416 nm
range, the wavelength at which this peak occurs shall be
tbe optimum wavelength for the measurement of ab-
sorbance for both the standards and samples.
122 Determination of Epeclrophotometer Callbra
tion Factor K, Add 00, 1.0. 2 (1. SO. and 4.0 ml of the
KNOi working standard solution (I ml-100 *g NOi) to
a series of five porcelain evaporating dishes. To each, add
It ml of absorbing notation. 10 ml deionited, distilled
water, and sodium hydroxide (IN), dropwise, until the
pH Is between t and 12 (about 29 to Si drops each).
BefinrmiK with the evaporation step, follow the analy-
sis procedure of Section 41, until the solution has been
transferred lo the 100 ml volumetric flask and diluted to
tbe mark Measure the absornance of each solution, at the
optimum wavelength, as determined In Section 6.2.1.
This calibration procedure must be repeated on each day
thst samples are analyte<1 Calculate the spectrophotom-
ft«r calibration factor as follows.
a.S Vacuum Oaugr Calibrate mechanical gauges. If
used, aialnst a mercury manometer such as that speci-
fied In 2.1.«.
S.« Analytical Balance. Calibrate against standard
wstfbls.
Carry out the calculations, retaining at least one extra
decimal figure beyond that of tbe acquired data Round
off figures after final calculation*
el Nomenclature
X-Atnorbanc* of sample
C-Concentralion of NO, as NOi. dry basis, cor
reeled U) standard conditions, mg/dscm
(lb/dscf) ,
••-Dilution factor (I e., »/8, a.'IO, etc., Nqillrrd
only If sample dilution was needed to redder
the absorbance Into tbe range of calibration)
Jfr—Bpeclrophotomeler calibration factor
w-Hsvi of NO, as NOi In gas sample, «
P/" Final absolute pressure of flask, mm Hp (in Hi)
P, -Initial absolute pressure o( flask, mm H( (in
He)
F.u -Standard absolute pressure, 780 mm Hg (29 92 in
He).
T/- Final absolute Itmperalure of flask ,°K (°R)
Ti-Inltial absolute temperature of flask °K <°Hj
T..d- Standard absolute temperature, 293C K (628" R)
I',, -Sample volume at standard conditions (dry
basis) , ml
V/-Volume of flask and valve, ml
V«« Volume of absorbing solution, 2fi ml
2 -60 '24. the aliquot factor. (If other than a 24- ml
aliquot waft used for anah'sr, tbe correspond-
Ins factor must he substituted)
(.2 Sample volume, dry basis, corrected to standard
conditions
Equation 7-1
wfaare;
JT, -Calibration factor
Xi- Absorbance of the lOO-* NOi standard
Xi-Abtorbanoeoftbt 200-* NO, standard
At- Absorbanoe of the 300-vl NO, standard
X4- Absorbanoe of the 400-«g NOi standard
1.1 Barometer. Calibrate against t mercury barom-
eter.
1.4 Temperature Gauge Calibrate dial tharmome:ert
against mercury-ln-class thermomeUn.
v «jy
v"
where:
A', = 0.3858
'
°K
-=17.64 r
C.l Total
mm Hg
°R
Equation 7-2
for metric units
in. Hg
NOi per sample.
for English
Equation 7-3
NOTE.— If other than a 2i-ml aliouot is used for analy-
sis, the factor 1 must be replaced by a corresponding
factor.
S.4 Sample concentration, dry basil, corrected to
standard condition!.
C-K,
m
V7.
Equation 7-4
where
JC,-iO> 5! ?/5£ for metric units
-6.243X 10-» '-^ '— f for English units
Mg/ml
7. BtUiotrtttkl
1. Standard Methods of Chemical Analysis. Cth ad
New York, D. Vna Nostrand Co., Inc. 1862 Vol. 1,
p. S20-330.
1. Standard Method of Test for Oxides of Nitrogen In
Oaseous Combustion Products (Phenoldisulfonic Acid
Procedure). In: 196S Book of ASTM Standards, Pan 2C
Philadelphia, Pa. 1968. ASTM Designation D-1608-60,
p. 715-728.
1. Jacob, M. B. Tbe Chemical Analysis of Air Pollut-
ants. New York. Inlersclence Publishers, Inc. I860.
Vol. 10, p. U1-3S6.
4. Beatty, R. L , L B. Berger, and H. H. Schrenk.
Determination of Oxides of Nitrogen by the Phenoldisul-
fonic Acid Metbod. Bureau of Mines, U.6. Dept. of
Interior. R. I. K87. February 1843.
6 Hamll, H. F. and D. K. Camann. Collaborative
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 6, 1ST3.
6. Hamll, H. T. and R. E. Thomas. Collaborative
Study of Metbod for the Drtennlnstion of Nitrogen
Oxide Emissions from Stationary Sources (Nitric Acid
Plants). Southwest Research Institute report for En-
vironmental Protection A««ncy Research Triangle
Park, N.C. May 1, 1974.
I T I - 3 9
-------
MITHOO a-DsTtaiiiNATioN or SDIIVUC AOD Mifi
AND SuLfUi DlOXIDI iMUtlONI F«OM BtlTIONAkT
BOUtCM
1. frlndplt
pit iiU Xp,
1.1 Principle A gas sample U estrartad Isoklnellcally
from Ihe stack. The lullunc Kid mJn (liicludinf nillur
uloildc) and lh« sulfur dloiido are separated, and both
fraction! are measured separately by Ib* bariuni-lhorin
U tret Ion method.
1.2 Applicability. Tlili method Is applicable (or tb>
determination ol lullurlc acid nil it (Including nilhir
trioude, and In the absence ol other paniculate tnatur)
and tullur dloilde emissions from ilailonary soureea.
Collaborative teili have iliown that the ruiiUmum
detectable limiu ol the method ere 0 OS mlllltTami/cubie
meter (0.03> Iff-' pounds/cubic lo.il) lor luilur trtoilde
and 1.2 m|,m> (0.74 10 ' Ih.'li'l lor sulfur dioilde. No
upper limits have been e«talilishcd. bawd on theoretical
calculations lur 2UO mlllililcrs ol a percent hydrofen
peroiide solution, the upper concentration limit lor
sulfur dioiidf In a 1.0 m' (36.3 It') ias aainple il about
12,400 mj'mi (7.7X10-' Ib.'ll"). The upper limit can be
extended by Increasing the -fl.'>;« Since' correct
IUOKC U Iniporlant In obtaining valid resulls, ell userv
ihuultl r.ad thu AfTD-0,',78 ilu un:. m and adupt tbe
opcrailnn and malnn'iuincr |ir,«., Jurcj outlined In U,
unless ol her wist >|>.Tirii'd ho Unrr. UorOdlllcHl t\ or <|iiant clou, with a
hrailni; jyilcm to iirrvcnt vlilUr i-ondnuiauon durlni
aunpUnii Do not UK metal probe liners.
2.1.3 I'liot Tub* Same as Method 1. Section 2.1 3
114 Differentia) Prcasun Oau«r Bame an Method «.
•eclloo 2.1.4.
2.1.8 FlltM Bolder Boralllcale |U». with a Rlav
ttt niter support and a illlcone ruhher |»ket Other
fatkel materials, e.|.. Teflon or Vlton, may be used sub-
ject Ui the approval of the Admlnlsiratoi. The holder
diditn shall provide a positive ami against leakage from
tbe ouUlde or around tbe Biter. The filter holder shall
be placed between trie Ant and second Implnners. Note
Do not heat the Alter holder.
2.1.6 Implnien—Fouj. ae shown In Flfure a-i The
tret and third shall be ol tbe. Oreonhurn-Bmllh dml«n
with standard tips. The second and fourth shall be of
tbe Orocnbujt Smith dee>t|rn, modified by nplarlnt the
luert with an approilmalrly 13 millimeter (O.i In.) ID
flaw tube, having an unconitriried tip locat*d 13 mm
(O.i In.) from the bottom of the flask (Similar collection
fraleme. which have been approved by the AdmlnU
tralor. mar b« nsed.
1.1.7 Metcrlni ByiUm. Bame as Method S, Section
2.1 J Barometer. Bame ai Method t, Section 2 11
2.1.9 Oa» Density Determination Equipment. Bame
M Method S, Section 2.1.10.
2.1 10 Temperature Oaufe. Thermometer, or equiva-
lent, to mMMure tbe temperature of tbe gas leavlni tbe
Isnpint«r train to within l« C (T T).
12 Sample Raeovcrr.
TEMPERATURE SENSOR
THERMOMETER
PROBE
~7
REVERSE TYPE
WOT TUBE
,CHECK
VALVE
PITOTTUIE
TEMPERATURE SENSOR
VACUUM
LINE
VACUUM
GAUGE
MAIN VALVE
MY TEST METER
Figurt 8-1. Sulfuric acid mist sampling train.
111-40
-------
*.» t *F*!h Bottle*. PolyMbyWoe or glass, 100 ml.
(two'.
Z.2.3 Graduated Cylinders HO ml, I UUr. (VohT
•»tric flaskj may also b« UMd.)
U.I Storage BotUet. Leak-tree polyethylene boltlsa.
1000 ml KM (two lor each sampling mn).
1.24 Trip Balance JOfHrrajn capacity, U> mearore to
*O.J I (necesaary only U * moisture content analysis I*
to be done).
2.3 AnalyilS
5.31 Pipettes. Volumetric 25 ml, 100ml.
it.) Burrellr.K) ml
1.3.9 Krlemneyer Flask ISO ml. (one for each sample
blink md standard).
2.1 4 Graduated Cylinder. 100ml.
2.1 5 Trip Balance. SCO g capacity, to measure 1C
*O.S|.
2.1« Dropping Bottle. To add Indicator solution,
12.VmlalM.
t. RrtfnU
Un)e.« otherwise Indicated, til reagent* are to conform
to tht1 spe< locations Miabllsned by the Committee on
Analytical Reagents of the American ChfmlcaJ Society,
where tiich specifications are available. OlberwiM, oae
the best available grade.
1.1 Sampling.
1.1.1 Filters Rame »s Method S. Section 3.1.1.
1.1.2 Bllica Or) Bune u Mrlhod 6, BfXtlon 3 1.2.
>.l 8 VViUr Drlonltrd. dljtlllMl to conform to A8TM
ipodflcatlon D1IV3-74. Typr I. At the option of the
analyst, tbf KMnOi t«9t (or oxldltable orfanlc matlrr
•ay b« omitted when blfb eoneentrmtloni at orfanlc
nailer are not eipectrd to M pretent.
that
On
1,1 4 laopropanol. M Pereant. Mix Km ml of Isopro-
paool with 100 ml of delonlted, distilled water.
NOTE.—Experience has shown that only A.C.B.
laopropanol Is satlafactory. Tests have shown
laopropanol obtained from commercial sources
easlonally has peroxide Imparities that will
roneously high sulfurlc acid mist measurement.
the following t«st for detecting peroxides In aacb lot ol
laopropanol Bbake If) ml of tbe Isopropanol with 10 ml
of freshly prepared 10 percent pouunlum loJIde solution.
Prepare a blank by similarly treating 10 ml of distilled
water. After I minute, read the ansnrbance on a speciro-
pbotometer at tol nanometen. If the absorbane* eiceedj
0.1. tbe Isopropanol (hall not be used. Peroxides may be
removed from Isopropanol by redistilling, or by passage.
through a column of activated alumina However, re-
agenUgrade Isopropanol with suitably low peroxide levels
to readily available from commercial sources; therefore,
rejection of contaminated lots may be more efficient
than following tbe peroxide removal procedure.
1.1.5 Hydrogen Peroxide. 1 Percent. DUnt* 100 ml
•I M percent hydrogen peroxide to I liter with dalonlaad,
dittUled water. Prepare freah dally.
1.1 8 Crushed Ice
1.2 Sample Recovery.
1J1 Water. Bame as 1.1.1.
1.2.2 Isopropanol, SO Percent. Buna u 1.1.4.
1.1 Analysis.
1.31 Water. Same as 3.1.3.
1.1,2 Isopropanol, 100 Percent.
1.1.3 Thorln Indicator. l-(o-arsonophenylaio)-2-oapb-
tbol-1, Wuulfonlc acid, dlsodlum salt, or equivalent.
~ re 0.20 g In 100 ml of delonlted. distilled water
1.14 Barium Perchlorate (0.0100 Normal). Duaolve
I. H| of barium perehlorau lr1hydrale(Ba(CIOi)ra(IiO)
ID 200 ml delonlted. dlftllled water, and dilute to I liter
with laopropanol. 1.23 I of barium chlorlrtr dlhydraie
(BaCli 2HrO) may be Html Inilaad of the barium per
atlloratr Btandardlie wHb •olfurlc acid an In Section e.?
Thli jolulkm molt be protaotad afalrut eraporaUon at
alltlmel
1.1 5 Bulfurtc Aeld Standard (00100 N). Purchaae or
itandardlu to ±0.0002 N afalrut 00100 N NaOH that
hai prrflouily been standardiud afalnit primary
standard pouaalum acid phthalate.
4. Practdurt
4.1 Sampling.
4.1.1 Pretest Praparalion. Follow the procedure out-
lined in Method 5. Bex-lion 4.1.1: flllrra should be In-
upecird. but need not be desiccated weighed, or Identi-
fied. If the effluent gas ran be considered dry. I.e., mois-
ture free, the silica gel need not be weighed
4.1.5 Preliminary Determinations Follow the pro-
cedure outlined in Mrlhod 5, Section 4.1.2.
4.1.3 Preparation ol Collection Tram Follow the pro-
cedure outlined in Method 5, Section 4.1 3 (eicrpi for
the second paraerApri and other obviously inapplicable
parts) and uw Figure 8-1 instead of Figure 5-1 Replace
the second paragraph wltb: Place 100 ml of 80 percent
Isopropanol in the Ant Impinger. 100 ml of 3 percent
hydrogen peroiide In both the second and third Im-
plngeri. retain a portion of each reagent tor us* as a
blank solution. Place about 200( of silica gal In tbe tonrth
Implrurer.
M.ANT.
LOCATION
OPERATOR
DATE
RUN NO
SAMPLE BOX NO.
METER BOX NO..
METER A Hf
CFACTOR
P1TOT TUBE COEFFICIENT, Ca.
STATIC PRESSURE, mm H| (hk H|)
AMBIENT TEMPERATURE
BAROMETRIC PRESSURE
ASSUMED MOISTURE. X
PROBE LENGTH, m (ft)
SCHEMATIC OF STACK CROSS SECTION
NOZZLE IDENTIFICATION NO
AVERAGE CALIBRATED NOZZLE DIAMETER, I
PROBE HEATER SETTING
LEAK RATE, mS/miri^elin)
PROBE LINER MATERIAL
FILTER HO.
nlifO.
TRAVERSE POINT
NUMBEF.
TOTAL
SAMPLINC
TIME
Wl. mi*.
AVERAGE
VACUUM
on H|
(ia.HfJ
STACK
TEMPERATURE
ITS).
*C (*F)
VELOCITY
HEAD
(A P$l
•WHJO
(la. H:0)
PRESSURE
DIFFERENTIAL
ACROSS
ORIFICE
METER.
mrnHjO
(in. HjO)
6AS SAMPLE
VOLUME,
•J (ftJ(
•AS SAMPLE TEMPERATURE
AT DRY GAS METER
INLET.
•C <»F)
Avg
OUTLET,
•C(»F»
Avg
Avg
TEMPERATURE
OF GAS
LEAVING
CONDENSER OR
LAST IMPINGER,
•C (»F)
Flout.(V2. FltlddtU.
111-41
-------
Non.-If moisture content to to b* determined bjr
Implnjer analysts, w*lf h **ch ol th* ftnt tore* tmplntnv
(Dimabsorblnfjolutlon) toth*n«ar*tt0,»gand record
that* weights. Th* w*lght of tb* silica 1*1 Tor illloa gel
plus container) miut al*o b* d*tormln*d to thi n*ar**t
C.J | lad recorded.
4.1.4 Pretest Uak-Ch*ek Proosdun. Follow UM
bMle procedure outlined In Mtthod 5. Section 4.1.4.1.
noting that tht prob» h«»Ur shall b* adjusted to tb*
minimum temperature required to prevent oondenia-
UOO. Mid also that VWbBg* lUCh U. '* ' ' plugging to.
latet to tb. lUUt bold«r • • V ihall b« replaced by.
plugging tht laltt to th* first Impinfsr • • V*
Tb* pnt*sTl*tI-«lMek Is option*!.
4.U Tnln OpmUon. Follow tb* basic procedures
ottttliwd In Method >. Section 4.1.4. ID conjunction with
tb* following special Instructions. Data shall b« mordtd
« • sb**t similar to tb* on* to Finn l-». Tb* sampling
ml* shall not ncMd O.OJO m>/min (1.0 eta) during tb*
ran. Periodically during th* Uft. obasrv* tb* connecting
Hn* b*tw**n th* prob* and first Implngcr lor Af ni of
sample as measured by dry
ni meter, dcm (dcf).
V.(std)- volume of gat tamplt measured by the dry
gai meter oorrectoo to standard conditions,
oscm (dscf).
Si—Averagt stack ga* velocity, calculated by
Method 2, Equation 2-4. using data obtained
from Method 8, m/Mc (ft/we).
Vtom**Total volume of solution in which tb*
aulfurlr acid or sulfur dioxide (ample Is
contained, 2M ml or 1,000 ml, respectively.
Vi-Volumt of barium perchlorate titrant used
lor the sample, ml.
Vit»Vo!ume of barium perchlorate titrant mad
for the blank, ml.
y-Dry gas meter calibration factor.
AH-Averaie pressure drop across orifice meter,
mm (In.) HiO.
e -Total sampling time, mln.
H.e-Speclflc gravity of mercury.
«0-Kc/mln.
100- Conversion to percent.
t.2 Averaitr dry gas roeur temperature and avtnge
•rtfic* preuurn drop &tt data shret (Figure (-2).
t.i Dry Oas Volumt. Correct tbt sample volume
measured by tb* dry ies meter to standard oondltloni
Off C and 7M nun Bg or X- T and 2».»2 In. Hg) by using
Xquatlon 8-1.
Vm ImtA) «
4JJ Contolotr No. t. TborongUy mli toe soiatlon
in tb* ooatalntr holding tb* content* of tbe stcood and
third implngtn. Hpctt* a 10-ml aliquot of *«mpl* Into a
KO-rnl Erlenmeyer ftatk. Add ml of Uopnpanol. 1 to
4 drop* of thorta Indicator, and UtraU to a pink Midpoint
wbtrt:
X,<-QMS»'KJmio Bg lor mttrir unite.
-17.M *R/in. Hg for English unite.
Nor* —If tbe leak rate obatrvtd during any manda-
tory leak-checks exceeds the epeclfted acorplablr rate,
tb* tosur shall tlihet oonect tbt ralue of t'. in Kquatlon
B-l (at deKribed in Section U of Method a), or (ball
Invalidate tb* to*t run.
M Volom* of Water Vapor and Moisture Content.
Calculate th* volume of water vapor using Equation
t-f of Method 6. the weight of water collected in the
top ugen and silica gel can b* directly eonvartad to
mfllilliers (th* specific gravity of water Is I */ml>. Cal-
•olate to* motttur* content of tbe Mark gas, using Equa
tton »-» of Method 6 Tbe "Note" in Section 6.6 ofMetlod
t also appli** to tbls method Note that U th. effluent ga.
Stream can b* ootutdrred dry, tbt volume of water vapor
and moisture oontent need not bt calculated.
«j Bulturtc acid mist (Including BOi) concentration
Csuao,-J
Equation
•bare:
Ci-0.04B04 g/mlllltqnlvalmt tor metric unite.
-1.0tlXIO-i|b/m*q tor English unite.
«.« Bulfur dioxid* concentration.
Ceo,-*!
'mint
Equation 8-3
JTi-0.03303 g/meq for metric units.
-7.081 XKHlb/meq for Knglisb unite.
m.7 laoklnttlc Variation.
a.7.1 CalculaUon from raw data.
/ 100 T.\K* Vi.+ (VJTm) P*, + Ag/13.6)l
Equation 8-4
wbere:
JsTi-0.003464 mm Hi-m>/ml-**t tor metric unite
-0.003876 In. Hg-fWml-'R tor English unite.
a.7.2 Calculation Irom intormedlate value*.
"*' P.v.A.0(\-B..)
Equation 8-5
_i-4 JSO lor metric unite.
-0.00450 for English unite.
tJ Acceptable Results. If (0 percent
-------
METHOD *—TOirAL Dm»ioj**Tiojf or rta
oricrrr or XJCXSSIONS VBOM STATIOMAIT
•OUBGB
Uany stationary sources discharge visible
emissions Into the atmosphere; these •mis-
sions are usually In the ahap* of a plum*.
This method Involves th* determination of
plum* opacity by qualified obesrteis. Tb*
method Include* procedure* for th* training
and certification of observers, and procedure*
to b* u»*d In th* field for determination of
plum* opacity. Tb* appearance of * plum* as
viewed by an obe*rv*r depends upon a num-
ber of variable*, com* of which may b* con-
trollable and some of which may not be
controllable in tb* neld. Variahl** which can
b* oontrolloA to an *xt*nt to which they no
longer exert a significant Influence upon
plum* appearance Include: Angle of th* ob-
server with respect to th* plume; angle of the
obeerver with respect to the sun; point of
cbaerratlon of attached and detached iteam
plume; and angle of the observer with re-
apect to a plum* emitted from a rectangular
atack with a large length to width ratio. Th*
method Includes apeciflc criteria applicable
to theae variable*.
Other varlablr which may not be control-
lable In the fleiu are luminescence and color
contrast betwet • the plume and th* back-
ground against vMcb the plume la viewed.
These variable* exert an influence upon the
appearance of a plume a* viewed by an ob-
server, and can affect the ability of th* ob-
aerver to accurately awlgn opacity value*
to the observed plume. Studies of the theory
of plume opacity and field studies have dem-
onstrated that a plume is most visible and
presents the greatest apparent opacity when
viewed against a contrasting background. It
follows from this, and Is confirmed by field
trials, that the opacity of a plume, viewed
under conditions where a contrasting back-
ground Is present can be assigned with the
greatest degree of accuracy. However, the po-
"tential for a positive error Is also th* greatest
when a plume Is viewed under such contrast-
Ing conditions. Under conditions presenting
a leaf contrasting background, the apparent
opacity of a plume Is less and approaches
tjero as the color and luminescence contrast
decrease toward zero. As a result, significant
negative bias and negative errors can be
made when a plume ii viewed under less
contrasting conditions. A negative bias de-
creases rather than increases the possibility
that a plant operator will b* cited for a vio-
lation of opacity standards due to observer
error.
Studies have been undertaken to determine
the magnitude of positive errors which can
be made by qualified observer* while read-
Ing plumes under contrasting condition* and
•using the procedures set forth In this
method. The results of these studies (field
trials) which Involve a total of 7flB seta of
25 readings each are as follows:
(I) For black plumes (133 sets at a smoke
generator), 100 percent of the sets wer*
read with a positive error" of leas thun 7.B
percent opacity; 00 percent wer* read with
a positive error of less than 5 percent opacity.
(2) For white plumes (170 sets at a smoke
generator, 168 sett at a coal-fired power plant,
298 sets at a sulfurlc acid plant), 99 percent
of the set* were read with a positive error of
less than 7.8 percent opacity; 66 percent were
read with a positive error oTless than 6 per-
cent opacity.
Th* posltlv* observational error associated
•with an average of twenty-five reading* Is
therefor* established. Th* accuracy of th*
method must be taken Into account-when
determining possible violations of appli-
cabl* opacity standards..
> 9or a act, positive error=averag* opacity
determined by observers' SB observations—
average opacity determined .from transmls-
aometert 96 recordings. .
1. Frinetple and appHoobOtty.
l.f Principle. Th* opacity of (missions
from stationary *ouro*s Is determined vis-
ually by a qualified observer. -
U Applicability. This method I* appli-
cable for th* determination of tb* opacity
of (missions from stationary source* pur-
suant to leo.ll(b) and for qualifying ob-
server* for visually determining opacity of
•missions.
9. Procedure*. Th* observer qualified m
accordance with paragraph 8 of this method
ahan us* th* following procedures for vis-
ually determining th* opacity of emissions:
S.I Position., Th* qualified observer shall
stand at a distance suOcUnt to provide a
clear view of the emissions with th* sun
oriented In th* 140* sector to his back. Con-
sistent with maintaining th* abov* require-
ment, the observer shall, as much a* possible,
make his observation* from a position such
that his line of vision Is approximately
perpendicular to the plum* direction, and
when observing opacity of emissions from
rectangular outlets (e.g. roof monitors, open
baghouses, nonclrcular stacks), approxi-
mately perpendicular to th* longer axis of
the outlet. Th* observer's line of sight should
not Include more than one plum* at a time
when multiple stacks an Involved, and in
any case the observer should mak* his ob-
servations with his Une of sight perpendicu-
lar to the longer axis of such a set of multi-
ple stacks (*.g. stub stacks on baghouses).
2.2 Field records. Th* observer shall re-
cord th* name of the plant, emission loca-
tion, type facility, observer's name and
affiliation, and the date on a field data sheet
(Figure 9-1). The time, estimated distance
to the emission location, approximate wind
direction, estimated wind speed, description
of the sky condition (presence and color of
clouds), and plume background are recorded
on a field date sheet at the time opacity read-
Ings are initiated and completed. • .
2.3 Observations. Opacity observations
shall bo made at the point of greatest opacity
In that portion of th* plum* where con-
densed water vapor Is not present. Th* ob-
server shall not look continuously at the
plume, but Instead shall observe tb* plume
momentarily at 15-seeond Intervals.
2.3.1 Attached steam plumes. When con-
densed water vapor U present within tb*
plume as It emerges from the emission out-
let, opacity observations shall be made be-
yond the point in the plume at which con-
densed water vapor Is no longer visible. The
observer shall record the approximate dls-
tanc* from th* emission outlet to the point
in th* plum* at which the observations are
made.
333 Detached steam plume. When water
vapor in the plume condenses and becomes
visible at a distinct distance from the emis-
sion outlet, the opacity of emissions should
be evaluated at the emission outlet prior to
the condensation of water vapor and the for-
mation of the steam plume. • •
3.4 Recording observations. Opacity ob-
servations shall be recorded to the nearest 5
percent at IB-second Intervals on an ob-
servational record sheet. (See Figure 9-3 for
an example.) A minimum of 34 observations
shall be recorded. Each momentary observa-
tion recorded shall bo deemed to represent
the average opacity of emission* for a IB-
second period.
9.B Date Reduction. Opacity shall be de-
termined as an average of 34 consecutive
observations recorded at IS-eecond Intervals.
Divide the observations recorded on the rec-
ord sheet into sets of 34 consecutive obser-
vations. A set ls composed of any 34 con-
secutive observations. Sets need not be con-
secutive in time and.in no case shall two
seta overlap. For each set of 34 observations,
calculate the averag* by summing th* opacity
of the 34 observations and dividing this sum
by 34. If an applicable standard specifies an
averaging time requiring more than 34 ob-
servations, calculate th* average for all ob-
servations mad* during tb* specified time
period. Record th* average opacity on a record
sheet. (See Figure 9-1 for an example.)
8. QtuUiftcattoni and t«*»nfl.
8.1 Certification requirement*. To receive
certification as a qualified observer, a can-
didate must be tested and demonstrate the
ability to assign opacity readings la • percent
Increments to 3> different black plumes and
M different white plumes, with an error
not to sKaeed IB percent opacity OB any one
rnail In t and an average error not to exceed
1& percent opacity In each category. Candi-
dates shall b* tested according to the pro-
cedures described in paragraph 83. Smoke
generator* used pursuant to paragraph 82
shall b* equipped with a smoke meter which
meets the requirement* of paragraph S3.
The certification shall be valid for a period
of 8 months, at which time the qualification
procedure must be repeated by any observer
in order to retain certification. _
• 83 Oertlfloatlon procedure. The certifica-
tion test consists of showing the candidate a
complete run of 60 plumes—3B Mack plumes
and 3B white plume*—generated by a smoke
generator. Plume* within each set of 36 black
and 25 white runs shall be presented In ran-
dom order. Tb* candidate assigns an opacity
valu* to each plume and records his obser-
vation on a suitable form. At the completion
of each run of 60 readings, the score of the
candidate is determined. If a candidate falls
to qualify, the complete run of 80 readings
must be repeated In any retest. The smoke
test may be administered as part of a smoke
echool or training program, and may be pre-
ceded by training or familiarization runs of
the smoke generator during which candidates
are shown black and white plumes of known
opacity.
. 84 Smoke generator specifications. Any
amok* generator used for the purposes of
paragraph 3.3 shall be equipped with a smoke
meter Installed to measure opacity across
the diameter of the smoke generator stack.
The smoke meter output shall display in-
•tack opacity baaed upon a patblength equal
to the stack exit diameter, on a full 0 to 100
percent chart recorder scale. The smoke
meter optical design and performance shall
meet the specifications shown in Table 9-1.
The smoke meter shall be calibrated as pre-
scribed In paragraph 3.3.1 prior to the con-
duct of each smoke reading test. At the
completion of each tost, the aero and span
drift shall be checked and If the drift ex-
ceeds ±1 percent opacity, the condition shall
be corrected prior to conducting any subse-
quent test runs. The smoke meter shall be
demonstrated, at the time of Installation, to
meet the specifications listed In Table 9-1.
This demonstration shall be repeated fol-
lowing any subsequent repair or replacement
of the photocell or associated electronic cir-
cuitry including the chart recorder or output
meter, or every • months, whichever occur*
1.8.1 Calibration. The smoke meter to
calibrated after allowing a minimum of 8O
minute* warmup by alternately producing
simulated opacity of 0 percent and 100 per-
cent. When stable response at 0 percent or
100 percent is noted, the smoke meter ls ad-
Justed to produce an output of 0 percent or
100 percent, a* appropriate. This calibration
shall be repeated until stable 0 percent and
100 percent readings are produced without
adjustment. Simulated 0 percent and 100
percent opacity values may be produced by
alternately switching the power to the light
souro* on and off while the smoke generator
to not producing smoke.
111-43
-------
Parameter?
*. Light wuroa...--
"
b. •peetral response
of pbotooell.
«. Angle «rf view....
d. Angle of projec-
tlon.
•. Calibration error.
f. Zero and span
•drift.
ffpeolpottfwfi
Incandescent lamp
operated at nominal
rated voltage.
Pbotoplo (daylight
• spectral respone* of
tbe human eye—
. reference 44).
!••' nuilmam total
angle.
U> msjttmum total
angle.
tt£% opacity, maxi-
mum.
*1« opacity, M
minuu*.
•J J took* m*t*r evaluation. The *mok*
meter dMlgn and pMforauno* are to be
evaluated aa follows:
S3.2.1 Ught source. Verify "o™ manu-
JaotuiWi d*t* and tfoip roltag* i»M«ur*-
m»nu mad* at the lamp, M incUUtd. that
th« lamp tt operated wttbJX ±8 percent of
the nominal rated roltage.
8355 Spectral TMponi* of photocell.
Verify from manuf»oturer'i date tbat tbe
photocell hae a photople reeponee; 1*, the
•peotral eeniitlvtty of the cell abaU oloaaly
•pproxbaate the itandard •pMtral-lumlno»»
tty ourre for photopto rUlon wbioa U refer-
•noetf in (b) of Table 0-1.
8453 Angle of new. Check oonjrtruotton
feometry to eniure tbat tbe total anyle of
view of the imolte plume, M eeen by tbe
photocell, doei not eioeed IB*. Hie total
angle of view may be calculated from: »»»
tan-* d/2L, where *• total angle of vtev,
dstbe turn of the photocell dlameter-f the
-f'r—**• of the limiting aperture: and
Z.stbe dtataflce from tbe photocell to tb»
limiting aperture. The limiting aoerture !•
tbe point la tbe petti between tbe pbotooeU
•ad tbe emoke plum* where tbe an|U of
T)*W to wse* reetrtcted. b anoke feoerator
•moke metere tbto to Bomally «a oclfloe
plate.
Angle of projection. Check eon-
geometry to euure that tbe total
•ogle of projection of tbe lamp oa tbe
•moke plume doe* not atood 18-. Tbe total
angle of projection may be calculated from:
t=3 tan-> d/3L, where »= total angle of pro-
jection; d» the eum of tbe length of the
lamp nlament ^ the diameter of *-^^ umit^y
aperture; and 1*= tbe dletanoe from the lamp
to tbe limiting aperture.
•J5J> Calibration error. Cdng neutral-
dentity flltere of known opacity, check the
•nor between the actual ratponee and the
theoretical linear reeponae of tbe amok*
meter. ThU check U accomplished by flrit
oallbratlng tbe amoke meter aocordlng to
•4.1 and then Inaartlng a eerie* of three
neutral-denelty fllten of »"""<"r' opacity of
SO, M, and 75 percent In the smoke meter
patblength. Filter* oallbarted within ±2 per-
cent shall be ueed. Care ahould be taken
when Inserting the Alters to prevent stray
light from affecting the meter. Make a total
of five nonoonsecutive resiling* for each
filter. The maximum error on any one read-
Ing shall be 8 percent opacity.
3J5.8 Zero and span drift. Determine
the »ero and span drift by calibrating and
operating the smoke generator In a normal
manner over a 1-hour period. The drift U
measured by checking the cero and span at
tbe end of this period.
t.S.a.7 Response time. Determine the re-
sponse time by producng the series of five
simulated 0 percent and 100 percent opacity
value* and observing the time required to
reach stable response. Opacity value* of 0
percent and 100 percent may be simulated
by alternately switching tbe power to the
light source off and on while tbe amoke
generator Is not operating.
4. Rtfcrcncet.
4.1 Air Pollution Control District Bulrs
and Regulation*, Lo* Angeles County Air
Pollution Control District, Regulation IV.
Prohibitions, Rule 60.
42 Welsburd, Uelvtn L. Field Operations
and Enforcement Manual for Air. TJ3. Envi-
ronmental Protection Agency, Research Tri-
angle Park. N.O, AFTD-1100, August 1073.
pp. 4.1-438.
43 Condon, C. XT., and Odishaw, tt. Hand-
book of Physios, McGraw-Hill Co.. N.T, N.T.
Mat. Table S.I. p. t-VL
TII-44
-------
FIGURE 9-1
RECORD OF VISUAL DETERMINATION OF OPACITY
PAGE of
COMPANY
LOCATION
TEST NUMBER,
DATE
TYPE FACILITY_
CONTROL DEVICE.
HOURS OF OBSERVATION,
OBSERVER
OBSERVER CERTIFICATION DATE_
OBSERVER AFFILIATION
POINT OF EMISSIONS
HEIGHT OP DISCHARGE POINT
CLOCK TIME
OBSERVER LOCATION
Distance to Discharge
"Direction from Discharge
Height of Observation Point
BACKGROUND DESCRIPTION
UEATHER CONDITIONS
Wind Direction
Wind Speed
Ambient Temperature
SKY CONDITIONS (clear,
overcast. % clouds, etc,) .
PLUME DESCRIPTION
Color
Distance Visible
OTHER INFOOIVVnOll
Initial
Final
F
1
t
SUMMARY OF AVERAGE OPACITY
Set
Number
'
eadlngs r
he source
he time e
T1me_
Start—End
Opacity . .
Sum
anapd froin to 1 ooac
was/was not in compliance wit
valuation was made.
Average
ity
h .at
-------
FIGURE 9-2 OBSERVATION RECORD
PAGE OF
COMPANY
LOCATION
TEST
WTE
OBSERVER
TYPE FAClLUV ""
POINT OF EHISSlCRT
Mr.
M1n.
0
1
2
3
4
5
6
7
8
9
10
Jl
12
13
14
15
16
17
18
19
20
21
^_22
23
24
25
26
27
28
29
0
Seconds
15
JO
*b
STEAM PLUME
(check If applicable)
Attached
Detached
COWEHTS
COHPAHY
LOCATION
TEST
WTE
FIGURE 9-2 OI&ERVA11UH RECORD
(Continued)
OJftLRVLR
TYPE FACILITY "~"
POINT OF EMISSTO5~
•Hr.
H1n.
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
Seconds
7T
Ib
30
4b
STEAM PLUME
(check 1f applicable)
Attached
Detached
*
UMNLNIS
1
[TR Doc.74-25160 FUed ll-ll-7*;8:48 am]
-------
APPENDIX B
Performance Specification 1—Performance
specifications and specification test proce-
dures for transmlasometer systems for con-
tinuous meuurement of the opacity of
•tack emissions .
1. Principle and Applicability.
1.1 Principle. The opacity of paniculate
matter In stack emissions Is measured by a
continuously operating emission measure-
ment system. These systems are based upon
the principle of transmlssometry which is a
direct measurement of the attenuation cf
visible radiation (opacity) by paniculate
matter In a stack effluent. Light having spe-
cflc spectral characteristics Is projected from
a lamp across the stack of a pollutant source
to a light sensor. The light Is attenuated due
to absorption and scatter by the paniculate
matter In the effluent. The percentage of
visible light attenuated Is defined as the
opacity of the emission. Transparent stack
emissions that do not attenuate light will
have a transmlttance of 100 or an opacity of
0. Opaque stack emissions that attenuate all
of the visible light will have a transmlttance
of 0 or an opacity of 100 percent. The tra,ne-
mlssometer is evaluated by use of neutral
density filters to determine the precisian of
the continuous monitoring system. Tests of
the system are performed to determine zero
drift, calibration drift, and response time
characteristics of the system.
1.2 Applicability. This performance spe-
cification Is applicable to the continuous
monitoring systems specified in the subparts
for measuring opacity cf emissions. Specifi-
cations for continuous measurement of vis-
ible emissions are riven In terms of design,
performance, and Installation parameters
These specifications contain Met procedures,
Installation requirements, and data compu-
tation procedures tor evaluating the accept-
ability of the continuous monitoring systems
cubject to approval by the Administrator.
2. Apparatus.
2.1 Calibrated Filters. Optical filters with
neutral spectral characteristics and known
optical densities to visible light or screens
known to produce specified optical densities.
Calibrated filters with accuracies certified by
the manufacturer to within :±3 percent
opacity shall be used. Filters required are
low, mid, and high-range filters with nom-
inal optical densities as follows when the
transmlssometer Is spanned at opacity levels
specified by applicable subparts:
Cilibr»t*d filler optical dens!ric<
Bptn Talu
(percent op«(
80... .
60
70
M
90
100 ..
f parenthesis
Jtr)
tow- Mid- .
ranee ranee
0 1 (20) • 0
1 (20)
.1 (20)
.1 (jo)
.1 (SO)
.1 (SO)
2 (87)
2 (87)
8 (50)
8 (60)
4 (60)
4 <«0)
Hlch-
nnpe
0.8 (69)
.8 (Ml)
.< (f«!
.6 (76)
.7 (8fi.
.« (67J4)
It Is recommended that filter calibrations
b« checked with a Wfll-colllmited photoplc
transmlEsometer of known linearity prior to
use. The filters abal) be of sufficient size
to attenuate the entire light beam of the
transml«ometer.
in Data Recorder. Analog chart recorder
or other suitable device with input voltage
ranje compatible with the analyzer system
output. The resolution of the recorder'*
datfc output shall be sufficient to allow com-
pletion of the test procedures within this.
specification.
3.3 Opacity measurement System. An in-
ctack transmlssometer (folded or single
path) with the optical design specifications
designated below, associated control unite
and apparatus to keep optical surfaces clean.
3. Definitions.
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of pollutant opacity in a source effluent
Continuous monitoring systems consist of
major subsystems as follows:
8.1.1 Sampling Interface. The portion of a
continuous monitoring system for opacity
that protects the analyzer from the effluent.
3.12 Analyzer. That portion of the con-
tinuous monitoring system which senses the
pollutant and generates a signal output thai
Is a function of the pollutant opacity.
3.1.3 Data Recorder. That portion of the
continuous monitoring system that processes
the analyzer output and provides a perma-
nent record of the output dgnal In terms of
pollutant opacity.
32 Transmlssometer. The portions of s
continuous monitoring system for opacity
that Include the sampling interface and the
analyzer.
33 Span. The value of opacity at •which
the continuous monitoring system Is set to
produce the maximum data display output.
The span ehall be set at an opacity specified
In each applicable subpart.
3.4 Calibration Error. The difference be-
tween the opacity reading Indicated by the
continuous monitoring system and the
known values of a merles of tert standards.
For this method the test standards are a
aeries of calibrated optical filters or screens.
3.S Zero Drift. The change In continuous
monitoring system output over a stated pe-
riod of time of normal continuous operation
when tbe pollutant concentration at the
Mm* of tbe measurement* Is aero
8.« Calibration Drift. The change In the
continuous monitoring system output over
• stated period of time of norm*! continuous
operation when the pollutant concentration
at the time of the measurements ls tbe same
known upscale value.
3.7 System Response. The time interval
from a step change In opacity In the stack
at the Input to the continuous monitoring
system to tbe time at which 95 percent of
tbe corresponding final vmlue Is reached as
displayed on Hie continuous monitoring sys-
tem data recorder.
3.8 Operational Test Period. A minimum
period of time over which a continuous
monitoring system it expected to operate
within certain performance specifications
without unscheduled maintenance, repair,
or adjustment.
3.9 Transmlttance. The fraction of Incident
light that U transmitted through an optical
medium of Interest.
8.10 Opacity. The fraction of Incident light
that Is attenuated by an optical medium of
Interest. Opacity (O) and transmlttance (T)
are related a/follows:
O = 1-T
• 3.11 Optical Density. A logarithmic meas-
ure of the amount of light that It attenuated
by an optical medium of Interest. Optical
density (D) Is related to the transmlttance
and opacity as follows:
D=-log,0T
»=-log,, (1-0)
8.13 Peak . Optical Response. The wave-
length of maximum' sensitivity of the Instru-
ment.
S.18 Mean Spectral Response. The wave-
length which bisects the total area under
the curve obtained pursuant to paragraph
•.2.1.
8.14 Angle of Tlew. The maximum (total)
angle of radiation detection by the photo-
detector assembly of the analyzer.
1.15 Angle of Projection. Tbe maximum
(total) angle that contains 95 percent of
the radiation projected from the lamp (
bly of the analyzer.
111-47
1.16 Patnlenjth. The depth of effluent In
ttM U|nt (MUD between the receiver and the
transmitter of the single-pass transmlssom-
eter, or the depth of effluent between the
transceiver arid reflector of a double-pass
tranimUsometer. Two pathlengths are refer-
enced by thU ipeclflcatlon:
8.16.1 Monitor Pathlength. The depth of
effluent at the Installed location of the con-
tinuous monitoring system
3.162 Emission Outlet Pathlength The
depth of effluent at the location emissions are
released to the atmosphere.
4. Installation Specification
4.1 Location. The transmlssometer must
be located across a section of duct or stack
that will provide a paniculate matter flow
through the optical volume of the trans-
mlssometer that Is representative of the par-
tlculate matter flow through the duct or
•tack. It Is recommended that the monitor
pathlength or depth of effluent for the trans-
mlssometer Include the entire diameter of
the duct or stack. In Installations using a
shorter pathlength, extra caution must be
used In determining the measurement loca-
tion representative of the paniculate matter
flow through the duct or stack.
4.1.1 The transmlsaometer location shall
be downstream from all paniculate control
equipment.
4.1.2 The transmlssometer shall be located
as far from bends and obstructions as prac-
tical.
4.1.3 A transmlssometer that Is located
In the duct or stack following a bend shall
be Installed In the plane defined by the
bend where possible
4.1.4 The transmlasometer should be In-
stalled in an acceaslble location.
4.1.S When required by the Administrator.
the owner or operator of a source must
demonstrate that the tranamlasometer Is lo-
cated In a section of duct or stack where
a representative paniculate matter distribu-
tion exists. The determination shall be ac-
complished by examining the opacity profile
of the effluent at a series of positions across
the duct or stack while the plant Is In oper-
ation at maximum or reduced operating rates
or by other tests,acceptable to the Adminis-
trator. .
42 Slotted Tube. Installations that require
the use of a slotted tube shall use a slotted
tube of sufficient size and blackness so as
not to Interfere with the free flow of effluent
through the entire optical volume of the
transmlssometer or reflect light Into the
transmlssometer photodetector. Ught re-
flections may be prevented by using black-
ened baffles within the slotted tube to pre-
vent the lamp radiation from Impinging upon
the tube walls, by restricting the angle of
projection of the light and the angle of view
of the photodetector assembly to less than
the cross-sectional area of the slotted tube,
or by other methods. The owner or operator
must show that the manufacturer of the
monitoring system has used appropriate
methods to minimize light reflections for
systems using slotted tubes.
4.3 Data Recorder Output. The continuous
monitoring system output shall permit ex-
panded display of the span opacity on a
standard 0 to 100 percent scale. Since all
opacity standards are based on the opacity
of the effluent exhausted to the atmosphere.
the system output shall be based upon the
•mission outlet pathlength and permanently
recorded. For affected facilities whose moni-
tor pathlength Is different from the facility's
•mission outlet pathlength, a graph shall be
provided with the Installation.to show the
relationships between the continuous moni-
toring system recorded opacity based upon
the emission outlet pathlength and the opac-
ity of'the effluent at the analyzer location
.(monitor pathlength). Tests for measure-
ment of opacity that are required by this
performance ipeclflcatlon are based upon the
-------
COMPANY
TEST NUM80T
MTE _
FIGURE S-2 OBSERVATION RECORD
OBSERVER
PAGE OF
TYPE FACILITY
POINT OF EHISSTCRT
Mr.
H1n.
-
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Seconds
TT
Ib
JO
4b
STEAM PLUME
(check If applicable)
Attached
iJetached
CflMwrrs
COMPW
tOCAT
TEST 1
DATE
FIGURE 5-Z OBbtKTMlUH Rtumu . rnoc, . ur . .
(Continued)
IT OBSERVER
OH •.•.-, •"
WHBIR
P
•Hr.
M1n.
30
31
32
33
34
35
36
37
38
39
40
41
42
43
45
46
4?
48
49
50
51
52
53
54
55
56
57
58
59
0
Sec
Ib
:ond<
JO
t>
!
4i»
•BDi
STEAM F
(check 1f I
Attached
JC.74-28160 I
WE FACILITY
OIKT OF EHIS
lUME
ppH cable)
Detached
"lied 11-11-74;!
5 ions
COMMITS
1
!:«un)
-------
APPENDIX B—PCHPOKMANCE SPECIFICATIONS
Performance Specification 1—Performance
specifications and specification test proce-
dures for transmlssometer systems for con-
tinuous meomiretnent of the opacity of
•Uck. emissions .
1. Principle and Applicability.
1.1 Principle. The opacity of paniculate
matter In stack emissions Is measured by a
continuously operating emission measure-
ment system. These systems are based upon
the principle of transmlssometry which Is a
direct measurement of the attenuation cf
visible radiation (opacity) by paniculate
matter In a stack effluent. Light having spe-
cflc spectral characteristics Is projected from
a lamp across the stack of a pollutant source
to a light sensor. The light Is attenuated due
to absorption and scatter by the paniculate
matter in the effluent. The percentage of
visible light attenuated Is defined as the
opacity of the emission. Transparent stack
emissions that do not attenuate light will
have a transmlttance of 100 or an opacity of
0. Opaque stack emissions that attenuate all
of the visible light will have a tranunlttance
of 0 or an opacity of 100 percent. The trs-ns-
mlssometer Is evaluated by use of neutral
density filters to determine the precisian of
the continuous monitoring system. Tests of
the system are performed to determine zero
drift, calibration drift, and response time
characteristics of the system.
1.2 Applicability. This performance spe-
cification Is applicable to the continuous
monitoring systems specified In the subpsrts
for measuring opacity cf emissions. Specifi-
cations for continuous measurement of vis-
ible emissions are elven In terms of design,
performance, and installation parameters
These specifications contain test procedures,
Installation requirements, and data compu-
tation procedures lor evaluating the accept-
ability of the continuous monitoring systems
subject to approval by the Administrator.
2. Apparatus.
2.1 Calibrated Filters. Optical filters with
neutral spectra! characteristics and known
optical densities to risible light or screens
known to produce specified optical densities.
Calibrated filters with accuracies certified by
the manufacturer to within ±3 -percent
opacity shall be used. Filters required are
low, mid, and high-range filters with nom-
inal optical densities as follows when the
transmlssometer Is spanned at opacity levels
specified by applicable subparts:
Span
Calibrated Clur optical dent!tic;
with tqulftltm opacity In
parenthesis
Low- Mid- Hlph-
rance ranee ranct
to o
60. ...
70...
W
90
100
1 (20) 0.2
1 (20) .2
1 (SO) .1
1 (20) .1
1 (20) .4
1 (20) .4
[57) O.S (69)
»7) .« (M)
SO) .4 Wi)
50) .6 (75)
«0) .7 (SO.
<0) .« (S7^)
It IB recommended that filter calibrations
be checked with a •well-colllm&ted pnotopic
transmlssometer of known linearity prior to
use. The filters shall be of sufficient size
to attenuate the entire light beam of the
trantmltsometer.
2.2 Data Recorder. Analog chart recorder
or other suitable device with Input voltage
range compatible with the analyzer system
output. The resolution of the recorder'*
datk output shall be sufficient to allow com-
pletion of the lest procedures within this
specification.
2.3 Opacity measurement System. An In-
ctack transmlssometer (folded or single
path) with the optical design specifications
deslcnated below, associated control units
and apparatus to keep optical surfaces clean.
3. Definitions.
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of pollutant opacity In a source effluent.
Continuous monitoring systems consist of
major subsystems as follows:
8.1.1 Sampling Interface. The portion of a
continuous monitoring system for opacity
that protects the analyzer from the effluent.
3.15 Analyzer. That portion of the con-
tinuous monitoring system which senses tbe
pollutant and generates a signal output thai
Is a function of tbe pollutant opacity.
3.1.3 Data Recorder. That portion of the
continuous monJtorlnf system that processes
tbe analyzer output and provides a perma-
nent record of tbe output elenal In terms of
pollutant opacity.
32 Transmlssometer. The portions of s
continuous monitoring system for opacity
that Include the sampling interface and the
analyzer.
33 Span. The value of opacity at -which
the continuous monitoring system Is set to
produce the maximum data display output.
Tbe span shall be set at an opacity specified
In each applicable subpart.
3.4 Calibration Error. The difference be-
tween tbe opacity reading Indicated by the
continuous monitoring system and the
known values of a series of t*rt rtandards.
For this method tbe test standards are a
aeries of calibrated optical filters or acreens.
3.5 Zero Drift. The change In continuous
monitoring system output over a stated pe-
riod of time of normal continuous operation
when tbe pollutant concentration at tbe
Mm* of the measurements Is aero.
8.« Calibration Drift. The change In the
continuous monitoring system output over
• stated period of time of normal continuous
operation when the pollutant concentration
at the time of the measurements U the same
known upscale value.
3.7 System Response. The time Interval
from a step change In opacity In the stack
at the Input to the continuous monitoring
system to the time at which 95 percent of
the corresponding final value Is reached as
displayed on tbe continuous monitoring sys-
tem data recorder.
3.B Operational Test Period. A minimum
period of time over which a continuous
monitoring system Is expected to operate
within certain performance specifications
without unscheduled maintenance, repair,
or adjustment.
3.9 Transxnlttance. The fraction of Incident
light that is transmitted through an optical
medium of Interest.
8.10 Opacity. The fraction of Incident light
that li attenuated by an optical medium of
Interest. Opacity (O) and transmlttance (T)
are related a/follows:
O=1-T
• 3.11 Optical Density. A logarithmic meas-
ure of the amount of light that It attenuated
by an optical medium of Interest. Optical
density (D) 1s related to the transmlttance
and opacity as follows:
D= -log,,T
8.12 Peak . Optical Response. The wave-
length of maximum'sensitivity.of the Instru-
ment.
8.13 Mean Spectral Response. Tbe wave-
length which bisects the total area under
the curve obtained pursuant to paragraph
t.2.1.
8.14 Angle of View. The maximum (total)
angle of radiation detection by the photo-
detector assembly of the analyzer.
t.16 Angle of Projection. Tbe maximum
(total) angle that contains 95 percent of
tbe radiation projected from tbe lamp assem-
bly of tbe analy»er.
111-47
S.16 Pathlength. The depth of effluent In
ate Ufht beam between the receiver and the
transmitter of tbe single-pass transmlssom-
eter, or the depth of effluent between the
transceiver •fid reflector of a double-pass
transmlssometer. Two pathlengths are refer-
enced by this specification:
8.10.1 Monitor Pathlength. The depth of
effluent at the Initalled location of the con-
tinuous monitoring system.
3.162 Emission Outlet Pathlength The
depth of effluent at the location emissions are
released to the atmosphere.
4. Installation Specification.
4.1 Location. The transmlsaometer must
be located across a section of duct or stack
that will provide a paniculate matter flow
through the optical volume of the trans-
mlssometer that Is representative of the par-
tlculat* matter flow through the duct or
stack. It Is recommended that the monitor
pathlength or depth of effluent for the trans-
mlssometer include the entire diameter of
the duct or stack. In Installations using a
shorter pathlength, extra caution must be
used In determining the measurement loca-
tion representative of the partlculate matter
flow through the duct or stack.
4.1.1 The transmlssometer location shall
be downstream from all paniculate control
equipment.
4.1.2 The transmlssometer shall be located
M far from bends and obstructions as prac-
tical.
4.1.3 A transmlssometer that Is located
In the duct or stack following a bend shall
be Installed In the plane defined by the
bend where possible
4.1.4 .The transmlssometer should be In-
stalled In an accessible location.
4.1.5 When required by the Administrator.
the owner or operator of a source must
demonstrate that the transmlssometer is lo-
cated In a section of duct or stack where
a representative paniculate matter distribu-
tion exists. The determination shall be ac-
complished by examining the opacity profile
of the effluent at a series of positions across
the duct or stack while the plant Is In oper-
ation at maximum or reduced operating rates
or by other tests,acceptable to the Adminis-
trator. .
4.2 Slotted Tube. Installations that require
the use of a slotted tube shall use a slotted
tube of sufficient size and blackness so as
not to Interfere with the free flow of effluent
through the entire optical volume of the
transmlssometer or reflect light Into the
transmlssometer photodetector. Light re-
flections may be prevented by using black-
ened baffles within the slotted tube to pre-
vent the lamp radiation from Impinging upon
the tube walls, by restricting the angle of
projection of the light and the angle of view
of the photodetector assembly to less than
the cross-sectional area of the slotted tube.
or by other methods. The owner or operator
must show that the manufacturer of the
monitoring system has used appropriate
methods to minimize light reflections for
systems using slotted tubes.
4.3 Data Recorder Output. The continuous
monitoring system output shall permit ex-
panded display of the span opacity on a
standard 0 to 100 percent scale. Since all
opacity standards are based on the opacity
of the effluent exhausted to the atmosphere,
the system output shall be based upon the
emission outlet pathlength and permanently
recorded. For affected facilities whose moni-
tor pathlength Is different from the facility's
emission outlet pathlength, a graph shall be
provided with the Installation.to show the
relationships between the continuous moni-
toring system recorded opacity based upon
the emission outlet pathlength and the opac-
ity of'the effluent at the analyzer location
{monitor pathlength). Tests for measure-
ment of opacity that are required by this
performance specification are based upon the
-------
snonltor pathlength. Tbe graph nsuseeery to
convert the data recorder output to the
•MUMr pathlength-baUJi shall b* eitthUahed
JM f ollowi:
lac <1~0,>- tot (i-*>
Whs**:
0,cthe opacity of the effluent baaed upon
,(0,=the'opacity of the effluent bMed upon TABLE 1-1.—/•er/ormawrr
If
l,=tbt •minion outltt pathlength.
l,= tb* monitor pathlength.
ft. Qpti
osnterllne of projection. Repeat the teit In
the verticil direction
T. Continuous Monitoring Svetem Fer-
lormlmre specifications
Toe continuous monitoring system ibe.ll
meet the performance sperlflaatlons in Table
1-1 to be considered acceptable under ttiln
method
Parameter
Sptclfltalltnu
ical Design Specifications.
The optical design specifications eet forth
In Section 0.1 shall bt met In order for a
measurement system to comply with the
requirements of thle method.
B. Determination of Oonformance with De-
eign Bpecineations.
D.I Tne ooaunuoua monitoring lyitem for
miMurement of opacity ihall be demon-
strated to conform to the deelgri epeclflca-
Uoni eet forth a* follows:
6.1.1 Peak Spectra) Response. Tht peak
spectral response of the continuous moni-
toring lyitemt iball occur between 500 nm
and 600 nm. Response at any wavelength be-
low 400 nm or above 700 nm shall be lew
than 10 percent of the peak response of the
continuous monitoring system.
6.1.2 Mean Spectral Response. The mean
•pectral response of the continuous monitor-
lag system shall occur between BOO nm and
•00 nm.
6.1.8 Angle of View. The total angle of view
•hall be no greater than 6 degrees.
6.1.4 Angle of Projection. The total angle
af projection shall be no greater than » de-
62 CoDformanoe with the requirements
of Motion 6.1 may be demonstrated by the
owner or operator of the affected facility by
testing each analyser or by obtaining a cer-
tificate of conformant 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 Ant analyzer randomly
sampled met all requirements of paragraph
6 of this specification. If any of the require-
ments were not met, the certificate must
ahow that the entire month's analyser pro-
duction was retampled according to the mili-
tary standard 105D sampling procedure
(MXU-BTD-106D) Inspection level II; was re-
teeted for each of the applicable require-
ments under paragraph 6 of this specifica-
tion; and was determined to be acceptable
under MTL-5TD-106D procedures. The certifi-
cate of oonfonnance must show the results
of each test performed for the analyMrs
•ampled during the month the analyzer be-
ing installed was produced.
i.3 The general test procedures to be fol-
lowed to demonstrate conformance with Sec-
tion 6 requirements are given as follows
(These procedures will not be applicable to
all designs and will require modification in
some cases. Where analyzer and optical de-
sign is certified by the manufacturer to con-
form with the angle of view or angle of pro-
jection specifications, the respective pro-
cedures may be omitted.)
6.3.1 Spectral Response. Obtain spectral
data for detector, lamp, and filter components
need in the measurement system from their
respective manufacturers. .
6.8.J Angle of View. Set the received up
as specified by the manufacturer. Draw an
arc with radius of 3 meters. Measure the re-
ceiver response to a small (leu than 8
centimeters) non-directional light s6uree at
4-centlmeter Intervals on the arc lor 36 centi-
meters on either side of the detector center-
line. Repeat the test in the vertical direction.
6.8.3 Angle of Projection. Set the projector
up as specified by the manufacturer. Draw
an arc with radius of 3 meters. Using a small
photoelectric light detector (less than 3
centimeters), measure the light Intensity at
•-centimeter Intervals on the arc for 96
oantlmeters on either tide of the light source
a. .Calibration «iror <> pet opacity.'
b Z»ro arid (24 h) <2 pet opacity.1
Calibration drill (24 h) <2 pet opacity '
d R«ipon» Umo 10» (mailmum)
i. Operational u»t period 188h.
1 Espraued ai sum of absolul* mean value and the
M pet confidence Interval ot a ttrtn ol tests.
8. Perfprmance Specification Teat Proce-
dures. The following test procedures shall be
used to determine conformance with the re-
quirement! of paragraph 7:
6.1 calibration Error and Response Time
Test. These tests are to be performed prior to
Installation of the system on the stack and
may be performed at the affected facility or
at other locations provided that proper notifi-
cation la given. Set up and calibrate the
measurement system as specified by the
manufacturer's written instructions for the
monitor pathlength to be used In the In-
stallatton. Span the analyzer as specified In
applicable subparts.
8.1.1 Calibration Error Test. Insert a series
of calibration filters In the transmlssometer
path at the midpoint. A minimum of three
calibration filters (low, mid, and high-
range) selected In accordance with the table
under paragraph 2.1 and calibrated -within
3 percent must be used Make a total of five
nonconsecutlve readings for each niter.
Record the measurement system output
readings in percent opacKy. (Se« Figure 1-1.)
8.1.2 "System Response Tost. Insert the
high-range filter in the transmlssometer
path five times and record the time required
for the system to respond to 95 percent of
final Eero and high-range filter values. (See
Figure 1-2.)
8.3 Field* Test for Zero Drift and Calibra-
tion Drift. Install the continuous monitoring
system on the affected facility and perform
the following alignments:
82.1 Preliminary Alignments. As soon as
possible after installation and once a year
thereafter when the facility is not In opera-
tion, perform the following optical and aero
alignments:
82.1.1 Optical Alignment. Align the light
beam from the trauimiseomeUr upon the op-
tical surfaces located across the effluent (!«.,
the retroflector or pbotodetecvor as applica-
ble) in accordance with the manufacturer's
instructions.
82.12 Zero Alignment. After the transmls-
someter has been optically aligned and the
transralsnometer mounting Is mechanically
stable (I.e.. no movement of the mounting
due to thermal contraction of the stack.
duct, etc.) and a clean stack condition has
been determined by a steady zero opacity
condition, perform the zero alignment. This
alignment is performed by balancing the con-
tinuous monitor system response so that any
simulated zero check coincides with an ac-
tual zero check performed across the moni-
tor pathlength of tb» clean stack.
8.2.1.3 Spun. Span the continuous monitor-
ing syrtcm at the opacity specified in sub-
parts nnd offset the zero setting at leant 10
percent ol span so that negative drift can be
quantified.
8.2.2. Final Alignments. After the prelimi-
nary alignments have been completed and the
affected facility has been started up and
reeches normal operating temperature, re-
check tlie optical alignment in accordance
with 82.1.1 of this specification. If the align-
ment has shifted, realign the optics, record
any detectable shift in the opacity measured
by tlir system that can be attributed to the
optical realignment, and notify the Admin-
istrator. This condition may not be objec-
tionable if the affected facility operates with-
in a fairly constant and adequately narrow
range of operating temperatures that does
not produce significant shift* In option!
alignment during normal operation of the
facility Onder circumstances where the facil-
ity operations produce fluctuations In the
effluent gas temperature that result In sig-
nificant misalignments, the Administrator
may require Improved mounting structures or
auother location for ln*ullatlon of tbe trans-
mlssometer.
82.3 Conditioning Period. After complet-
ing the post-startup alignments, operate the
system for an initial 168-hour conditioning
period In a normal operational manner.
82.4 Operational Test Period. After com-
pleting the conditioning period, operate the
system for an additional 168-hour period re-
taining the zero offset. Tbe system shall mon-
itor the source effluent at all times except.
when being zeroed or calibrated At 24-hour
Intervals tbe zero and span shall be checked
according to the manufacturer's instructions.
Minimum procedures used shall provide a
system check of tbe analyzer Internal mirrors
and all electronic circuitry including the
lamp and photodetector assembly and shall
Include a procedure for producing a simu-
lated zero opacity condition and a simulated
upscale (span) opacity condition as viewed
by the receiver. The manufacturer'* v,Titten
instructions may be uoed providing the i they
equal or exceed these minimum procedures.
Zero and span the transmlssometer. clean all
optical surfaces exposed to the effluent, rea-
lign optics, and make any necessary adjust-
ments to the calibration of the system dally.
These zero and calibration adjustments and
optical realignment* are allowed only at 24-
hour intervals or at such shorter Intervals as
the manufacturer's written Instructions spec-
ify. Automatic corrections made by tbe
measurement system without operator Inter-
vention are allowable at any time. Tbe mag-
nitude of any zero or span drift adjustments
shall be recorded. During this 168-hour op-
erational test period, record the following at
24-hour Intervals: (a) tbe zero reading and
span readings alter the system Is calibrated
(these readings should be set at the same
value at the beginning of each 24-hour pe-
riod);, (b) the zero reading after each 24
hours of operation, but before cleaning and
adjustment; and (c) the span reading after
cleaning and zero adlustment, but before
span adlustment. (Bee Figure 1-3.)
9. Calculation, Data Analysis, and Report-
^B.l Procedure for Determination of Mean
Values and Confidence Intervals.
6.1.1 The mean value of the data set Is cal-
culated according to equation 1-1.
n I-' Equation 1-1
where x,= absolute value of the individual
measurements.
of the Individual values.
x = mean value, and
n = number of data points.
8.1.2 The 65 percent confidence' Interval
(two-sided) Is calculated sccordlng to equa-
tion 1-2:
.
n>'n -
Equation 1-2
where
£x[— sum of all data points,
t i:s«t| — or/2, and
C.1..J— 95 percent confidence interval
estimate of the average mean
value.
The values In this table are already cor.
reeled for n-1 degrees of freedom. Use n equal
to the number of samples as data points.
111-48
-------
Values for 1.975
2
3
5
«
7
p
I)
n -.975
12 705
4 303
B 18°
2776
S. ST1
2 447
2. K.S
HOG
n
10
11
12
13
H
15
10
>.»75
2. 2W
2.226
5.201
2.170
S. 1BO
2 14J
2. HI
93 Data Analysis and Reporting.
9.3.1 Spectral Response Combine the
spectral data obtained ID accordance with
paragraph 6.3.1 to develop the effective spec-
tral response curve of the transmlssometer.
Report the wavelength at which the peak
response occurs, the wavelength at which the
tncan response occurs, and the maximum
response at any wavelength below 400 nm
aud above 700 nm expressed at a percentage
of the peak response as required under para-
graph 6.2.
8.2.2 Angle of View. Using the data obtained
In accordance with par»cjaph 6.3.2, calculate
the response of the receiver as a function of
viewing angle In the horizontal and vertical
directions (26 centimeters of arc with a
radius or 3 meters equal 6 degrees) Repcrt
relative angle of view curves as required un-
der paragraph 0.2.
B.2.3 Angle of Projection. DsLng the data
obtained In accordance with paragraph 6.3.3,
calculate the response of the photoelectric
detector as a function of projection angie In
the horizontal and vertical directions. Report
relative angle of projection curves as required
under paragraph 6.2.
8.2 4 Calibration Error. Using the data from
paragraph 8.1 (Figure 1-1), subtract the
known niter opacity value from the va'.ue
shown by the measurement system for each
of the 15 readings. Calculate the mean and
05 percent confidence Interval of the five dif-
ferent values at each test niter value accord-
Date of Test
Low
Range 1 opacity
Span Value X opacity
M1d High
Range X opacity Range X opacity
Location of Test
Calibrated Filter
Analyzer Reading
X Opacity
Differences
S Opacity
n
13
15
Mean difference
Confidence Interval
Calibration error - Mean Difference + C.I.
Low Hid High
Low, mid or high range
'Calibration filter opacity - analyzer reading
Absolute value
Figure 1-1. CiV.bratlor. Error Test
ing to equations 1-1 and 1-2. Report the sum
of the absolute mean difference and the 65
percent confidence Interval for each of the
'three test Biters.
0.2.6 Zero Drift. Using the icro opacity
vahies measured every 24 hours during the
field test (paragraph B.2). calculate the dif-
ferences between the zero point after clean-
ing, aligning, and adjustment, and the zero
value 24 hours later Just prior to cleaning,
aligning and adjustment. Calculate the
mean value of these points e J the confi-
dence Interval using equations 1-1 and 1-2.
Report the sum of the absolute mean value
and the 95 percent confidence Interval.
9.2.6 Calibration Drift. Using the span
value measured every 24 hours during the
field test, calculate the differences between
the span value after cleaning, aligning, and
adjustment of zero and span, and the span
value 24 hours later just after clear-Ing
aligning, and adjustment of Eero and before
adjustment of span. Calculate the mecr.
value of these points and the conf.dt:-.cc
Interval using equations 1-1 and 1-2. Report
the sum of the absolute mean value and the
confidence Interval.
8.2.7 Response Time. Using the data from
paragraph 8.1, calculate the time Interval
from filter Insertion to 95 percent of the flr.al
stable value for all upscale and downscole
traverses Report the mean of the 10 upscale
and downscale test times.
9.2.8 Operational Tatt Period. During the
168-hour operational test period, the con-
tinuous monitoring system shall not require
any corrective maintenance, repair, replace-
ment, or adjustment other than that clearly
specified as required In toe manufacturer's
operation and maintenance manuals as rou-
tine and expected during a one-week period.
If the continuous monitoring system I* oper-
ated within the specified performance pa-
rameters snd does not require corrective
maintenance, repair, replacement, or adjust-
ment other than as specified above during
the 168-hour test period, the operational
test period shall have been successfully con-
cluded. Failure of the continuous monitor-
ing system to meet these requirements shall
call for a repetition of the 168-hour test
period. Portions of the tests which were sat-
isfactorily completed need not be repeated.
Failure to meet any performance specifica-
tion (s) shall call for a repetition of the
one-week ooeratlonal test period and that
specific portion of .the tests required by
partgraph 8 related to demonstrating com-
pliance with the failed specification. All
maintenance and adjustments required shall
be recorded. Output readings ahall be re-
corded before and after all adjustment*.
loT*®DerunenteJ Stattitles," Department
of Commerce, National Bureau of Standards
Handbook 91, 1063. pp. 3-31, paragraphs
l6i '"Performance Specifications for Sta-
tionary-Source Monitoring Systems for Oases
and Visible Emissions," Environmental Pro-
tection Agency, Research Triangle Park,
N.C., EPA-650/2-74-01J, January 1974.
111-49
-------
Zero StttlAf
. (Set M'-<*r*r* ••*.» Bste ef ten
0«tt
IIKJ
TIM
lere
(Itfwt c1«»i«9
tot Idjuitnnt)
Spin '.tiding Ciltbntlofl
Zere Drift '(After cltinlnf and irro ttfjuitment Drift
(*Ztr«) tat btforc spin idJuiOwnt) (tSpin)
Ztro Drift • MMII Ztro Drift* .
CI (Z«ro
UM»rst1e»*rlft • Nun Spin Drift* .
.+ CI (Sp«n)
'Akttlvtt Mint
SMCOTCATJON 3— ParoaMAMCX
ar-XCiriCATIONS AND SWtCIFICATJON TXST rto-
OSDUIUCt FOR MONITORS OF SOl AHD NOl
1TAT1ONAJIT SOUBCEE
1. Principle and Applicability,
1.1 Principle. The concentration of tulfur
dioxide or oxides of nitrogen pollutant* in
•tack emissions U measured by a continu-
ously operating •minion measurement ayi-
ttm. Concurrent with operation of the con-
tlnuoui monitoring lyttem, the pollutant
concentration* art alao measured with refer-
ence methods (Appendix A). An average of
the continuous monitoring system data Is
computed for each reference method testing
period and compared to determine the rela-
tive accuracy of the continuous monitoring
system. Other tests of the continuous mon-
itoring system are also performed to deter-
mine calibration error, drift, and response
characteristics of the system.
1.3 Applicability. This performance spec-
ification is applicable to evaluation of con-
tinuous monitoring systems for measurement
of nitrogen oxides or sulfur dioxide pollu-
tants. These specifications contain test pro-
cedures, Installation requirements, and data
computation procedures for evaluating the
acceptability of the continuous monitoring
system*.
« Apparatus
»4 Calibration Gas Mixtures. Mixtures of
known concentrations of pollutant gas in a
diluent gas shall be prepared. The pollutant
gas shall be sulfur dloxjde or the appropriate
oxlde(s) of nitrogen specified by paragraph
• and within subparts. For sulfur dioxide gas
mixtures, the diluent gas may be air or nitro-
gen. For nitric oxide (NO) gas mixtures, the
diluent gas shall be oxygen-free «10 ppm)
nitrogen, and for nitrogen dioxide (NO,) gas
mixtures the diluent gas shall be air. Concen-
trations of approximately 60 percent and 90
percent of span are required. The BO percent
gas mixture 1* used to set and to check the
epan and U referred to as the spaa gas.
U Zero QM. A gas certified by the manu-
facturer to contain leas than 1 ppm of the
pollutant gas or ambient air Buy be used.
S J Bqulpment for measurement of the pol-
lutant gas concentration using the reference
method specified in the applicable standard
2.4 Data Recorder. Analog chart recorder
or other suitable device with Input voltage
range compatible with analyzer system out-
put. The resolution of the recorder's data
output shall be sufficient to allow completion
of the test procedures within this specifi-
cation .
2.5 Continuous monitoring system for SO,
or NOi pollutants as applicable.
8. Definitions.
S.I Continuous Monitoring Bystem. The
total equipment required lor the determina-
tion of a pollutant gaa concentration In a
source effluent. Continuous monitoring sys-
tems consist of major subsystems as follows:
3.1.1 Sampling Interface—That portion of
an extractive continuous monitoring system
that performs one or more of the following
operations: acquisition, transportation, and
conditioning of a sample of the source efflu-
ent or that portion of an In-sltu continuous
monitoring system that protects the analyser
from the effluent.
3.1.2 Analyzer—That portion of the con-
tinuous monitoring system which senses the
pollutant gas and generates a signal output
that Is a function of the pollutant concen-
tration.
3.1.3 Data Recorder—That portion of the
continuous monitoring system that provides
a permanent record of the output signal In
terms of concentration units.
3.2 Span, The value of pollutant concen-
tration at which the continuous monitor-
ing system Is set to produce the maximum
data display output. The span shall be set
at the concentration specified In each appli-
cable subpart.
3.3 Accuracy (Relative). The degree of
correctness with which the continuous
monitoring system yields the value of fas
concentration of a sample relative to the
value given by a defined reference method.
This accuracy Is expressed In terms of error,
Which Is Uu difference between the paired
concentration measurements expressed aa a
percentage of the mean reference value.
1.4 Calibration Error. The difference b*-
tareen the pollutant concentration indi-
cated by the continuous monitoring nystem
and the known concentration of the test
gas mixture.
1.6 Zero Drift. The change In the continu-
ous monitoring system output over e stated
period of time of normal continuous opera-
tion when the pollutant concentration at
tb* time for the measurements IB zero
3.8 Calibration Drift. The change In the
continuous monitoring system output over
a stated time period of normal continuous
operations when the pollutant concentra-
tion at the time of the measurements IE the
acme known upscale value.
3.7 Response Time. The time Interval
from a step change In pollutant concentra-
tion at the Input to the continuous moni-
toring system to the time at which 95 per-
cent of the corresponding final value is
reached as displayed on the continuous,
monitoring system data recorder.
tX Operational Period A minimum period
of time over which a measurement system
Is expected to operate within certain per-
formance specifications without unsched-
uled maintenance, repair, or adjustment
3.9 Stratification. A condition Identified
toy a difference In excess of 10 percent be-
tween the average concentration In the due:
or stack and the concentration at any point
more than 1.0 meter from the duct or stack
wall.
4. Installation Specifications Pollutant
continuous monitoring systems (SO. and
NO.) shall be Installed at a sampling loca-
tion where measurements can be made which
are directly representative (4.1), or which
can be corrected so as to be representative
(43) of the total emissions from the affected
facility. Conformance with this requirement
•ball be accomplished as follows:
4.1 Effluent gases may be assumed to be
•onstratlfled If a sampling location eight or
more stack diameters (equivalent diameters;
downstream of any air In-leakage l» se-
lected. This assumption and data correction
procedures under paragraph 4.2.1 may not
be applied to sampling locations upstream
of an air preheater In a (team generating
facility under Subpart D of this part. For
sampling locations where affluent gases are
•Ither demonstrated (4.8) or may be as-
sumed to be nonstratlfled (eight diameters),
a point (extractive systems) or path (In-sltu
systems) of average concentration may be
monitored
4.3 For sampling locations where effluent
gases cannot be assumed to be nonstratl-
fled (less than eight diameters) or have been
shown under paragraph 4.3 to be stratified,
result* obtained must be consistently repre-
sentative (e.g. a point of average concentra-
tion may shift with load changes) or the
data generated by sampling at a point (ex-
tractive systems) or across a path (In-sltu
systems) must be corrected (42.1 and 4.22)
so as to be representative of the total emis-
sions from the affected facility. Conform-
ance with this requirement may be accom-
plished In either of the following ways:
43.1 Installation of a diluent continuous
monitoring system (O. or CO. as applicable)
In accordance with the procedures under
paragraph 4.2 of Performance Specification
3 of this appendix. If the pollutant and
diluent monitoring systems are not of the
aarae type (both extractive or both In-sltu),
the extractive system must use a multipoint
probe.
4J.2 Installation of extractive pollutant
monitoring systems using multipoint sam-
pling probes or In-sltu pollutant monitoring
systems that sample or view emissions which
are consistently representative of the total
emissions for the entire croes eectlon. The
Administrator may require data to be sub-
111-50
-------
mltted to demonstrate that tne emissions
sampled or viewed are consistently repre-
sentative for several typ>e*l facility process
operating condition*.
4.3 The owner or operator may perform a
traverse to characterize any stratification of
effluent gases that might exist In a stack or
duct. If no stratification Is present, sampling
procedures under paragraph 4.1 may be ap-
plied fen though toe eight diameter criteria
Is not met.
4.4 When single point sampling probes for
extractive systems are Installed within the
•tack or duct under paragraphs 4.1 and 4.2.1.
the sample may not. be extracted at any point
less than 1.0 meter from the stack or duct
wall. Multipoint sampling probes Installed
under paragraph 4.2.2 may be located st any
points necessary to obtain consistently rep-
resentative samples.
5. Continuous Monitoring System Perform-
ance Speculations.
The continuous monitoring system iball
meet the performance specifications In Table
3-1 to be considered acceptable under 'this
method.
TABLE 2-1.—Performance tpeciflcatiom
Perimeter
Specification
1 Accuracy i . ... - <20 pel of the mean value of the reference method lest
data.
?. Calibration error' S S pet of each (SO pet, 90 pet) calibration gas mixture
value.
S. Zero drill (2 h) > 2 pet of spaa
4. Zero drift (24 h) 1 Do.
s. Calibration drift (2h)' Do.
e. Calibration drift (24 h)' 2.8 pet. of span
7. Response time IS min mailmum.
8. OperaUonal period 168 h minimum.
1 Eipresacd as sum of abeoluu mean value plus 85 pet confidence Interval of a series of tests.
tlonal 168-hour period retaining the zero
offset. The system shall monitor the source
effluent at all times except when being
zeroed, calibrated, or backpurged.
6.2.2.1 Field Test for Accuracy (Relative).
For continuous monitoring systems employ-
ing extractive sampling, the probe tip for the
continuous monitoring system and the probe
tip for the Reference Method sampling train
should be placed at adjacent locations In the
duct. For NO, continuous monitoring sys-
tems, make 27 NOX concentration measure-
ments, divided Into nine sets, using the ap-
plicable reference method. No more than one
set of tests, consisting of three Individual
measurements, shall be performed in any
one hour. All individual measurements of
each set shall be performed concurrently,
or within a three-minute interval and the
results averaged. For SO, continuous moni-
toring systems, make nine SO. concentration
measurements using the applicable reference
method. No more than one measurement
shall be performed In any one hour. Record
the reference method test data and the con-
tinuous monitoring system concentrations
on the example data sheet shown In Figure
2-3.
6.2.22 Field Test for Zero Drift and Cali-
bration Drift. For extractive systems, deter-
mine the values given by zero and span gas
pollutant concentrations at two-hour Inter-
vals until 16 sets of data are obtained. For
nonextractlve measurement systems, the zero
value may be determined by mechanically
producing a zero condition that provides a
system check of the analyzer internal mirrors
and all electronic circuitry including the
radiation source and detector assembly or
by Inserting three or more calibration gas
cells nnd computing the zero point from the
upscale measurements. If this latter tech-
nique is used, a graph (s) must be retained
by the owner or operator for each measure-
ment system that shows the relationship be-
tween the upscale measurements and the
zero point. The span of the system shall be
checked by using a calibration gas cell cer-
tified by the manufacturer to be function-
ally equivalent to 50 percent of span concen-
tration. Record the zero and span measure-
ments (or the computed zero drift) on the
example data sheet shown In Figure 3-4.
The two-hour periods over which measure-
ments are conducted need not be consecutive
but may not overlap. All measurements re-
quired under this paragraph may be eon-
ducted concurrent with tests under para-
graph e.a.a.i. .
6. PerforTrt*pce Spec^catlon Test
dures. The following test procedures shall be
used to determine conformance with the
requirements of paragraph 5. For NO, an-
requlrements of paragraph 5. For NOi an-
alyzers that oxidize nitric oxide (NO) to
nitrogen dioxide (NO.), the response time
test under paragraph 6'.3 of this method shall
be performed using nitric oxide (NO) span
gas. Other tests for NO. continuous monitor-
Ing systems under paragraphs 6.1 and 6.2 and
all tests for sulfur dioxide systems shall be
performed using the pollutant span gu spe-
cified by each lubpart.
6.1 Calibration Error Test Procedure. Set
up and calibrate the complete continuous
monitoring system according to the manu-
facturer's wrlten Instructions. This may be
accomplished either In the laboratory or In
•.he field.
6.1.1 Calibration Oas Analyses. Triplicate
analyses of the gas mixtures shall be per-
formed within two weeks prior to use using
Reference Methods 6 for SO, and 7 for NOi.
Analyze each calibration gas mixture (50%,
GO'-o) and record the results on the example
sheet shown In Figure 2-1. Each sample test
result must be within 20 percent of the aver-
aged result or the tests shall be repeated.
This step may be omitted for non-extractive
monitors where dynamic calibration gas mix-
tures are not used (8.1.2).
6.1.2 Calibration Error Test Procedure.
Make a total of 15 nonconsecutlve measure-
ments by alternately using zero gas and each
:oliberatlon gas mixture concentration (e.g..
3<>. 50%. 0%, 80%. S07c, 80%, 50%. 0%,
tie.). For nonextractlve continuous monitor-,
lag systems, this test procedure may be per-'
formed by using two or more calibration gas
cells whose concentrations are certified by
the manufacturer to be functionally equiva-
lent to these gas concentrations. Convert the
continuous monitoring system output read-
Ings to ppm and record the results on the
example sheet shown in Figure 2-2.
6.2 Field Test for Accuracy (Relative).
Zero Drift, and Calibration Drift. Install and
operate the continuous monitoring system In
accordance with the manufacturer's written
Instructions and drawings as follows:
6.2.1 Conditioning Period. Offset the zero
setting at least 10 percent of the span ao
that negative zero drift can be quantified.
Operate the system for an Initial 168-hour
conditioning period In normal operating
manner.
6.3.3 Operational Test Period. Operate th»
continuous monitoring system for an addi-
8.3.2.3 Adjustments. Zero and calibration
corrections and adjustments are allowed only
at 34-hour Intervals or at such shorter In-
tervals as the manufacturer's written in-
structions specify. Automatic corrections
made by the measurement system without
operator Intervention or Initiation are allow-
able at any time. During the entire 168-hour
operational test period, record on the ex-
ample sheet shown In Figure 3-6 the values
given by zero and span gu pollutant con-
centrations before and after adjustment at
24-hour Intervals.
63 Field Test for Response Time
63.1 Scope of Test. Dae the entire continu-
ous monitoring system as Installed, including
sample transport lines If used. Flow rates.
line diameters, pumping rates, pressures (do
not allow the pressurized calibration gas to
change the normal operating pressure lu the
sample line), etc.. shall be at the nominal
values for normal operation as specified n>
the manufacturer's written instructions. U
the analyzer Is used to sample more than one
pollutant source (stack), repeat this test for
each sampling point.
6.3.2 Response Time Test Procedure. In-
troduce zero gas into the continuous moni-
toring system sampling Interface or as close
to the sampling Interface as possible. When
the system output reading has stabilized,
switch quickly to a known concentration of
pollutant gas. Record the time from concen-
tration switching to 95 percent of final stable
response. For non-extractive monitors, the
highest available calibration gas concentra-
tion shall be switched Into and out of the
sample path and response times recorded.
Perform this test sequence three (3) Umes.
• Record the results of each test on the
example sheet shown in Figure 2-0.
">• Calculations. Data Analysis and Report-
tn^ - -
7.1 Procedure for determination of moan
values and confidence Intervals.
7.1.1 The mean value of a date set Is
calculated according to equation 3-1.
.
" !-' Equation ? •]
whore :
x, = absolute value of the measurements
2= sum of the Individual values,
r= mean value, and
n = number of date points.
7.1.2 The 85 percent confidence interval
(two-sided) Is calculated according to equa-
tion 3-3:
Equation 2-2
where:
Lxt— sum of all datn points,
t.rri— 1| — a/2, and
C.I.M=9,:) percent confidence interval
estimate of the average mean
value.
Values for V975
The values In this table are already cor-
rected (or n-1 degrees of freedom. Use n
111-51
-------
equal to tbe number of sample* aa d*te
points.
tJ Data AaalyaU wd lUportlng.
Ta.l Accuracy (Relative). For each or tbe
nine reference method test polnU, determine
the average pollutant concentration reported
by th* continuous monitoring system. These
average concentration* shall be determined
from tb« continuous monitoring system deU
recorded und«r 7.2.2 by integrating or aver-
aging the pollutant eonotntrmtloni over Meh
3f th* Urn* Interval* ooncurrent with each
reference method testing period. Before pro-
ceeding to tbt next »tep, determine tbt bails
(wet or dry) of tbe continuous monitoring
•yitsm data aad reference method test data
concentration*. If tbe bate* in not con-
sistent, apply • mouture correction to eltber
reference aetbod concentrations or tbe con-
tinuous monitoring system concentrations
as appropriate. Determine the correction
factor by moisture testa concurrent witb tbe
reference metbod testing periods. Report the
moisture test method and tbe correction pro-
cedure employed. For each of tbe nine test
runs determine tbe difference for eacb test
run by subtracting the respective reference
metbod teet concentration* (uae average of
each act of tnree mr .urcments for NO«)
from tbe continuous monitoring system inte-
grated or averaged
-------
Calibration Gas Mixture Data (Fran Figure 2-1)
Mid (505) ppn High (901) ppm
Run t
CaTi bra t i on Gas
Concentration,ppm
Measurement Systen
Reading, ppn
Differences, ppm
n_
\2
15
Hid High
Mean difference
Confidence interval
Calibration error =
T
Near Difference + C.I.
Average Calibration Gas Concentration
•x 100
Calibration gas concentration - measurement system reading
i
'Absolute value
Figure 2-2. Calibration Error Determination
«t
to.
1
t
,
4
$
du
•nd
Itat
Mffcrtncff Hrthod bnplti
MJ
S«pfl 1
. ;
«• I
7
,
t
fit
lit
leu
U|
rtf«r«nc« •
MllM (10,
JlflfMO 1
Mtll04
Rtorv«)f •
SmpU 1
W KO
(^m) j (ppn)
i
i
|
W Suplt
«»tr.«
(P^i)
Mllyltr l-NMir
i
1
HHn rtffrtnci atttod
t«t vilirt (HD )
(M.) • «
»%«n »f th« ^ifftr»ncc> * f$( (onrtMnct~1ntffrv«) »•« _
*"*' N««n rtf«r,)
to.
DtUrvtnttlM (SO, t*t M,)
111-53
-------
UU
kt Ttat
J*. »t|<> M
tttt
Zir*
Drift
**"
Brlfl
(tin")
(•HkrtU
drift
( Split-
2*r« Vift • [Hun Irro
bMbrlttCKi Drift • (Mtcn ip«n 1
•Aktetutt Vtlut.
r.(urc
C«llbr«ticn
D»te Zero Span Calibration
and Zero Drift Reading Drift
Time Reading (AZero) (After zero adjustment)
Zero Drift • [Mean Zero Drift* + C.I. (Zero)
t [Instrument Span] x ICO «
Calibration Drift « [Mean Span Drift*
+ C.I. (Span)
[Instrument Span] x 100
* Absolute value
Figure 2-5. Zero and Calibration Drift (24-hour)
111-54
-------
Bate of Test
Span Gas Concentration
Analyzer Span Setting
_PP*
_ppra
1 seconds
Upscale 2 , seconds
3 seconds
Average upscale response seconds
1 seconds
Downscale 2 seconds
-3
seconds
Average downscale response seconds
System average response -time (slower time) • seconds.
Idevlatlon from slower . [average upscale minus average downscale"] lnnT
system average response 1
slower time J " •"". •
Figure 2-6. Response Time
j — Performance
specintlonaaaspecmcuon test proce-
dures for monitors of CO, and O, from sta-
tionary sources.
1. Principle and Applicability.
1.1 Principle. Effluent gases are continu-
ously sampled and are analyzed (or carbon
dioxide or oxygen by a continuous monitor-
Ing system. Test] of the system are performed .
during a minimum operating period to deter-
mine zero drift, calibration drift, and re-
sponse time characteristics.
1.2 Applicability. This performance speci-
fication Is applicable to evaluation of con-
tinuous monitoring systems for measurement
of carbon dioxide or oxygen. These specifica-
tions contain test procedure], installation re-
quirements, and data computation proce-
dures for evaluating the acceptability of the
continuous monitoring systems subject to
approval by the Administrator. Sampling
may include either extractive or non-extrac-
tive (In -situ) procedures.
2. Apparatus.
2.1 Continuous Monitoring System for
Carbon Dioxide or Oxygen.
2.2 Calibration Oas Mixtures. Mixture of
known concentrations of carbon dioxide or
oxygen In nitrogen or air. Mldrange and 90
percent of span carbon dioxide or oxygen
concentrations are required. The 90 percent
of span gas mixture Is to be used to set and
check the analyzer span and Is referred to
«L) span gai. For oxygen analyzers, If the
sp»n Is higher than 21 percent O,, ambient
air may be used In place of the 90 percent of
span calibration gas mixture. Triplicate
analyses of the gas mixture (except ambient
air) shall be performed within two weeks
prior to use using Reference Method. 3 of
this pan.
2.3 Zero Oas. A gas containing less than 100
ppm of carbon dioxide or oxygen.
2.4 Data Recorder. Analog chart recorder
or other suitable device with Input voltage
range compatible with analyzer system out-
put. The resolution of the recorder's data
output shall be sufficient to allow completion
of the tut procedures within this specifica-
tion.
3. Definitions.
1.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of carbon dioxide or oxygen In a given
source effluent. The system consists of three
major subsystems:
3.1.1 Sampling Interface. That portion of
the continuous monitoring system that per-
forms one or more of the following opera-
tions: delineation, acquisition, transporta-
tion, and conditioning of a cample of the
saurce effluent or protection of the analyzer
from the hostile aspects of the sample or
source environment.
3.1.2 Analyzer. That portion of the con-
tinuous monitoring system which senses the
pollutant gas and generates a signal output
that Is a function of the pollutant concen-
tration.
3.1.3 Data Recorder. That portion of the
continuous monitoring system that provides
a permanent record of toe output signal in
terms of concentration units.
33 Span. The value of oxygen or carbon di-
oxide concentration at which the continuous
monitoring system is set that produce* the
maximum data display output. For the pur-
poses of this method, the span shall be set
no less than l.S to 2.S times the normal car-.
bon dioxide or normal oxygen concentration
In the stack gu of the affected facility.
3.3 Mldrange. The value of oxygen or car-
bon dioxide concentration that Is representa-
tive of the normal conditions in the stack
gas of, the affected facility at typical operat-
ing rates.
3.4 Zero Drift. The change in the contin-
uous monitoring system output over a stated
period of time of normal continuous opera-
tion when the carbon dioxide or oxygen con-
centration at the time for the measurements
is zero. „
3.5 Calibration Drift. The change to the
continuous monitoring system output over a
stated time period of normal continuous op-
eration when the carbon dioxide or oxygen
continuous monitoring system Is measuring
the concentration of span gas.
8.6 Operational Test Period. A minimum
period of time over which the continuous
monitoring system 1s expected to" operate
within certain performance specifications
without unscheduled maintenance, repair, or
adjustment. . . ' v .
. 3.7 Response time. The time interval from
a step change In concentration at the Input
to the continuous monitoring system to the
tun* at which 98 percent of to* oomepoad-
lag final value Is displayed on the oontlnuoas
nonltorlnc system data recorder.
4. T"*tallatlon Specification.
Oxygen or carbon dioxide continuous mon-
itoring systems" shall be installed at a loca-
tion where measurement* art directly repre-
sentative of the total effluent from the
affected facility or representative of the same
effluent sampled by a SO, or NO. continuous
monitoring system. This requirement anal)
be complied with by use of applicable re-
quirements in Performance Specification 9 of
this appendix as follows:
4.1 Installation of Oxygen or Carbon Dl-
'oxlde Continuous Monitoring Systems Not
Used to Convert Pollutant Data. A sampling
location shall be selected In accordance with
the procedures under • paragraphs 4.3.1 or
. 4.2.2, or Performance Specification 3 of this
appendix. •
4.2 Installation of Oxygen or Carbon Di-
oxide Continuous Monitoring Systems Used
to Convert Pollutant Continuous Monitoring
System- Data to Units of Applicable Stand-
ards. The diluent continuous monitoring sys-
tem (oxygen or carbon dioxide) 'shall be In-
stalled at a sampling location where measure-
ments that can be made are representative of
the effluent gases sampled by the pollutant
continuous monitoring system(s). Conform -
ance with this requirement may be accom-
plished in any of the following ways:
4.2.1 The sampling location for the diluent
system shalTbe near the sampling location for
the pollutant continuous monitoring system
such that the same approximate point (s)
(extractive systems) or path (In-situ sys-
tems) in the cross section Is sampled or
viewed. . - •
42.2 The diluent and pollutant continuous
monitoring systems may be Installed at dif-
ferent locations If the effluent gases at both
sampling locations are nonstratlned as deter-
mined under paragraphs 4.1 or 4.3, Perform-
ance Specification 2 of this appendix and
there is no In-leakage occurring between the
two sampling locations. If the effluent gases
are stratified at either location, the proce-
dures under paragraph 422, Performance
Specification 3 of this appendix shall be used
for installing continuous monitoring systems
at that location.
6. Continuous Monitoring System Perform-
ance Specifications.
The continuous monitoring system shall
meet the performance specifications In Table
3-1 to be considered acceptable under this
method.
0. Performance Specification Test Proce-
dures.
The i
is following test procedures shall bo used
to determine conformence with the require-
ments of paragraph 4. Due to the wide varia-
tion existing in analyzer designs and princi-
ples of operation, these- procedures are not
applicable to all analyzers. Where this occurs,
alternative procedures, subject to the ap-
proval of the Administrator, may be em-
ployed. Any such alternative procedures must
fulfill the same purposes (verify response,
drift, and accuracy) as the following proce-
dures, and must clearly demonstrate con-
formance with specifications In Table 8-1.
"" 6.1 Calibration Check. Establish a cali-
bration curve tor the continuous moni-
toring system using zero, mldrange, and
span concentration gas mixtures. Verify
that the resultant curve of analyzer read-
ing compared with the calibration gas
value is consistent with the expected re-
sponse curve as described by the analyzer
manufacturer. If the expected response
curve is not produced, additional cali-
bration ias measurements shall be made,
or additional stops undertaken to verify
111-55
-------
the accuracy of the response curve of the
analyzer.
6.2 Field Test for Zero Drift and Cali-
bration Drift. Install and operate the
continuous monitoring system In accord-
ance with the manufacturer's written in-
structions and drawings as follows:
TABU: 8-1.—Performance ipeclflcaliimt
Armatcr
fpMf/tttffon
1. Ztro drill (Zh)1
2. Ztro drill >
i. Calibration drill (5 h) '..
4, Csllbraifon rtnd (24 b) ' .
A. Operational period
<0.4 pel Otor COi
3-0.6 pet Ot or COi.
?0.4 pet Oioi COt.
-------
»U
itt
I*.
t\m
DlU
Uro
Ztro
Drift *p4n
(*2tro) *«dti>«
Iftn
Drift
Drin
C«>1bnt1on Drift • [M»M $p«n Drift*
•Abtolutl V«lu«.
Fljurt 3-1. Ziro »nd UllSrttlon Drift (2 Hour).
late Zero Span Calibration
nd Zero Drift Reading Drift
1me Reading (iZero) (After zero adjustment) (iSpan)
iero Drift - [Mean Zero Drift*
.+ C.I. (Zero)
:a11oration Drift • [Mean Span Drift*
•f C.I. (Span)
Absolute value
Figure 3-2. Ziro and Calibration Drift (24-hour)
TII-57
-------
Cat* Of Tut
Span Gas Concentration
Analyzer Span Setting ppm
1. seconds
Upscale 2. seconds
3. seconds
Average upscale response seconds
1. seconds
Downscale 2. seconds
3. seconds
Average downscale response seconds
>ysttm average response time (slower tiire) • seconds
•vufnf/ from slower B ^veraqe upscale minus average downscale
systejn average response slower time
., ,.,
Figure 3-3. Response
(Sac. 114 of th» Cltttn Air Act M
(O U.8C. »M7o-«).).
Ill-58
-------
IULES AND REGULATIONS
Tttto 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY'
SUBCHAPTER C-^AIR PROGRAMS
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Additions and Miscellaneous Amendment!
OPACITY
It Is evident from coiflmenta received
that an inadequate explanation was given
for applying both an enforceable opacity
standard and an enforceable concentra-
tion standard to the same source and that
the relationship between the concentra-
tion standard and the opacity standard
was not clearly presented. Because all
but one of the regulations Include these
dual standards, this subject Is dealt with
here from the general viewpoint. Specific
changes made to the regulations pro-
posed for a specific source are described
in the discussions of each source.
A discussion of the major points raised
by the comments on the opacity standard
follows:
1. Several commentators felt that
opacity limits should be only guidelines
for determining when to conduct the
stack tests needed to determine compli-
ance with concentration/mass standards.
Several other commentators expressed
the opinion that the opacity standard
was more stringent than the concentra-
tion/mass standard.
As promulgated below, the opacity
standards are regulatory requirements,
just like the concentration/mass stand-
ards. It is not necessary to show that the
concentration/mass standard is being
violated In order to support enforcement
of the opacity standard. Where opacity
and concentration/mass standards are
applicable to the same source, the opacity
standard is not mote restrictive than the
concentraUon/mafls standard. The con-
centration/mass standard is established
at a level which will result in the design.
Installation, and operation of the beat
adequately demonstrated system of emis-
sion reduction (taking costs Into ac-
count) for each source. The opacity
standard la established at a. level which
will require proper operation and mainte-
nance of such control systems on a day-
to-day basis, but not require the design
and Installation of a control system more
efficient or expensive than that required
by the concentration/mass standard.
Opacity standards are a necessary sup-
plement to concentration/mass stand-
ards. Opacity standards help ensure that
sources and emission control systems
continue to be properly maintained and
operated so as to comply with concen-
tration/mass standards. Participate test-
Ing by EPA method 5 and most other
techniques requires an expenditure of
$3,000 to $10,000 per test including about
300 man-hours of technical and semi-
technical personnel. Furthermore, sched-
uling and preparation are required such
that it is seldom possible to conduct a
test with less than 2 weeks notice. There-
fore, method 5 participate tests can be
conducted only on an Infrequent basis.
If there were no standards other than
concentration/mass standards. It would
be possible to Inadequately operate or
maintain pollution control equipment at
all tlm«e except during periods of per-
formance testing. It takes 2 weeks or
longer to schedule a typical stack test.
If only small repairs were required, e.g.,
pump or fan repair or replacement of
fabric filter bags, such remedial action
could be delayed until shortly before the
test Is conducted. For some types of
equipment such as scrubbers, the energy
Input could be reduced (the pressure drop
through the system) when stack tests
weren't being conducted, which would
result in the release of significantly more
particulate matter than normal. There-
fore, EPA has required that operators
properly maintain air pollution control
equipment at all times (40 CFT* 60.11
(d)) and meet opacity standards- at all
times except during periods of startup,
shutdown, and malfunction (40 CFR
80.11 (c)), and during other periods of
exemption as specified In Individual
regulations.
Opacity of emissions is indicative of
whether control equipment is properly
maintained and operated. However, It Is
established as an Independent enforce-
able standard, rather than an indicator
of maintenance and operating conditions
because Information concerning the lat-
ter is peculiarly within the control of
the plant operator. Furthermore, the
time and expense required to prove that
proper procedures have not been fol-
lowed are so great that the provisions of
40 CFR 60.1 l(d) by themselves (without
opacity standards) would not provide an
economically sensible means of ensuring
on a day-to-day basis that emissions of
pollutants are within allowable limit*.
Opacity standards require nothing more
than a trained observer and can be per-
formed with no prior notice. Normally.
It Is not even necessary for the observer
to be admitted to the plant to determine
properly the opacity of stack emissions.
Where observed opacities are within al-
lowable limits, It is not normally neces-
sary for enforcement personnel to enter
the plant or contact plant personnel.
However, In some cases, Including times
when opacity standards may not be
violated, a full investigation of operating
and maintenance conditions will be de-
sirable. Accordingly, EPA has require-
ments for -both opacity limits and proper
operating and maintenance procedures.
2. Some commentators suggested that
the regulatory opacity limits should be
lowered to be consistent with the opacity
observed at existing plants; others felt
that the opacity limits were too strin-
gent. The regulatory opacity limits are
sufficiently close to observed opacity to
ensure proper operation and mainte-
nance of control systems on a continuing
basis but still allow some room for minor
variations from the conditions existing
at the time opacity readings were made.
3. There are specified periods during
which opacity standards do not apply.
Commentators questioned the rationale
for these time exemptions, as proposed.
some pointing out that the exemptions
were not justified and some that they
were Inadequate. Time exemptions fur-
ther reflect the stated purpose of opacity
standards by providing relief from such
standards during periods when accept-
able systems of emission reduction are
judged to be Incapable of meeting pre-
scribed opacity limits. Opacity standards
do not apply to emissions during periods
of startup, shutdown, and malfunction
(see FEDERAL REGISTER of October 19.
1873, 38 FR 28564), nor do opacity stand-
ards apply during periods judged neces-
sary to permit the observed excess emls«
slons caused by soot-blowing and un-
stable process conditions. Some confu-
sion resulted from the fact that the
startup-shutdown-malfunction regula-
tions were proposed separately (see FED-
ERAL REGISTER of May 2, 1973, 38 FR
10820) from the regultlons for this'sroup
of new sources. Although this was point-
ed out hi the preamble (see FEDERAL REG-
ISTER of June 11, 1973, 38 FR 15406) to
this group of new source performance
standards, It appears to have escaped the
notice of several commentators.
4. Other comments, along with • re-
study of sources and additional opacity
observations, have led to definition of
specific time exemptions, where needed,
to account for excess emissions resulting
from soot-blowing and process varia-
tions. These specific actions replace the
generalized approach to time exemp-
tions, 2 minutes per hour, contained In
all but one of the proposed opacity
standards. The intent of the 2 minutes
was to prevent the opacity standards
from being unfairly stringent and re-
fleeted an arbitrary selection of a time
exemption to serve this purpose. Com-
ments noted that observed opacity and
operating conditions did not support this
approach. Some pointed out that these
exemptions were not warranted; other*.
that they were Inadequate. The cyclical
basic oxygen steel-making process, for
example, does not operate In hourly
cycles and! the inappropriateness of 2
minutes per hour in this case would ap-
ply to other cyclical processes which ex-
ist both in sources now subject to stand-
ards of performance and sources for
which standards will be developed in the
future. The time exemptions now pro-
vide for circumstances specific to the
sources and, coupled with the startup-
shutdown-malfunctlon provisions and
the hlgher-than-observed opacity limits,
provide much better assurance that the
opacity standards are not unfairly
stringent.
Dated: February 22, 1B74.
RUSSELL E. TtAnt,
Adminittrator.
FtDfRAL IfOISTM, VOL 3», HO. 47-
-fttOAV, MAtCH •, 1»74
111-59
-------
tULES AND HEGULATIONS
THIe40 PiutecUon of the Environment
CHAPTER I— ENVIRONMENTAL
PROTECTION AGENCY
C—AIK MOOMM8
(nU.Ml-4)
PART 60— STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Opacity Provisions
On June 29. 1973. the United States
Court of Appeals for the District of
Columbia In "Portland Cement Associa-
tion v. Ruckelshaus," 486 F. 3d 376 (1973)
remanded to EPA the standard of per-
formance for Portland cement plants (40
CFR 60.80 et sen.) promulgated by EPA
under section 111 of the Clean Air Act.
In the remand, the Court directed EPA to
reconsider among other things the use
of the opacity standards. EPA has pre-
pared a response to the remand. Copies
of this response are available from the
Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, N.C.
27711. Attn: Mr. Don R. Goodwin. In de-
veloping the response, EPA collected and
evaluated a substantial amount of In-
formation which is summarised and ref-
erenced in the response. Copies of this
information are available for inspection
during normal office hours at EPA's Office
of Public Affairs, 401 M Street SW.,
Washington, D.C. EPA determined that
the Portland cement plant standards
generally did not require revision but did
not find that certain revisions are ap-
propriate to the opacity provisions of
the standards. The provisions promul-
gated herein Include a revision to I 60.11,
Compliance with Standards and Mainte-
nance Requirements, a revision to the
opacity standard for Portland cement
plants, and revisions to Reference Meth-
od ». The bases for the revisions are dis-
cussed in detail in the Agency's response
to the remand. They are summarized
below.
The revisions to I 60.11 include the
modification of paragraph (b) and the
addition of paragraph
-------
reading opacity tn this manner and will
propoee this revision to Method 8 as soon
as this analysis Is completed. The Agency
solicits comments and recommendations
on the need for this additional revision to
Method 9 and would welcome any sug-
gestions particularly from air pollution
control agencies on how we might make
Method 9 more responsive to the needs of
these agencies.
These actions are effective on Novem-
ber 12,197*. The Agency finds good cause
exists for not publishing these actions
as a notice of proposed rulemaklng and
for making them effective Immediately
upon publication for the following
reasons:
(1) Only minor amendments are be-
ing made to the opacity standards which
were remanded.
(2) The VS. Court of Appeals for
the District of Columbia Instructed EPA
to complete the remand proceeding with
respect to the Portland cement plant
standards by November 5,1974.
(3) Because opacity standards are the
subject of other litigation, It Is necessary
to reach a final determination with re-
spect to the basic Issues Involving opacity
at this time In order to properly respond
to this Issue with respect to such other
litigation.
These regulations are Issued under the
authority of sections 111 and 114 of the
Clean Air Act, as amended (42 UJS.C.
1857C-8 and 9).
Dated: November 1,1074.
JOHH QUARLCB,
Acting Atfmlntotrator.
MDftAL tMMSTOt. VOL -99. NO. tlt-
-YUESOAr, NOVtMUt 11,
tUUES AND 1EOULATIONS
Title 4O—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
[FRL 393-7]
PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Five Categories of Sources In the
Phosphate Fertilizer Industry
OPACITY STANDARDS
Many commentators challenged the
proposed opacity standards on the
grounds that EPA had shown no correla-
tion between fluoride emissions and
plume opacity, and that no data were
presented which showed that a violation
of the proposed opacity standard would
Indicate simultaneous violation of the
proposed fluoride standard. For the
opacity standard to be used as an en-
forcement tool to Indicate possible vio-
lation of the fluoride standard, such a
correlation must be established. The
Agency has reevaluated the opacity test
data and determined that the correlation
is insufficient to support a standard.
Therefore, standards for visible emissions
for diammonium phosphate plants, triple
superphosphate plants, and granular
triple superphosphate storage facilities
have been deleted. This action, however,
is not meant to set a precedent re-
garding promulgation of visible emission
standards. The situation which necessi-
tates this decision relates only to fluoride
emissions. In the future, the Agency will
continue to set opacity standards for
affected facilities where such standards
•re desirable and warranted based on
test data.
In place of the opacity standard, a pro-
vision has been added which requires an
owner or operator to monitor the total
pressure drop across an affected facility's
scrubbing system. This requirement will
provide an affected facility's scrubbing
system. This requirement will provide for
a record of the operating conditions of
the •control system, and will serve as an
effective method for monitoring compli-
ance with the fluoride standards.
aflomrouno RcQvnuntnrn
Several comments were received with
regard to the sections requiring a flow
measuring device which has an accuracy
of i 5 percent over Its operating range.
The commentators felt that this accu-
racy could not be met and that the
capital and operating costs outweighed
anticipated utility. First of all, "welgh-
belts" are common devices in the phos-
phate fertilizer industry as raw material
feeds are routinely measured. EPA
felt there would be no economic Impact
resulting from this requirement because
plants would have normally installed
weighing devices anyway. Second, con-
tacts with the industry led EPA to be-
lieve that the ± 6 percent accuracy re-
quirement would be easily met, and a
search of pertinent literature showed
that weighing devices with ± 1 percent
accuracy are commercially available.
Xffective tote. In accordance with sec-
tion 111 of the Act, these regulations pre-
scribing standards of performance for
the selected stationary sources are effec-
tive on August 4, 1075, and apply to
sources at which construction or modifi-
cation commenced after October 22,1074.
RUSSELL E. Turn,
Administrator.
JULY 26, 107S.
ffOOAL HOISTH, VOL 40, NO. 1S2-
-WEDNESDAY, AUOUST 6, It75
111-61
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PART 60—STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Cmiuion Monitoring Requirement* end
Revisions to Performance Testing
Methods
On September 11, 1974 (39 FR 32852),
the Environmental Protection Agency
(EPA) proposed revisions to 40 CPR Part
60, Standards of Performance for New
Stationary Sources, to establish specific
requirements pertaining to continuous
emission monitoring system performance
specifications, operating procedures, data
These requirements would apply to new
and modified facilities covered under
Part 60, but would not apply to existing
facilities.
Simultaneously (39 FR 32871), the
Agency proposed revisions to 40 CPR
Part 51, Requirements for the Prepara-
tion, Adoption, and Submittal of Imple-
mentation Plans, which would require
States to revise their State Implementa-
tion Plans (SIP's) to include legal en-
forceable procedures requiring certain
specified stationary sources to monitor
•missions on a continuous basis. These
requirements would apply to existing fa-
cilities, which are not covered under Part
60.
Interested parties participated in the
rulemaking by sending comments to EPA.
A total of 105 comment letters were re-
ceived on the proposed revisions to Part
60 from monitoring equipment manufac-
turers, data processing equipment manu-
facturers, industrial users of monitoring
equipment, air pollution control agencies
including State, local, and EPA regional
offices, other Federal agencies, and con-
sultants. Copies of the comment letters
received and a summary of the issues and
EPA's responses are available for Inspec-
tion and copying at the U.S. Environ-
mental Protection Agency, Public Infor-
mation Reference Unit, Room 2922 (EPA
Library), 401 M Street, 8.W., Washing-
ton, D.C. In addition, copies of the issue
summary and EPA responses may be ob-
tained upon written request from the
EPA Public Information Center (PM-
215), 401 M Street, 8.W., Washington,
D.C. 20460 (specify Public Comment
Summary: Emission Monitoring Require-
ments). The comments have been care-
fully considered, additional Information
has been collected and assessed, and
where determined by the Administrator
to be appropriate, changes have been
made to the proposed regulations. These
changes are incorporated in the regula-
tions promulgated herein.
BACKGROUND
At the time the regulations were pro-
posed (September 11, 1974), EPA had
promulgated 12 standards of perform-
ance for new stationary sources under
section 111 of the Clean Air Act, as
amended, four of which required the af-
fected facilities to Install and operate
systems which continuously monitor the
levels of pollutant emissions, where the
technical feasibility exists using cur-
rently available continuous monitoring
technology, and where the cost of the
•ULES AND REGULATIONS
systems is reasonable. When the four
standards that require monitoring sys-
tems were promulgated, EPA had limited
knowledge about the operation of such
systems because only a few systems had
been installed; thus, the requirements
were specified in general terms. EPA
Initiated a program to develop perform-
ance specifications and obtain informa-
tion on the operation of continuous
monitoring systems. The program was
designed to assess the systems' accuracy,
reliability, costs, and problems related
to installation, operation, maintenance,
and data handling. The proposed regu-
lations (39 FR 32652) were based on the
results of this program.
The purpose of regulations promul-
gated herein is to establish minimum
performance specifications for continu-
ous monitoring systems, minimum data
reduction requirements, operating pro-
cedures, and reporting requirements for
those affected facilities required to In-
stall continuous monitoring systems.
The specifications and procedures are
designed to assure that the data obtained
from continuous monitoring systems will
be accurate and reliable and provide the
necessary information for determining
whether an owner or operator is follow-
ing proper operation and maintenance
procedures.
SIGNIFICANT COMMENTS AND CHANGES
MADE To PROPOSED REGULATIONS
Many of the comment letters received
by EPA contained multiple comments.
The most significant comments and the
differences between the proposed and
final regulations are discussed below.
(1) Subpart A—General Provisions.
The greatest number of comments re-
ceived pertained to the methodology and
expense of obtaining and reporting con-
tinuous monitoring system emission
data. Both air pollution control agencies
and affected users of monitoring equip-
ment presented the view that the pro-
posed regulations requiring that all
emission data be reported were exces-
sive, and that reports of only excess
emissions and retention of all the data for
two years on the affected facility's
premises Is sufficient. Twenty-five com-
mentators suggested that the effective-
ness of the operation and maintenance of
an affected facility and 1U air pollution
control system could be determined by
reporting only excess emissions. Fifteen
others recommended deleting the report-
ing requirements entirely.
EPA has reviewed these comments and
has contacted vendors of monitoring and
data acquisition equipment for addi-
tional information to more fully assess
the impact of the proposed reporting
requirements. Consideration was also
given to the resources that would be re-
quired of EPA to enforce the proposed
requirement, the costs that would be
incurred by an affected source, and the
effectiveness of the proposed require-
ment in comparison with a requirement
to report only excess emissions. EPA
concluded that reporting only excess
emissions would assure proper operation
and maintenance of the air pollution
control equipment and would result in
lower costs to the source and allow more
effective use of EPA resources by elimi-
nating the need for handling and stor-
ing large amounts of data. Therefore,
the regulation promulgated herein re-
quires owners or operators to report only
excess emissions and to maintain a
permanent record of all emission data
for a period of two years.
In addition, the proposed specification
of minimum data reduction procedures
has been changed Rather than requiring
integrated averages as proposed, the reg-
ulations promulgated herein also spec-
ify a method by which a minimum num-
ber of data points may be used to com-
pute average emission rates. For exam-
ple, average opacity emissions over a six-
minute period may be calculated from a
minimum of 24 data points equally
spaced over each six-minute period. Any
number of equally spaced data points in
excess of 24 or continuously integrated
data may also be used to compute six-
minute averages. This specification of
minimum computation requirements
combined with the requirement to report
only excess emissions provides source
owners and operators with maxinunn
flexibility to select from a wide choke of
optional data reduction procedures.
Sources which monitor only opacity and
which infrequently experience excess
emissions may choose to utilize strip
chart recorders, with or without contin-
uous six-minute integrators; whereas
sources monitoring two or more pollut-
ants plus other parameters necessary to
convert to units of the emission stand-
ard may choose to utilize existing com-
puters or electronic data processes in-
corporated with the monitoring system
All data must be retained for two years,
but only excess emissions need be re-
duced to units of the standard. However,
in order to report excess emissions, ade-
quate procedures must be utilized to in-
sure that excess emissions are identified.
Here again, certain sources with minimal
excess emissions can determine excess
emissions by review of strip charts, while
'sources with varying emission and ex-
cess air rates will most likely need to
reduce all data to units of the standard to
identify any excess emissions. The regu-
lations promulgated herein allow the use
of extractive, gaseous monitoring systems
on a time sharing basis by installing sam-
pling probes at several locations, provided
the minimum number of data points
(four per hour) are obtained.
Several commentators stated that the
averaging periods for reduction of moni-
toring data, especially opacity, were too
short and would result in an excessive
amount of data that must be reduced and
recorded. EPA evaluated these comments
and concluded that to be useful to source
owners and operators as well as enforce-
ment agencies, the averaging time for the
continuous monitoring data should be
reasonably consistent with the averag-
ing time for the reference methods used
during performance tests. The data re-
duction requirements for opacity have
been substantially reduced because the
averaging period was changed from one
111-62
-------
RULES AND REGULATIONS
minute, which was proposed, to six min-
utes to be consistent with revisions made
to Method 9 (39 FR 39872).
Numerous comments were received on
proposed { 60.13 which resulted In several
changes. The proposed section has been
reorganized and revised In several re-
spects to accommodate the comments
and provide clarity, to more specifically
delineate the equipment subject to Per-
formance Specifications in Appendix B,
and to more specifically define require-
ments for equipment purchased prior to
September 11, 1974. The provisions In
I 60.13 are not intended to prevent the
use of any equipment that can be demon-
strated to be reliable and accurate;
therefore, the performance of monitor-
ing systems is specified in general terms
with minimal references to specific equip-
ment types. The provisions in { 60.13(1)
are included to allow owners or operators
and equipment vendors to apply to the
Administrator for approval to use alter-
native equipment or procedures when
equipment capable of producing accurate
results may not. be commercially avail-
able (e.g. condensed water vapor inter-
feres with measurement of opacity),
when unusual circumstances may justify
less costly procedures, or when the owner
or operator or equipment vendor may
simply prefer to use other equipment or
procedures that are consistent with his
current practices.
Several paragraphs in {60.13 have
been changed on the basis of the com-
ments received. In response to comments
that the monitor operating frequency re-
quirements did not consider periods when
the monitor is inoperative or undergo-
ing maintenance, calibration, and adjust-
ment, the operating frequency require-
ments have been changed. Also the fre-
quency of cycling requirement for opacity
monitors has been changed to foe con-
sistent with the response time require-
ment in Performance Specification 1,
which reflects the capability of commer-
cially available equipment.
A second area that received comment
concerns maintenance performed upon
continuous monitoring systems. Six
commentators noted that the proposed
regulation requiring extensive retestlng
of continuous monitoring systems for all
minor failures would discourage proper
maintenance of the systems. Two other
commentators noted the difficulty of de-
termining a general list of critical com-
ponents, the replacement-of which would
automatically require a retest of the sys-
tem. Nevertheless, it is EPA's opinion
that some control must be exercised to
insure that a suitable monitoring system
is not rendered unsuitable by substantial
alteration or a lack of needed mainte-
nance. Accordingly, the regulations pro-
mulgated herein require that owners or
operators submit with the quarterly re-
port information on any repairs or modi-
fications made to the system during the
reporting period. Based upon this infor-
mation, the Administrator may review
the status of the monitoring system with
the owner or operator and, If determined
to be necessary, require retesting of the
continuous monitoring system (•).
Several commentators noted that the
proposed reporting requirements are un-
necessary for affected facilities not re-
quired to install continuous monitoring
^ystems. Consequently, the regulations
promulgated herein do not contain the
requirements.
Numerous comments were received
which indicated that some monitoring
systems may not be compatible with the
proposed test procedures and require-
ments. The comments were evaluated
and, where appropriate, the proposed
test procedures and requirements were
changed. The procedures and require-
ments promulgated herein are applicable
to the majority of acceptable systems;
however, EPA recognizes that there may
be some acceptable systems available
now or in the future which could not
meet the requirements. Because of this,
the regulations promulgated herein in-
clude a provision which allows the Ad-
ministrator to approve alternative testing
procedures. Eleven commentators noted
that adjustment of the monitoring in-
struments may not be necessary as a re-
sult of daily zero and span checks. Ac-
cordingly, the regulations promulgated
herein require adjustments only when
applicable 24-hour drift limits are ex-
ceeded. Four commentators stated that
it is not necessary to introduce calibra-
tion gases near the probe tips. EPA has
demonstrated in field evaluations that
this requirement is necessary in order to
assure accurate results; therefore, the
requirement has been retained. The re-
quirement enables detection of any dilu-
tion or absorption of pollutant gas by the
plumbing and conditioning systems prior
to the pollutant gas entering the gas
analyzer.
Provisions have been added to these
regulations to require that the gas mix-
tures used for the daily calibration check
•of extractive continuous monitoring sys-
tems be traceable to National Bureau of
Standards (NBS) reference gases. Cali-
bration gases used to conduct system
evaluations under Appendix B must
either be analyzed prior to use or shown
to be traceable to NBS materials. This
traceablllty requirement will assure the
accuracy of the calibration gas mixtures
and the comparability of data from sys-
tems at all locations. These traceablllty
requirements will not be applied, when-
ever the NBS materials are not available.
A list of available NBS Standard Refer-
ence Materials may be obtained from the
Office of Standard Reference Materials,
Room B311. Chemistry Building, Na-
tional Bureau of Standards, Washington,
D.C. 20234.
Recertiflcatlon of the continued ac-
curacy of the calibration gas mixtures is
also necessary and should be performed
at intervals recommended by the cali-
bration gas mixture manufacturer. The
.NBS materials and calibration gas mix-
tures traceable to these materials should
not be used after expiration of their
stated shelf-life. Manufacturers of cali-
bration gas mixtures generally use NBS
materials for traceability purposes,
therefore, these amendments to the reg-
ulations will not Impose additional re-
quirements upon most manufacturers.
(2) Subpart - D—Fossil-Fuel Fired
Steam Generators. Eighteen commenta-
tors had questions or remarks concern-
ing the proposed revisions dealing with
fuel analysis. The evaluation of these
comments and discussions with coal sup-
pliers and electric utility companies led
the Agency to conclude that the pro-
posed -provisions for fuel analysis are not
adequate or consistent with the current
fuel situation. An attempt was made to
revise the proposed provisions; however,
it became apparent that an in-depth
study would be necessary before mean-
ingful provisions could be developed. The
Agency has decided to promulgate all of
the regulations except those dealing with
fuel analysis. The fuel analysis provi-
sions of Subpart D have been reserved
in the regulations promulgated herein.
The Agency has initiated a study to ob-
tain the necessary Information on the
variability of sulfur content in fuels, and
the capability of fossil fuel fired steam
generators to use fuel analysis and
blending to prevent excess sulfur dioxide
emissions. The results of this study will
be used to determine whether fuel anal-
ysis should be allowed as a means of
measuring excess emissions, and if al-
lowed, what procedure should be re-
quired. It should be pointed out that
this action does not affect facilities which
use flue gas desulfurization as a means
of complying with the sulfur dioxide
standard; these facilities are still re-
quired to install continuous emission
monitoring systems for sulfur dioxide.
Facilities which use low sulfur fuel as a
means of complying with the sulfur di-
oxide standard may use a continuous
sulfur dioxide monitor or fuel analysis.
For facilities that elect to use fuel anal-
ysis procedures, fuels are not required
to be sampled or analyzed for prepara-
tion of reports of excess emissions until
the Agency finalizes the procedures and
requirements.
Three commentators recommended
that carbon dioxide continuous monitor-
ing systems be allowed as an alternative
for oxygen monitoring for measurement
of the amount of diluents in flue gases
from steam generators. The Agency
agrees with this recommendation and has
included a provision which allows the use
of carbon dioxide monitors. This -pro-
vision allows the use of pollutant moni-
tors that produce data on a wet basis
without requiring additional equipment
or procedures for correction of data to a
dry basis. Where CO, or O, data are not
collected on a consistent basis (wet or
dry) with the pollutant data, or where
oxygen is measured on a wet basis, al-
ternative procedures to provide correc-
tions for stack moisture and excess air
must be approved by the Administrator,
Similarly, use of a carbon dioxide con-
tinuous monitoring system downstream
of a flue gas desulfurization system is not
permitted without the Administrator's
prior approval due to the potential for
absorption of CO, within the control
device. It should be noted that when any
fuel Is fired directly In the stack gases
111-63
-------
tULES AND REGULATIONS
for reheating, the P and F, factors
promulgated herein must be prorated
based upon the total heat input of the
fuels fired within the facility regardless
of the locations of fuel firing. Therefore,
any facility using a flue gas desulfuriza-
tion system may be limited to dry basis
monitoring Instrumentation due to the.
restrictions on use of a CO. diluent moni-
tor unless water vapor is also measured
subject to the Administrator's approval.
Two commentators requested that an
additional factor (F •) be developed for
use with oxygen continuous monitoring
systems that measure flue gas diluents on
a wet basis. A factor of this type was
evaluated by EPA, but is not being pro-
mulgated with the regulations herein.
The error in the accuracy of the factor
may exceed ±5 percent without addi-
tional measurements to correct for va-
riations in flue gas moisture content due
to fluctuations in ambient humidity or
fuel moisture content. However, EPA will
approve installation of wet basis oxygen
systems on a case-by-case basis if the
owner or operator will proposed use of
additional measurements and procedures
to control the accuracy of the F,. factor
within acceptable limits. Applications for
approval of such systems should include
the frequency and type of additional
measurements proposed and the resulting
accuracy of the Fw factor under the ex--
tremes of operating conditions
anticipated.
•» One commentator stated that the pro-
posed requirements for recording heat
input are superfluous because this infor-
mation is not needed to convert monitor-
ing data to units of the applicable stand-
ard. EPA has reevaluated this require-
ment and has determined that the con-
version of excess emissions into units of
the standards will be based upon the
F factors and that measurement of the
rates of fuel firing will not be needed ex-
cept when combinations of fuels are fired.
Accordingly, the regulations promulgated
herein require such measurements only
when multiple fuels are fired.
Thirteen commentators questioned the
rationale for the proposed increased op-
erating temperature of the Method 5
sampling train for fossil-fuel-fired steam
generator particulate testing and the
basis for raising rather than lowering
the temperature. A brief discussion of the
rationale behind this revision was pro-
vided in the preamble to the proposed
regulations, and a more detailed discus-
sion is provided here. Several factors are
of primary importance in developing the
data base for a standard of performance
and in specifying the reference method
for use in conducting a performance test,
Including:
a. The method used for data gathering
to establish a standard must be the
same as, or must have a known relation-
ship to, the method subsequently estab-
lished as the reference method.
b. The method should measure pollut-
ant emissions indicative of the perform-
ance of the best systems of emission re-
duction. A method meeting this criterion
will not necessarily measure emissions
at they would exist after dilution and
cooling to ambient temperature and pres-
sure, as would occur upon release to the
atmosphere. As such, an emission factor
obtained through use of such a method
would, for example, not necessarily be of
. use in an ambient dispersion model. This
seeming inconsistency results from the
fact that standards of performance are
intended to result in installation of sys-
tems of emission reduction which are
consistent with best demonstrated tech-
nology, considering cost. The Adminis-
trator, in establishing such standards, is
required to identify best demonstrated
technology and to develop standards
which reflect such technology. In order
for these standards to be meaningful,
and for the required control technology
to be predictable, the compliance meth-
'ods must measure emissions which are
indicative of the performance of such
systems.
c. The method should include sufficient
detail as needed to produce consistent
and reliable test results.
EPA relies primarily upon Method 5
for gathering a consistent data base for
particulate matter standards. Method 5
meets the above criteria by providing de-
tailed sampling methodology and in-
cludes an out-of-stack filter to facilitate
temperature control. The latter is needed
to define participate matter on a com-
mon basis since it is a function of tem-
perature and is not an absolute quantity.
If temperature is not controlled, and/or
if the effect of temperature upon particu-
late formation is unknown, the effect on
an emission control limitation for partic-
ulate matter may be variable and un-
predictable.
Although selection of temperature can
be varied from industry to industry, EPA
specifies a nominal sampling tempera-
ture of 120" C for most source categories
subject to standards of performance.
Reasons for selection of 120° C include
the following:
a. Filter temperature must be held
above 100° C at sources where moist gas
streams are present. Below 100" C, con-
densation can occur with resultant plug-
ging of filters and possible gas/liquid re-
actions. A temperature of 120° C allows
for expected temperature variation
within the train, without dropping below
100° C.
b. Matter existing in particulate form
at 120° C is indicative'of the perform-
ance of the best particulate emission re-
duction systems for most industrial proc-
esses. These include systems of emission
reduction that may involve-not only the
final control device, but also the process
and stack gas conditioning systems.
c. Adherence to one established tem-
perature (even though some variation
may be needed for some source categor-
ies) allows comparison of emissions from
source category to source category. This
limited standardization used in the de-
velopment of standards of performance
is a benefit to equipment vendors and to
source owners by providing a consistent
basis for comparing test results and pre-
dicting control system performance. In
comparison, in-stack filtration takes
place at stack temperature, which usually
is not constant from one source to the
next. Since the temperature varies, in-
stack filtration does not necessarily pro-
vide a consistent definition of particulate
matter and does not allow for compari-
son of various systems of control. On
these bases, Method 5 with a sampling
v filter temperature controlled at approxi-
mately 120° C was promulgated as the
applicable test method for new fossil-fuel
fired steam generators.
Subsequent to the promulgation of the
standards of performance for steam
generators, data became available indi-
cating that certain combustion products
which do not exist as particulate matter
at the elevated temperatures existing in
steam generator stacks may be collected
by Method 5 at lower temperatures (be-
low 160° C). Such material, existing in
gaseous form at stack temperature,
would not be controllable by emission re-
duction systems involving electrostatic
precipitators (ESP). Consequently,
measurement of such condensible matter
would not be indicative of the control
system performance. Studies conducted
in the past two years have confirmed that
such condensation can occur. At soi rces
where fuels containing 0.3 to 0.85 percent
sulfur were burned, the incremental in-
crease in particulate matter concentra-
tion resulting from sampling at 120° C
as compared to about 150° C was found
to be variable, ranging from 0.001 to
0.008 gr/scf. The variability is not neces-
sarily predictable, since total sulfur oxide
concentration, boiler design and opera-
tion, and fuel additives each appear to
have a potential effect. Based upon these
data, it is concluded that the potential
increase In particulate concentration at
sources meeting the standard of per-
formance for sulfur oxides is not a seri-
ous problem in comparison with the par-
ticulate standard which is approximately
0.07 gr/scf. Nevertheless, to insure that
an unusual case will not occur where a
high concentration of condensible mat-
ter, not controllable with an ESP, would
prevent attainment of the particulate
standard, the samDling temperature al-
lowed at fossil-fuel fired steam boilers is
being raised to 160° C. Since this tem-
perature is attainable at new steam gen-
erator stacks, sampling at temperatures
above 160" C would not yield results nec-
essarily representative of the capabilities
of the best systems of emission reduction.
. In evaluating particulate sampling
techniques and the effect of sampling
temperature, particular attention has
also been given to the possibility that
SO, may react in the front half of the
Method 5 train to form particulate mat-
ter. Based upon a series of comprehen-
sive tests involving both source and con-
trolled environments, EPA has developed
data that show such reactions do not oc-
cur to a significant degree. '
Several control agencies commented on
the Increase in sampling temperature
and suggested that the need is for sam-
pling at lower, not higher, temperatures.
This is a relevant comment and is one
which must be considered in terms of the
basis upon which standards are estab-
lished.
111-64
-------
4ULES AND RIOULATIONS
For existing boilers which are not sub-
ject to this standard, the existence of
higher stack temperatures and/or the
use of higher sulfur fuels may result In
significant condensation and resultant
high indicated participate concentra-
tions when sampling is conducted at
120" C. At one coal fired steam generator
burning coal containing approximately
three percent sulfur, EPA measurements
at 120° C showed an Increase of 0.05 gr/
dscf over an average of seven runs com-
pared to samples collected at approxi-
mately 150° C. It IB believed that this In-
crease resulted, in large part, if not
totally, from 8O3 condensation which
would occur also when the stack emis-
sions are released into the atmosphere.
Therefore, where standards are based
upon emission reduction to achieve am-
bient air quality standards rather than
on control technology (as is the case
with the standards promulgated herein),
a lower sampling temperature may be
appropriate.
Seven commentators questioned the
need for traversing for oxygen at 12
points within a duct during performance
tests. This requirement, which is being
revised to apply only when participate
sampling is performed (no more than 12
points are required) is Included to In-
sure that potential stratification result-
ing from air in-leakage will not ad-
versely affect the accuracy of the
participate test.
Eight commentators stated that the
requirement for continuous monitoring
of nitrogen oxides should be deleted be-
cause only two air quality control re-
gions have ambient levels of nitrogen
dioxide that exceed the national ambient
air quality standard for nitrogen dioxide.
Standards of performance issued under •
section 111 of the Act are designed to re-
quire affected facilities to design and in-
stall the best systems of emission reduc-
tion (taking into account the cost of such
reduction). Continuous emission mon-
itoring systems are required to Insure
that the emission control systems are
operated and maintained properly. Be-
cause of this, the Agency does not 'feel
that it is appropriate to delete the con-
tinuous emission monitoring system re-
quirements for nitrogen oxides; however,
in evaluating these comments the Agency
found that some situations may exist
where the nitrogen oxides monitor Is not
necessary to Insure proper operation
and maintenance. The quantity of nitro-
gen oxides emitted from certain types Of
furnaces is considerably below the nitro-
gen oxides emission limitation. The low
emission level is achieved through the
design of the furnace and does not re-
quire specific operating procedures or
maintenance on a continuous basis to
keep the nitrogen oxides emissions below
the applicable standard. Therefore, in
this situation, a continuous emission
monitoring system for nitrogen oxides is
unnecessary. The regulations promul-
gated herein do not require continuous
emission monitoring systems for nitrogen
oxides on facilities whose emissions are
30 percent or more below the applicable
standard.
Three commentators requested that
owners or operators of steam generators
be permitted to use NO, continuous mon-
itoring systems capable of measuring
only nitric oxide (NO) since the amount
of nitrogen dioxide (NO.) in the flue
gases is comparatively small. The reg-
ulations proposed and those promulgated
herein allow use of such systems or any
system meeting all of the requirements
of Performance Specification 2 of Ap-
pendix B. A system that measures only
nitric oxide (NO) may meet these specifi-
cations Including the relative accuracy
requirement (relative to the reference
method tests which measure NO + NOi)
without modification. However, In the
Interests of maximizing the accuracy of
the system and creating conditions favor-
able to acceptance of such systems (the
cost of systems measuring only NO is
less), the owner or operator may deter-
mine the proportion of NO, relative to
NO In the flue gases and use a factor to
adjust the continuous monitoring system
emission data (e.g. 1.03 x NO = NO,)
provided that the factor is applied not
only to the performance evaluation data,
but also applied consistently to all data
generated by the continuous monitoring
system thereafter. This procedure is lim-
ited to facilities that have less than 10
percent NO: (greater than 90 percent
NO) in order to not seriously impair the
accuracy of the system due to NO> to NO
proportion fluctuations.
Section 60.45(g) (1) has been reserved
for the future specification of the excess
emissions for opacity that must be re-
ported. On November 12, 1974 (39 PR
39872), the Administrator promulgated
revisions to Subpart A, General Provi-
sions, pertaining to the opacity provi-
sions and to Reference Method 9, Visual
Determination of the Opacity of Emis-
sions from Stationary Sources. On
April 22,1975 (40 PR 17778), the Agency
issued a notice soliciting comments on
the opacity provisions and Reference
Method 9. The Agency intends to eval-
uate the comments received and make
any appropriate revision to the opacity
provisions and Reference Method 9. In
addition, the Agency is evaluating the
opacity standards for fossil-fuel flred
steam generators under -i 60.42(a) (2) to
determine if changes are needed because
of the new Reference Method 9. The pro-
visions on excess emissions for opacity
will be issued after the Agency completes
Its evaluation of the opacity standard.
(3) Subpart Q—Nitric Acid Plants.
Two commentators questioned the long-
term validity of the proposed conversion'
procedures for reducing data to units of
the standard. They suggested that the
conversion could be accomplished by
monitoring the flue gas volumetric rate.
EPA reevaluated the proposed procedures
and found that monitoring the flue gas
vplume would be the most direct method
and would also be an accurate method of
converting monitoring data, but would
require the Installation of an additional
continuous monitoring system. Although
this option Is available and would be ac-
ceptable subject to the Administrator's
approval, EPA does not believe that the
additional expense this method (moni-
toring volumetric rate) would entail is
warranted. Since nitric acid plants, for
economic and technical reasons, typi-
cally operate within a fairly narrow
range of conversion efficiencies (90-96
percent) and tail gas diluents (2-5 per-
cent oxygen), the flue gas volumetric
rates are reasonably proportional to the
acid production rate. The error that
would be Introduced into the data from
the maximum variation of these param-
eters is approximately 15 percent and
would usually be much less. It is expected
that the tail gas oxygen concentration
(an indication of the degree of tail gas
dilution) will be rigidly controlled at fa-
cilities using catalytic converter control
equipment. Accordingly, the proposed
procedures for data conversion have been
retained due to the small benefit that
would result from requiring additional
monitoring equipment. Other procedures
may be approved by the Administrator
under 160.13(1).
(4) Subpart H—Sulfurtc Acid Plants.
Two commentators stated that the pro-
posed procedure for conversion of moni-
toring data to units of the standard
would result in large data reduction
errors. EPA has evaluated more closelv
the operations of sulf uric add plants and
agrees that the proposed procedure is in-
adequate. The proposed conversion pro-
cedure assumes that the operating con-
ditions of the affected facility will re-
main approximately the same as during
the continuous monitoring system eval-
uation tests. For sulfuric acid plants this
assumption is invalid. A sulfuric acid
plant is typically designed to operate at
a constant volumetric throughput
(scfm). Acid production rates are altered
by by-passing portions of the process air
around the furnace or combustor to vary
the concentration of the gas entering
the converter. This procedure produces
widely varying amounts of tail gas dilu-
tion relative to the production rate. Ac-
cordingly, EPA has developed new con-
version procedures whereby the appro-
priate conversion factor Is computed
from «n analysis of the 6O3 concentra-
tion entering the converter. Air Injection
plants must make additional corrections
for the diluent air added. Measurement
of the Inlet SO, is a normal quality con-
trol procedure used by most sulfuric acid
plants and does not represent an addi-
tional cost burden. The Reich test or
other suitable procedures may be used.
(5) Subpart J—Petroleum Refineries.
One commentator stated that the re-
quirements for installation of continuous
monitoring systems for oxygen and fire-
box temperature are unnecessary and
that Installation of a flame detection de-
vice would be superior for process con-
trol purposes. Also, EPA has obtained
data which show no identifiable rela-
tionship between furnace temperature,
percent oxygen in the flue gas, and car-
bon monoxide emissions when the facil-
ity is operated in compliance with the
applicable standard. Since firebox tern-*
perature and oxygen measurements may
not be preferred by source owners and
operators for process control, and no
111-65
-------
tUUES AND REGULATIONS
known method is available for transla-
tion of these measurements into quanti-
tative reports of excess carbon monoxide
emissions, this requirement appears to
be of little use to the affected facilities
or to EPA. Accordingly, requirements for
installation of continuous monitoring
systems for measurements of firebox
temperature and oxygen are deleted from
the regulations.
Since EPA has not yet developed per-
formance specifications for carbon mon-
oxide or hydrogen sulfide continuous
monitoring systems, the type of equip-
ment that may be installed by an owner
or operator in compliance with EPA re-
quirements is undefined. Without con-
ducting performance evaluations of such
equipment, little reliance can be placed
upon the value of any data such systems
would generate. Therefore, the sections
of the regulation requiring these systems
are being reserved until EPA proposes
performance specifications applicable to
HrS and CO monitoring systems. The
provisions of § 60.105(a) (3) do not apply
to an owner or operator electing to moni-
tor H:S. In that case, an H,S monitor
should not be installed until specific H?S
monitoring requirements are promul-
gated. At the time specifications are pro-
posed, all owners or operators who have
not entered into binding contractual ob-
ligations to purchase continuous moni-
toring equipment by (date of publication!
will be required to install a carbon
monoxide continuous monitoring system
and a hydrogen sulfide continuous moni-
toring system (unless a sulfur dioxide
continuous monitoring system has been
installed) as applicable.
Section 60.105(a> (2), which specifies
the excess emissions for capacity that
must be reported, has been reserved for
the same reasons discussed under fossil
fuel-fired steam generators.
(6) Appendix B—Performance Speci-
fications. A large number of comments
were received in reference to specific
technical and editorial changes needed
in the specifications. Each of these com-
ments has been reviewed and several
changes in format and procedures have
been made. These include adding align-
ment procedures for opacity monitors
and more specific instructions for select-
ing a location for installing the monitor-
ing equipment. Span requirements have
been specified so that commercially pro-
duced equipment may be standardized
where possible. The format of the speci-
fications was simplified by redefining the
requirements in terms of percent opacity,
or oxygen, or carbon dioxide, or percent
of span. The proposed requirements were
in terms of percent of the emission
standard which is less convenient or too
vague since reference to the emission
standards would have represented a
range of pollutant concentrations de-
pending upon the amount of diluents (i.e.
excess air and water vapor) that are
present in the effluent. In order to- cali-
brate gaseous monitors in terms of a
•specific concentration, the requirements
were revised to delete reference to the
emission standards.
Four commentators noted that the ref-
• erence methods used to evaluate con-
tinuous monitoring system performance
may be less accurate than the systems
themselves. Five other commentators
questioned the need for 27 nitrogen ox-
Ides reference method tests. The ac-
curacy specification for gaseous monitor-
ing systems was specified at 20 percent, a
value In excess of the actual accuracy
of monitoring systems that provides tol-
erance for reference method Inaccuracy.
Commercially available monitoring
equipment has been evaluated using these
procedures and the combined errors (i.e.
relative accuracy) in the reference meth-
ods and the monitoring systems have
been shown not to exceed 20 percent after
the data are averaged by the specified
procedures.
Twenty commentators noted that the
cost, estimates contained in the proposal
did not fully reflect installation costs,
data reduction and recording costs, and
the costs of evaluating the continuous
monitoring systems. As a result, EPA
reevaluated the cost analysis. For opac-
ity monitoring alone, Investment costs
including data reduction equipment and
performance tests are approximately
$20,000, and annual operating costs are
approximately $8,500. The same location
on the stack used for conducting per-
formance tests with Reference Method 5
(particulate) may be used by installing
a separate set of ports for the monitoring
system so that no additional expense for
access is required. For power plants that
are required to install opacity, nitrogen
oxides, sulfur dioxide, and diluent (CX
or CO«) monitoring systems, the invest-
ment cost is approximately $55,000, and
the operating cost is approximately $30,-
000. These are significant costs but are
not unreasonable in comparison to the
approximately seven million dollar in-
vestment cost for the smallest steam
-generation facility affected by these regu-
lations.
Effective date. These regulations are
promulgated under the authority of sec-
tions 111, 114 and 301 (a) of the Clean
Air Act as amended [42 U.S.C. 1857c-«',
1857C-9, and 1857g(a) 1 and become ef-
fective October 6, 1978.
Dated: September 23, 1975.
JOHN QTTARLES,
Acting Administrator.
KDERAl MOISTE*, VOL. 40, NO. 1»4~
-MONDAY, OCTOMR 6, 497S
111-66
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ENVIRONMENTAL
PROTECTION
AGENCY
ELECTRIC UTILITY STEAM
GENERATING UNITS
Proposed Standards of
Performance and Announcement
of Public Hearing on Proposed
Standards
111-67
-------
42154
PROPOSED RULES
[6560-01]
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Port 60]
CPRL 967-1]
STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES
Electric Utility Steam Generating Unit*
AGENCY: Environmental Protection
. Agency (EPA).
ACTION: Proposed rule.
SUMMARY: The proposed standards
of performance would limit emissions
of sulfur dioxide (SO2), particulate
, matter, and nitrogen oxides (NOX)
from new, modified, and reconstructed
electric utility steam generating units
capable of combusting more than 73
megawatts (MW) heat input (250 mil-
lion Btu/hour) of fossil fuel. A new
reference method for determining con-
tinuous compliance with SOa and NO,
standards is also proposed. The Clean
Air Act Amendments of 1977 require
EPA to revise the current standards of
performance for fossil fuel-fired sta-
tionary sources. The intended effect of
this proposal is to require new. modi-
fied, and reconstructed electric utility
steam generating units to use the best
demonstrated systems of continuous
emission reduction and to satisfy the
requirements of the Clean Air Act
Amendments of 1977.
The principal issue associated with
this proposal is whether electric utility
steam generating units firing low-
sulfur-content coal should be required
to achieve the same percentage reduc-
tion in potential SO, emissions as
those burning higher sulfur content
coal. Resolving this question of full
versus partial control is difficult be-
cause of the significant environmental,
energy, and economic implications as-
sociated with each alternative. The
Administrator has not made a decision
on which of the alternatives should be
adopted in the final standard and so-
licits additional data on these impacts
before promulgating the final regula-
tion.
The conference report for the Clean
Air Act Amendments of 1977 says in
pertinent part:
• • • in establishing a national percent re-
duction for new fossil fuel-fired sources, the
conferees agreed that the Administrator
may, in his discretion, set a range of pollut-
ant reduction that reflects varying fuel
characteristics. Any departure from the uni-
form nn Mortal percentage reduction require-
ment, however, must be accompanied by a
finding..that such a departure does not un-
dermine the basic purposes of the House
provision and other provisions of the act,
such as maximizing the use of locally availa-
ble fuels.
This proposal sets forth the full, or
uniform control alternative and sets
forth other alternatives for comment
as well. It should be noted that the
Clean Air Act provides that new
source performance standard^ apply
from the date they are proposed and it
would be easier for powerplants 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 pro-
posal.
The final decision on the appropri-
ate level of control will be made only
after analyses are completed and
public comments evaluated. Because
the decision will require a careful bal-
ancing of environmental, energy, and
economic" impacts, the Administrator
believes that extensive public involve-
ment is essential. Comments on the
factual basis for the standards and
suggestions on the interpretation of
data are actively solicited.
DATES: Comments. Comments must
be received on or before November 20,
1978.
Public hearing. A separate notice is
published in today's FEDERAL REGISTER
announcing the time and place of a
public hearing on the proposed stand-
ards.
ADDRESSES: Comments. Comments
should be submitted to Jack R.
Farmer, Chief, Standards Develop-
ment Branch (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
Background information. The back-
ground information documents (refer
to section on studies) for the proposed
standards 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.
Docket. Docket No. OAQPS-78-1.
containing all supporting information
used by EPA in developing the pro-
posed standards, is available for public
inspection and copying betv/een 8 a.m.
and 4 p.m., Monday through Friday, at
EPA's Central Docket Section, room
2903B, Waterside Mall, 401 M Street
SW., Washington. D.C. 20460.
The docket is an organized and com-
plete file of all the information sub-
mitted to or otherwise considered by
EPA in the development of this pro-
posed rulemaking. The docketing
system is intended to allow members
of the public and industries involved
to readily identify and locate docu-
ments so that they can intelligently
and effectively participate in the rule-
making process. Along with the state-
ment of basis and' purpose of the pro-
mulgated rule and EPA responses to
significant comments, the contents of
the docket will serve as the record in
case of judicial review (section
307(d)(a)).
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:
Summary of proposed standards; ra-
tionale; background; applicability; SO,
standards; particulate matter stand-
ards; NO, standards; studies; perform-
ance testing; and miscellaneous.
SUMMARY OF PROPOSED STANDARDS
APPLICABILITY
The proposed standards would apply
to electric utility steam generating
units that are capable of firing nure
than 73 MW (250 million Btu/hour)
heat input of fossil fuel and for which
construction is commenced after Sep-
tember 18, 1978.
SOj EMISSIONS
The proposed SOa standards would
limit SO, emissions to 520 ng/J (1.2
Ib/million Btu) heat input for solid
fuel (except for 3 days per month) and
340 ng/J (0.80 Ib/million Btu) for
liquid and gaseous fuel (except for 3
days per month). Also, uncontrolled
SOa emissions from solid, liquid, and
gaseous fuel would be required to be
reduced by 85 percent. Compliance
with the SO» emission limitation and
percent reduction would be deter-
mined on a 24-hour daily basis. The
85-percent requirement would apply at
all times except for 3 days per month,
when only a 75-percent SO2 reduction
requirement would apply. The percent
reduction requirement would not
apply if SO2 emissions into the atmo-
sphere are less than 86 ng/J (0.20 lb/
million Btu) heat input.
The percent reduction would be
computed on the basis of overall SO3
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
ctfal pulverizer or in bottom ash and
flyash would also be included in the
computation.
PARTICULATE MATTER EMISSIONS
The proposed particulate matter
emission standard would limit emis-
sions to 13 ng/J (0.030 Ib/million Btu)
heat input. The proposed opacity
standard would limit the opacity of
emissions to 20 percent (6-minute aver-
age). If an affected facility exhibits
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-68
-------
PROPOSB) RULiS
42155
opacity levels higher than 20 percent.
while at the same time demonstrating
compliance with the participate
matter standard, then a source-specific
opacity standard may be established
under 40 CFRMUKe).
NO, EMISSIONS
The proposed NO, emission stand-
ards vary according to fuel character-
istics as follows:
(1) 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.
(2) 260 ng/J (0.60 Ib/million Btu)
heat Input from the combustion of bi-
tuminous coal.
In addition, separate standards arc
being proposed for gaseous and liquid
fuels not derived from coal, lignite
from certain areas, and coal refuse.
RATIONALE
SOi STANDARDS
Under section 11 Ha) of the Act, a
standard of performance 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 consid-
eration cost and any noriair quality
health and environmental impacts and
energy requirements. In addition,
credit te to be given for any cleaning of
the fuel, or reduction In pollutant
characteristics of the fuel, after
mining and prior to combustion.
The 1977 amendments substantially
changed the criteria for regulating
new powerplants by requiring the ap-
plication of technological methods of
control to minimize SO, emissions and
to maximize the use of locally availa-
ble coals. Under the statute, these
goals are to be achieved through revi-
sion of the standards of performance
for new fossil fuel-fired stationary
sources to specify (1) an emission limi-
tation and (2) a percentage reduction
requirement. According to legislative
history accompanying the amend-
ments, the percentage reduction re-
quirement should be applied uniform-
ly on a nationwide basis, unless the
Administrator finds that varying re-
quirements applied to coals of differ-
ing characteristics will not undermine
the objectives of the House bill and
other Act provisions.
The principal issue to be resolved in
this rulemaking is whether a plant
burning low-sulfur coal should be re-
quired to achieve the same percentage
reduction in potential SO, emissions as
those burning higher sulfur content
coals.
Prior to framing alternative SO3
standards, EPA evaluated control
technology in terms of performance.
costs, energy require men ti», and envi-
ronmental impacts. EPA has conclud-
ed that the proposed emission' limits
and control efficiencies are achievable
with well-designed, maintained, and
operated flue gas desulfurlisation sys-
tems but has not determined whether
uniform application of these require-
ments is necessary to satisfy section
111 of trie Ac!. EPA's final decision on
this issue must be based on an assess-
ment of the national, regional, and
local environmental (air, water, and
solid waste), economic, and energy im-
pacts of both the uniform percentage
reduction requirement and the other
alternatives under consideration.
Toward this end, EPA performed ex-
tensive analyses of the potential Im-
pacts associated with each of the alter-
natives at the national, regional, and
plaritsite levels. Economic models were
used for the purpose fo forecasting
the nature of the utility industry in
future years. Evaluation of the data
revealed that the results predicted by
the model were very sensitive to such
assumptions as the rate of growth pre-
dicted for the industry, co
-------
42156
PROPOSED RULES
with the revised standard of perform-
ance will have on the air quality incre-
ment. A source with lower emissions
will use less of the available incre-
ment, thus providing a greater margin
for growth. As mentioned above, the
impact of this standard can be either
to increase or to decrease emission
rates for a given plant depending on
the selection of the coal to be fired. In
view of the above, the Administrator
solicits comments as to how much
Weight should be given to PSD consid-
erations when establishing the final
standard of performance requirement.
PARTICIPATE MATTER STANDARDS
The proposed standards would limit
the emissions of particulate matter to
13 ng/J (0.03 Ib/million Btu) heat
input and would require a 99-percent
reduction in uncontrolled emissions
from solid fuels and a 70-percent re-
duction for liquid fuels. No particulate
matter control would be necessary for
units firing gaseous fuels alone, and
thus a percent reduction would not be
required. The 20-percent opacity (6-
minute average) standard that is cur-
rently applicable to steam electric gen-
erating units (40 CFR Part 60, Sub-
part D) would be retained under the
proposed standard to insure proper op-
eration and maintenance of the partic-
ulate matter control system.
The proposed standards are based on
the performance of a well designed
and operated baghouse or electrostatic
precipitator (ESP). EPA has deter-
mined that these control systems are
the best adequately demonstrated sys-
tems of continuous emissitilh reduction
(taking into consideration the cost of
achieving such emission reduction, and
any nonair quality health and environ-
mental impact, and energy require-
ments).
This determination was reached
after analyzing emission test results
from steam generators firing both
high- and low-sulfur coal and employ-
ing either ESP's or baghouses. Al-
though the baghouse data were based
on units of less than 44 MW, EPA has
concluded that there are no techno-
logical barriers that would preclude
their application on larger units. In
addition, a number of large instala-
tions are now under construction, and
a 350-MW facility equipped with a
baghouse for particulate emission con-
trol recently began operation.
EPA considered a standard of 21 ng/
J (0.05 Ib/million Btu) which could be
met by wet particulate matter scrub-
bers in addition to baghouses and
ESPs, but rejected this option because
using scrubbers could increase emis-
sions of fine particulate matter. A 21
ng/J standard would result in 60 per-
cent higher emissions which could
have an adverse effect on visibility. On
the other hand, an advantage to allow-
ing the use of scrubbers is that a
single scrubber may be able to control
both S*Oa and particulate matter.
It should be noted that there were
no plants available for testing at
which a well designed ESP or bag-
house was followed by an POD
system; thus, the proposed standards
are based on emission measurements
taken at the particulate matter con-
trol device discharge prior to any FQD
unit. Since there is the potential for
an FGD system to affect particulate
emissions, EPA is continuing to assess
this situation. Of particular concern is
the potential contribution of sulfuric
acid mist to the measured particulate
matter emissions. This issue is dis-
cussed in more detail under the partic-
ulate matter standards section of this
preamble. EPA solicits comments and
available data on this matter.
The proposed limit of 13 ng/J (0.03
Ib/million Btu) will effectively pre-
clude the use of ESPs on facilities
using low sulfur coal and require bag-
house control. DOE and the utility in-
dustry believe that baghouse technol-
ogy has not been demonstrated suffi-
ciently to require its use on utility size
facilities. Because of this, DOE recom-
mends that the standard be no less
than 21 ng/J (0.05 Ita/million Btu)
while the industry recommends a
standard of 34 ng/J (0.08 Ib/million
Btu). EPA requests comments on this
this recommendation as well as- on
EPA's proposal.
NO, STANDARDS
The proposed NO, standards for dif-
ferent fuels are based on the emission
limitations achievable through com-
bustion modification techniques. Com-
bustion modification limits NO, forma-
tion in the boiler by reducing flame
temperatures and by minimizing the
availability of oxygen during combus-
tion. The levels to which NO, emis-
sions can be reduced with combustion
modification depend upon the type of
fuel burned, boiler design, and boiler
operating practice.
When considering these factors,
EPA concluded that a uniform stand-
ard could not be applied to all fossil
fuels or boiler types. In addition, EPA
took into consideration the adverse
side effects of low NOX operation such
as boiler tube wastage. As a result, dif-
ferent requirements were developed
for bituminous and subbituminous
coals.
The limitations for coal-derived
liquid and gaseous fuels and shale oil
are based on limits achievable with
subbituminous coals. The limitations
for liquid and gaseous fuels are the
same as those promulgated in 1971
under 40 CFR part 60 subpart D for
large steam generators. These require-
ments were not reexamined since few,
if any, new oil- or gas-fired power
plants are expected to be built. The re-
cently promulgated limitations for lig-
nite combustion (43 PR 9276) have
been incorporated into these regula-
tions without change because no new
data have become available since their
promulgation. Similarly, the exemp-
tion for combustion of coal refuse has
also been retained.
BACKGROUND
In December 1971, under section 111
of the Clean Air Act, the Administra-
tor promulgated standards of perform-
ance to limit emissions of SO2> particu-
' late matter, and NO, from new, modi-
fied, and reconstructed fossil-fuel-fired
steam generators (40 CFR 60.40 et
seq.). Since that time, the technology
for controlling these emissions has im-
proved, but emissions of SOS, particu-
late matter, and NO, continue to be a
national problem. In 1976, steam elec-
tric generating units contributed 24
percent of the particulate matter, 65
percent of the SO2, and 29 percent cf
the NO, emissions on a national basis.
The utility industry is expected to
have continued and significant
growth: approximately 300 new fossil-
fuel-fired power plant boilers are to
begin operation within the next 10
years. Associated with utility growth is
the continued long-term increase in
utility coal consumption from some
650 million tons/year in 1975 to be-
tween 1,400 and 1,800 million tons/
year in 1990. Under the current per-
formance standards for power plants,
national SO* emissions are projected
to increase approximately 15 to 16 per-
cent between 1975 and 1990.
Impacts will be more dramatic on a
regional basis. For example, in the ab-
sence of more stringent controls, util-
ity SOi emissions are expected to in-
crease tenfold to over 2 million tons by
1990 in the West South Central region
of the country (Texas, Oklahoma, Ar-
kansas, 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, stand-
ard so as to require a 90 percent reduc-
tion in SO9 emissions from all coal-
fired power plants. The petition in-
cluded information to support the
claim that advances hi technology
since 1971 called for a revision of the
standard, and EPA agreed to investi-
gate the matter thoroughly. On Janu-
ary 27, 1977 (42 FR 5121), EPA an-
nounced that it had initiated a study
to complete the technological, eco-
nomic, and other documentation
needed to determine to what extent
the SOj standard for fossil-fuel-fired
steam generators should be revised.
On August 7, 1977, President Carter
signed into law the Clean Air Act
Amendments of 1977. The provisions
under section lll(b)(6) of the Act, as
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-70
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PtOfOSED MAIS
42187
amended, require EPA to revise the
standards of performance for fossil-
fuel-fired electric utility steam gener-
ators within 1 year after enactment.
After the Sierra Club petition of
August 1976, EPA Initiated studies to
review the advancement made on pol-
lution control systems at power plants.
These studies were continued follow-
ing the amendment of the Clean Air
Act. In order to meet the schedule es-
tablished by the Act, a preliminary as-
sessment of the ongoing studies was
made in late 1977. A National Air Pol-
lution Control Techniques Advisory
Committee (NAPCTAC) 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 re-
vised by August 7, 1978. When it ap-
peared that EPA would not meet this
schedule, the Sierra Club filed a com-
plaint on July 14, 1978, with the U.S.
District Court for the District of Co-
lumbia requesting injunctive relief to
require, among other things, that EPA
propose the revised standards by
August 7, 1978. A consent order was
developed and Issued by the court re-
quiring the EPA Administrator to (1)
deliver the proposal package to the
office of the Federal Register by Sep-
tember 12, 1978, and (2) promulgate
the final standards within 6 months
after proposal
The purpose of this proposal is to re-
spond to the petition of the Navaho
Tribe and Sierra CUib, and to initiate
the rulemaking required under section
lll(b)(6)of the Act.
APPLICABILITY
The proposed standards would apply
to all electric utility steam generating
units (1) capable of firing more than
73 MW (250 minion Bty/per hour)
heat input of fossil fuel (approximate-
ly 25 MW of electrical energy output)
and (2) for which construction is com-
menced after September 18,1978.
On December 23, 1971, EPA promul-
gated, 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 proposed standards
will not apply to electric utility steam
generating units originally subject to
those standards (subpart D) unless the
affected facilities are modified or re-
constructed.
ELECTRIC UTILITY STEAM GENERATING
UNITS
An electric utility steam generating
unit is defined as any steam electric
generating unit that is physically con-
nected to a power distribution system
and is constructed for the purpose of
selling for use by the general public
more than one-third of its maximum
electrical generating capacity. Any
steam that could be sold to produce
electrical power for sale Is also Includ-
ed when determining applicability of
the standard.
INDUSTRIAL FACILITIES
Industrial steam electric generating
units with heat input above 73 MW
that are constructed for the purpose
of selling more than one-third of their
maximum electrical generation capac-
ity (or steam generating capacity used
to produce electricity for sale) would
be covered under the proposed stand-
ards. Industrial steam generating units
with a heat input above 73 MW that
produce only steam or that were con-
structed for'the purpose of selling- leas
than 6ne-third of their electric genera-
tion capacity are not covered by the
proposed standards, but will continue
to be covered under subpart D.
COGENERATION
Electric cogeneration units (steam
generating units that would produce
steam used for electric generation and
process heat) would be considered
electric utility steam generating units
if they: (1) Were capable of combust-
ing more than 73 MW of fossil fuel
and (2) would be physically connected
to a power distribution system for the
purpose of selling for use by the gen-
eral public more than one-third of
their maximum electrical generating
capacity. Cogeneration facilities that
would produce power only for "in-
house" industrial use would be consid-
ered industrial boilers and would be
covered under subpart D If applicable.
RESOURCE RECOVERY UNITS
Steam electric generating units that
combust nonfossll fuels such as weed
residue, sewage sludge, waste material,
or municipal refuse (either aone or in
combination with fossil fuel) would
only be covered by the proposed stand-
ards If the steam generating unit is ca-
pable of firing more than 73 MW of
fossil fuel. If only municipal refuse
were fired and the unit was not capa-
ble of being fired with more than 73
MW of fossil fuel, the unit would be
considered an incinerator and the
standards under subpart E would
apply. Similarly, the standards under
subpart O for sewage treatment plants
would apply if only sewage sludge
were burned.
COMBINED-CYCLE GAS TURBINES
The proposed standards would cover
boiler emissions from electric utility
combined-cycle gas turbines that are
capable of being fired with more than
73 MW (250 million Btu-hour) heat
input of fossil fuel In the steam gener-
ator, and where the unit is constructed
for the purpose of celling more than
one-third of it* electrical output ca-
pacity to the general public. Electric
utility combined-cycle gas turbine*
that use only turbine exhaust gas to
heat a steam generator (waste heat
boiler) or that are not capable of being
fired with more than 73 MW of fossil
fuel in the steam generator would not
be covered by the proposed standard*.
ISSUK8 ON APPLICABILITY
Noncontlnental
emtatana to power plants located In
that Stake. Anthracite is also low in
sulfur content, but it is more expen-
sive to produce than other locally
available coals. In view of this, propo-
nents of anthracite argue that if con-
trol cost were reduced through a less
stringent standard, anthracite could
then compete with locally available
high sulfur content bituminous coal
(see section 4.7.3 of EPA 4SO/2-7*-
007a-l).
Emerytntr tecfmolosriet. Various
groups expressed concern that if the
proposed standards were rigidly ap-
plied, the development of new and
promising technologies might be dis-
couraged. They suggested that the In-
novative technology waiver provisions
under the* Clean Air Act Amendments
of 1977 are not adequate to encourage
certain capital-intensive, . front-end
FEDERAL REVKTER, V
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42158
PROPOSED RULES
control technologies. Under the inno-
vative technology waiver provisions
(section lll(j) of the Act) the Admin-
istrator may grant waivers for a period
of up to 7 years from the date of issu-
ance of the waiver or up to 4 years
from the start of operation of a facili-
ty, 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. For most front-end con-
"trol technologies, modification or re-
trofit may be economically unreason-
able.
To mitigate the potential impact on
emerging front-end technologies, EPA
proposes to establish slightly less
stringent requirements for initial full-
scale demonstration plants. This
should insure that these standards do
not preclude the development of new
front-end technologies and should
compensate for problems that may
arise when applying them to commer-
cial-scale facilities. The 85 percent SO,
control requirement and the 210-ng/J
NO, standard will provide developers
of new technologies a clear environ-
mental control objective for commer-
cial facilities. However, if the Adminis-
trator subsequently finds that a given
emerging technology (taking into con-
sideration all areas of environmental
impact, including air, water, solid
waste, toxics, and land use) offers su-
perior overall environmental perform-
ance, alternative standards would then
be established by the Administrator.
Under the proposal, the Administra-
tor (in consultation with the Depart-
ment of Energy) would issue commer-
cial demonstration permits for the
first three full scale demonstration fa-
cilities of each of the technologies
listed in the following table. These
technologies have been shown to have
the potential to achieve the standards
established for commercial facilities.
Under such permits, an 80 percent SO,
control level (24-hour average) or a
300 ng/J (0.70 Ib/million Btu) NOX
emission limitation for liquid fuel de-
rived from bituminous coals would be
established. If the Administrator (in
consultation with the Department of
Energy) finds that additional demon-
stration of a given technology is neces-
sary, additional permits may be issued.
No more than 15,000 MW equivalent
electrical capacity would be allocated
for the purpose of commercial demon-
strations under this proposal. This ca-
pacity would be allocated as follows:
MW
Technology
Pollutant
Equivalent
electrical
capacity
Solvent-refined coal SO, 6.000-10.000
Pluldized bed combustion SO, 400-3,000
(atmospheric).
Fluidized bed combustion SO, 200-1,200
(pressurized).
Coal liquefaction NO, 750-10.000
The capacity is presented in ranges
because of uncertainty as to the
amount that will be required for, any
one technology. This use of ranges
should not be construed to mean that
more than 15,000 MW would be allo-
cated for purposes of commercial dem-
onstration permits.
It should be noted that these per-
mits would only apply to the applica-
tion of this standard and would not su-
per cede the new source review proce-
dures and prevention of significant de-
terioration requirements under section
110 of the Act.
Finally, concern has been expressed
as to whether emerging technologies
should be required to comply with the
proposed particulate standard. Since
this concern is based on the same ar-
guments that have been offered in
regard to conventional technologies,
consideration of special provisions will
be tied to the final decision on the par-
ticulate emission limitation.
Modifications. The question has
been raised whether the use of shale
oil coal-based fuels such as coal/oil
mixtures or solvent-refined coal in a
boiler originally designed for oil firing
is considered a modification under 40
CFR 60.14(c). In response, EPA pro-
poses that shifting an existing oil-fired
steam generator to coal/oil mixtures,
shale oil, or coal-derived fuels, would
not be considered a modification and
the facility would not be subject to the
proposed standards.
SO, STANDARDS
General Requirements. The pro-
posed standards for SO, emissions
would require:
1. Reduction of potential SO, emis-
sions for solid, liquid, and gaseous
fuels by 85 percent (24-hour average
control efficiency) except for 3 days
per month when no less than 75 per-
cent is allowed.
2. Maximum allowable emissions
from solid fuel of 520 ng/J (1.2 Ib/mil-
lion Btu) heat input 24-hour average
except for the 3 days per month when
the 75 percent is allowed.
3. Maximum allowable emissions
from liquid or gaseous fuels of 340 ng/
J (0.80 Ib/million Btu) heat input 24-
hour average except for 3 days per
month.
4. Maximum control level of 86 ng/J
(0.20 Ib/million Btu) heat input 24-
hour average.
DISCUSSION
The proposed standards are based on
emission levels and the percentage re-
duction achievable with a well de-
signed, operated, and maintained flue
gas desulfurization (FGD) system.
EPA believes the following types of
FGD systems are capable of achieving
the proposed standards: lime, limes-
tone, Wellman-Lord, magnesium
oxide, and double alkali. In determin-
ing that FGD is the best system of
continuous emission reduction that
has been adequately demonstrated for
removal of SO,, EPA assessed the costs
of achieving the proposed standards
and the nonair quality health and en-
vironmental impacts and energy re-
quirements. Although the proposed
standards are based on the perform-
ance of FGD systems, the use of other
systems should not be discouraged. In
this regard, a number of emerging
technologies show promise.
The proposed percentage reduction
requirement would apply to the com-
bustion of all fossil fuels unless the
emission level of 86 ng/J (0.20 Ib/mil-
lion Btu) is constantly attained (24-
hour average basis). In effect, this
means that all coal-fired and residual-
oil-fired plants would be required to
install FGD or equivalent SO, emis-
sion control systems. On the other
hand, the emission level of 86 ng/J
would permit certain clean fuels, such
as wood waste, to be burned without
FGD or at a very low percentage of re-
duction.
The emission limitations of 520 ng/J
(1.2 Ib/million Btu) for solid fuels and
340 ng/J (0.80 Ib/million Btu) for
liquid and gaseous fuels would place a
maximum limit on SO> emissions re-
gardless of percentage of SO, reduc-
tion attained and thus restrict the
amount of sulfur in the fuel fired.
In determining that FGD systems
were adequately demonstrated and
that they could attain the proposed
limitations, EPA has conducted a
number of studies either directly or
through consultants. To evaluate the
relative performance of FGD systems,
EPA has conducted tests at various
sites. Several absorber designs and ab-
sorbents were tested at the Shawnee
10-MW test facility, emission tests
were performed at various full-scale
operations, and performance results
from other test facilities and scrubber
installations were surveyed, both in
the United States and Japan. A de-
tailed summary of the results from
these studies is provided in section 4.2
of the supplement to the Background
Information document for SO» (EPA
450/2-78-007a-l). In addition, all of
the study reports are available in the
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-12
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PROPOSED RULES
42159
docket for review (see listing set forth
later in this preamble).
PERCENTAGE REDUCTION REQUIREMENT
In establishing the percentage re-
duction requirement for potential SO»
emissions for solid, liquid, and gaseous
fuels, EPA considered the SO, removal
efficiency of prototype, pilot-scale,
and commercial-scale POD systems.
EPA's considerations included meas-
ured variability of percentage reduc-
tion, effects of scrubber and coal
sulfur variability on performance, ef-
fects of a spare module on scrubber re-
liability, and effects of design changes
and maintenance practices on scrubber
reliability.
To establish the variation of FGD
system removal efficiency and the ef-
fects of varying sulfur content of coal
on measured 24-hour-average SO, re-
movals, EPA .obtained continuous
monitoring data from the Cane Bun
and Bruce Mansfield powerplants.
These data were analyzed to establish
the geometric standard deviations.
Based on these analyses, EPA project-
ed the mean Sd removal needed to
comply with the proposed percentage
reduction requirement. At the 99.99
percent confidence level, EPA conclud-
ed that an POD 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) require-
ment.
With respect to long-term SO, re-
moval efficiency, EPA has concluded
that with certain practical changes in
design, operation, and maintenance
practices, lime/limestone FGD sys-
tems can achieve long-term SO» re-
moval of 92 percent. FGD technologies
employing more reactive absorbents
such as magnesium oxide, additive
magnesium-oxide-enriched lime, and
sodium-based liquors can achieve SO,
removal levesls of greater than 92 per-
cent. For a more detailed discussion of
these findings, please refer to section
4.2 of EPA 450/2-78-
-------
42160
PROPOSED RULES
has not revealed any significant prob-
lems from impoundment of treated
POD wastes.
EPA has concluded from these stud-
ies that sludge can be disposed of in an
environmentally sound manner at rea-
sonable costs. EPA will continue to
evaluate the costs and effectiveness of
alternative disposal methods as part of
the economic analyses to be conducted
during the proposal period. Comments
on alternative control methods are in-
vited.
With respect to the potential water
pollution impact. EPA's consultant ex-
amined alternative standards in terms
of their effects on the quality and
- quantity of poworplant waste-water ef-
fluents, and the amount of water con-
sumption. In addition, alternative SO,
control systems were examined rela-
tive to their impact on the above. The
potential environmental effects of SO*
control on effluents were also exam-
ined, and alternative treatment proc-
esses wei <° evaluated.
The water pollution impact report
"Controlling SO* Emissions from Coal-
Fired Steam Electric Generators:
Water Pollution Impact," EPA 600/7-
78-045, concluded that in the aggre-
gate the volume and quality of waste
streams from SO, control systems are
affected very little by alternative
standards and that all effluent
streams can be treated to acceptable
levels using proven, commercially
available technologies. Similarly, a
more stringent standard would have
little effect on water demand when
compared to total plant consumptive
water use.
ALTERNATIVE TECHNOLOGY
A potential alternative to wet FGD
systems is dry SO2 scrubbing. One of
the more effective designs incorpo-
rates the use of a spray dryer and
baghouse. In this system a spray dryer
(similar to a wet SO2 scrubber) is used
with lime, soda ash, or other reactants
to scrub SOa from the flue gases. Be-
cause of the minimal use of water in
the spray dryer (by design), no addi-
tional reheating is required. Following
the spray dryer, a baghouse is used to
collect all particulate matter (includ-
ing SOa reactants).
Spray drying has been tested at pilot
plants, and it may be capable of
achieving 85 percent removal with
lime, soda ash, and other reactants.
. Due to cost considerations, the system
is principally limited to coals with less
than 1.5-percent sulfur if lime is used.
Full-sized spray-drying units for
powerplant application have been or-
* dered and are expected to begin oper-
ation in the early 19SO's. (Refer to sec.
4.3 of EPA 450/2-78-007a-l.)
In addition, a combination of physi-
cal cleaning of the fuel in conjunction
with FGD systems may be a viable
option for reducing SOa, depending on
the particular characteristics of the
coal being used.
MAXIMUM ALLOWABLE EMISSION
LIMITATION
In selecting the proposed maximum
allowable emission limitation, EPA
had to take into consideration two pri-
mary factors: FGD performance and
the impact of the limitation on high-
sulfur coal reserves. In effect, FGD
performance determines the maxi-
mum sulfur content of coals that can
be fired in achieving compliance with
the maximum allowable emission limi-
tation. To estimate coal sulfur content
which can be used, EPA projected SO,
emissions based upon minimum FGD
system performance (i.e., 75 percent
SO» removal 3 days per month) and
maximum daily average sulfur con-
tent. Two alternative maximum al-
lowable emission levels were consid-
ered: (a) 520 ng/J with three exemp-
tions per month that would be coinci-
dent with the proposed percentage re-
duction requirement, and (b) 520 ng/J
with no exemptions.
An analysis of national and regional
coal production in 1990 was performed
for each option. There would be no
significant differences in total nation-
al production with either option. The
analysis included use of cleaned, mid-
western coal when coal cleaning would
be necessary to attain compliance with
the limitation. Sufficient reserves
would be available to satisfy national
demand with either option. However,
on a regional basis a limitation with-
out exemptions could have the poten-
tial of dislocating some coal produc-
tion in the Midwest.
Under either option, midwestern
coal production would increase to
about 300 million tons; however, the
use of some coal reserves in this area
_would be restricted by the limitation
"without exemptions. In the States of
Ohio, Illinois, and in western Ken-
tucky, 60 or more percent of reserves
might be restricted even if coal clean-
ing were used. ,
On the other hand, this analysis
may overstate the potential impacts
since coal mixing or other methods of
reducing the maximum daily average
coal sulfur content were not fully con-
sidered. In view of this, the Agency
will continue to examine the need for
exemptions and the appropriateness
of more stringent maximum emission
levels such as 410 ng/J (1.0 Ib/million
Btu) or 340 ng/J (0.80 Ib/million Btu)
during the comment period. (See sec-
tion 4.7.1 of EPA 450/2-78-007a-l for
a more detailed discussion.)
Based on our present estimates of
the potential impact upon midwestern
coal reserves and production, EPA has
proposed that the maximum allowable
emission limitation should have a 3-
day exemption coincident with the 3
days of 75-percent control in the per-
cent reduction standard. However, the
Agency specifically requests comments
on the level of the emission limit and
the appropriateness of the 3-day ex-
emption.
MAXIMUM CONTROL LEVEL
Under the proposed SO* standard, a
maximum control level would be es-
tablished. Compliance with that con-
trol level would constitute compliance
with the percentage reduction require-
ment. In developing the proposed
standard, EPA has considered two al-
ternatives. The first would establish
the level of 86 ng/J (0.20 Ib/million
Btu). The second would establish a
higher level. Values from 215 ng/J
(0.50 Ib/million Btu) to 340 ng/J (0.80
Ib/million Btu) have been considered.
In essence, these options focus on
the question of whether a powerplant
burning low-sulfur coal should be .-e-
quired to achieve the same percentage
reduction as those burning high-sulfur
coal. The emission level of 86 ng/J
would require virtually all coal-fired
plants to reduce potential emissions by
85 percent. In addition, it would re-
quire the installation of FGD systems
on oil-fired powerplants. Therefore,
this option is commonly referred to as
full scrubbing or full control. On the
other hand, an emission level in the
range of 215-340 ng/J would permit
plants firing low-sulfur coal to reduce
their emissions by less than 85 per-
cent, hence the term partial scrubbing.
Proponents of partial scrubbing
have argued that adoption of a limita-
tion in the range of 215-340 ng/J
would reduce scrubber costs and
permit bypassing of a portion of the
flue gas and thus alleviate the need
for plume reheat and associated
energy costs, since low-sulfur coal in-
herently emits less SO>, proponents of
partial scrubbing maintain that these
benefits can be obtained by partial
scrubbing without a significant in-
crease in emissions nationally. Finally,
it is argued that since coal-fired units
would be cheaper to build and operate
if partial scrubbing were allowed, less
dependence would be placed on exist-
ing oil-fired units and turbines, and a
significant saving of oil would be real-
ized.
On the other hand, proponents of
full control have maintained that
plants firing low-sulfur coal should be
subject to the same reduction require-
ment as those burning high-sulfur
coal. They argue that the statutory re-
quirements and legislative history of
section 111 of the Clean Air Act
Amendments of 1977 require a uni-
form percentage reduction require-
ment. They also point out that apply-
ing full scrubbing to low-sulfur coal is
technologically less demanding and
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-74
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PROPOSED RULES
42161
less expensive than applying full
scrubbing to high-sulfur coal and that
emissions from a plant burning low-
sulfur coal would be up to four times
greater under partial scrubbing than
under full control. Finally, it is argued
that adoption of full control will tend
to promote the use of locally available,
higher sulfur content coals, particular-
ly in the Midwest.
ALTERNATIVE SO, STANDARDS
The following alternative standards
for SO, have been suggested by DOE:
1. Eighty-five percent reduction of
potential SO, emissions during each
calendar month.
2. A maximum control level of 340
ng/J (0.80 Ib SO,/million Btu), not to
be exceeded during any 24-hour
period.
3. A minimum of 33-percent reduc-
tion of potential SO, emissions. The
alternative standards would have the
following operational characteristics:
Monthly averaging. There would be
no daily restriction on the percent re-
duction in potential SO, emissions.
The requirement would be that the
total sulfur emissions summed over
each calendar month be no more than
15 percent of the total sulfur content
of the coal consumed. There would be
no restriction on bypassing some or all
of the flue gas, so long as the monthly
percent reduction requirement is met.
If the monthly requirement is not
met, enforcement penalties would be
applied on the basis of the number of
Individual 24-hour periods during
which the percent reduction was less
than 85 percent.
Maximum control level of 340 ng/J
(0.80 Ib SO,/million Btu). Under this
alternative, a slidlng-scale-percent re-
duction would be required; the full 85-
percent reduction would be required
only when high-sulfur coals were used.
Only the minimum percent reduction
requirement would be enforced for 24-
hour periods when SO, emissions
would be 340 ng/J or less. Any 24-hour
period when emissions are greater
than 340 ng/J and reduction is less
than 85 percent will be a violation of
the percent reduction requirement.
There would be no waivers or exemp-
tion for this daily requirement.
Minimum percent reduction require-
ment of 33 percent. Regardless of
whether the resulting emissions would
be lower than the 340 ng/J (0.80 Ib/
million Btu) emissions requirement,
33-percent reduction in potential SO,
emissions would be required. This
would assure that continuous emis-
sions reduction technology Is applied
to all coals. Including those with the
lowest naturally occurring sulfur con-
tent.
In addition to the DOE proposal, the
utility industry, through the Utility
Air Regulatory Group (UARO), has
also suggested an alternative SO,
standard. The industry proposal con-
templates a sliding scale percentage
production standard for sulfur-dioxide
emissions under which the required
percent reduction declines as sulfur
content In the coal declines. Under the
Industry proposal, there would be a
ceiling of 1.2 pounds of sulfur dioxide
and the required percent reduction
would range between 85-percent re-
moval on a coal with uncontrolled
emissions' of 8 pounds to 20-percent
removal on coals with uncontrolled
emissions of 1 pound or less. Specifi-
cally, for coals with uncontrolled emis-
sions of 5.0 pounds of sulfur dioxide or
greater, the constraining emissions
limit would be 1.2 pounds of nilfur
dioxide. For coals with uncontrolled
sulfur-dioxide emissions of 5 pounds of
sulfur dioxide, percent removal would
be 76 percent and, in the range be-
tween 5 pounds and 4 pounds of un-
controlled emissions, percent removal
would decline by 0.1 percentage point
for each 0.1-pound decrease in uncon-
trolled emissions. For coals with un-
controlled emissions of 4 pounds of
sulfur dioxide, percent removal would
be 75 percent and, between 4 pounds
and 3 pounds of uncontrolled emis-
sions, percent removal would decline
by 0.9 percentage point for each 0.1
pound decrease in uncontrolled emis-
sions. For coals with 3 pounds of un-
controlled emissions, percent removal
would be 66 percent, and between 3
pounds of sulfur dioxide and 2 pounds
of sulfur dioxide, percent removal
would decline by 1.3 percentage points
for each 0.1-pound decrease in uncon-
trolled emissions. At 2 pounds of un-
controlled emissions percent removal
would be 53 percent, and between 2
pounds and 1 pound of uncontrolled
emissions, percent removal would de-
cline by 3.3 percentage points for each
0.1 pound decline in uncontrolled
emissions. For coals with 1 pound or
less of uncontrolled emissions percent
removal would be 20 percent.
Compliance with these sulfur-diox-
ide standards would be determined on
a 30-day average. Industry has also
recommended that consideration be
given to establishing an emission ceil-
ing of 1.5 pounds for coal with uncon-
trolled emissions over 8 pounds.
Comments on these alternative
standards are invited.
ANALYSES OF ALTERNATIVES
In order to determine the appropri-
ate form and level of control for the
'Uncontrolled emissions of sulfur dioxide
are defined as twice the sulfur content of
the coal measured In pounds per million
Btu. For the purposes of this standard,
sulfur content of the coal can be measured
at the plant for unwashed coals and at the
mine prior to washing, for washed coals. In
calculating percent removal, sulfur content
of the flue gas as It leaves the stack la com-
pared with the uncontrolled emissions of
the coal.
proposed standards, EPA has per-
formed extensive analyses of the po-
tential national impacts associated
with the alternative standards. The
Agency employed economic models to
forecast the structure and operating
characteristics of the utility industry
in future years. These models project
the environmental, economic, and
energy impacts of alternative stand-
ards for the electric utility industry.
The major analytical efforts were a
preliminary analysis completed in
April 1978 and a revised assessment
completed in August 1978. While these
analyses'are preliminary and subject
to change, the issues examined and
the results obtained are summarised in
this section and In the following
tables. Further details of the analyses
can be found in "Background Informa-
tion for Proposed SO, Emission Stand-
ards-Supplement," EPA 450/2-78-
007a-l. '
Impacts analyzed. The environmen-
tal Impacts of the alternative stand-
ards were examined by projecting pol-
lutant emissions. The emissions were
estimated nationally and by geograph-
ic region for each plant type, fuel
type, and age category. The Agency is
also evaluating the significance of
waste products generated by the con-
trol technologies and their environ-
mental impacts.
The economic and financial effects
of the alternatives were examined.
This assessment Included an estima-
tion 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 equip-
ment. These costs were examined in
terms of annuallzed costs and annual
revenue requirements. The Impact on
consumers was determined by analyz-
ing the effect of the alternatives on
average consumer costs and average
monthly residential bills. The alterna-
tives were also examined in terms of
cost per ton of SO, removal, Finally,
the present value costs of the alterna-
tives were calculated.
The effects of the alternative pro-
posals on energy production and con-
sumption were also analyzed. National
coal use was projected and broken
down In terms of production by geo-
graphic region and consumption by
region. The amount of western coal
shipped to the Midwest and East was
also estimated. In addition, utility con-
sumption of oil and gas was analyzed.
Major attumptions. Two types of as-
sumptions 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 use/1 to
specify future economic conditions.
FEDERAL REGISTER, VOl 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-75
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PROPOSED RULES
The utility model selected for this
analysis can be characterized as a cost
minimizing economic model. In meet-
ing 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 exist-
ing plants. It also determines the opti-
mum operating level for new and ex-
isting plants. This economic-based de-
.cision 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 associat-
ed with alternative choices.
Such assumptions may not represent
the utility decisionmaking process in
all cases. For example, the model as-
sumes that a utility bases supply deci-
sions on the cost of constructing and
operating new capacity versus the cost
of operating existing capacity. Envi-
ronmentally, this implies a tradeoff
between emissions from new and old
sources. The cost minimization as-
sumption implies that in meeting the
standard a new powerplant will fully
scrub high-sulfur coal if this option is
cheaper than fully or partially scrub-
bing low-sulfur coal. Often the model
will have to make such a decision, es-
pecially in the midwest where utilities
can choose between burning local high
or imported western low-sulfur coal.
The assumption of risk neutrality im-
plies that a utility will always choose
the low-cost option. Utilities, however,
may perceive full scrubbing as involv-
ing 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 trans-
portation of coal, and thus opt for full
control even though partial control is
less costly. Comments are solicited re-
garding the use of a cost optimization
model to simulate utility decisions.
The assumptions used in the analy-
ses to represent economic conditions
in a given year have a significant
impact on the final results readied.
The ma.ior assumptions used in the
EPA analyses are shown in table 1 and
the significance of these parameters is
summarized below. Comments are so-
licited regarding the assumptions
used.
The growth rate in demand for elec-
tric power is very important since this
rate determines the amount of new ca-
pacity which will be needed and thus
directly affects the emission estimates
and the projections of pollution con-
trol costs. A high electric demand
growth rate results in a larger emis-
sion reduction associated with the pro-
posed standards and also results in
higher costs. The April analysis used a
relatively high-growth rate consistent
wit h last year's national energy policy
studies. The August analysis used a
lower growth projection whic ii Is more
in line with curivitt estimates of
demand growth.
The nuclear capacity assumed to be
installed in a given year is also impor-
tant 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 assump-
tion affects the amount of new coal ca-
pacity which will be required to meet a
given electric demand level. In prac-
tice, there are a number of constraints
which limit the amount of nuclear ca-
pacity which can be constructed. The
assumptions used in the EPA analyses
assume high (April) and moderate
(August) growth in nuclear capacity.
The oil price assumption has a
major Impact on tho amount of pre-
dicted 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 gen-
eration 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 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. The
model does not incorporate the Agen-
cy's PSD regulation?: or forthcoming
requirements to protect and enhance
visibility. These requirements may be
important factors for new power-
plants.
Summary of results. The results of
the EPA analyses which were complet-
ed in April and August 1978 are pre-
sented in tables 2 through 8 and dis-
cussed below. Pour alternative stand-
ards were evaluated. Each of the op-
tions presented includes 85-percent
control of inlet SO, (24-hour average),
except for 3 days per month, a maxi-
mum SOa emission limit of 520 ng/J
(1.2 Ib/million Btu) except for 3 days
per month, a particulate matter stand-
ard of 13 ng/J (0.03 Ib/rnillion Btu),
and the proposed NO, standards. The
partial control options in the tables
represent alternative levels for the
maximum control level required on a
24-hour basis.
The projected SOi emissions from
utility boilers are shown by plant type
and geographic region in tables 2
through 5. Table 2 details the 1990 na-
tional SOj emissions resulting from
different plant types and age groups.
As is expected, the proposed standards
result in a significant reduction of SOj
emissions as compared to the current
standards. This reduction ranges from
10 to 12 percent depending on the al-
ternative examined and the assump-
tions used. The emissions from new
plants directly affected by the stand-
ards are reduced by up to 73 percent.
However, the model predicts that the
proposed standards will delay the con-
struction of new plants (note the total
coal capacity changes) causing existing
coal- and oil-fired plants to be utilized
more than they would have been with-
out the proposed standards. This
causes an increase in emissions from
existing plants which offsets part of
the reduction achieved by new plants.
As discussed above, this shift in capac-
ity utilized is predicted by the costs
minimiization model as a result! of in-
creased pollution control cost for new
coal-fired plants. This shift in the gen-
eration mix has important implica-
tions for the decisionmaking process.
For example, if a national energy
policy phases out oil use for electric
power generation, then the April
study's prediction (table 6) of in-
creased oil use in 1990 (over 1975
levels) will not be allowed to occur.
With such a policy, oil consumption
impacts would be similar to those
shown for the August analysis in table
6.
A summary of the projected 1990 re-
gional SOa emissions under the alter-
native control levels is shown in table
3. The combined emissions in the East
and Midwest are reduced about 7 per-
cent as compared to predictions under
the current standards. These emis-
sions are not affected greatly by the
various control options, although
there is a slight increase shown under
the 340 ng/J (0.80 Ib/million Btu)
option in the April analysis. The com-
bined emissions in the west south-cen-
tral and west regions show a greater
variation on a percentage basis. In the
analysis, the full control and 210 ng/J
(0.50 Ib/million Btu) options both
result in a 36-percent reduction from
emission levels under the current
standards, while the 340 ng/J (0.80 lb/
million Btu) option results in a 28-per-
cent decrease.
Regional emissions from the new
plants directly affected by the pro-
posed standards are shown for the
years 1990 and 1995 in tables 4 and 5.
These tables also project the coal con-
sumption and emission factors (million
tons of SO, per quadrillion Btu) for
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-76
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PROPOSED RULES
42163
the new plants. The latter figures are
shown to illustrate the effect of
changes in the amount of new capac-
ity and variations in the utilization of
the new capacity. As noted above, the
1990 emissions from new plants drop
dramatically under the proposed
standards to a level only about one-
third that which would result under
the current standards. This emission
reduction is due in part to lower emis-
sion factors and in part to reduced
coal consumption predicted by the
model. Coal consumption in the East
is virtually unchanged, but in the Mid-
west coal consumption in new plants
drops by one-third as a result of the
proposed standards. In the west south-
central and west regions coal con-
sumption drops 5 to 10 percent which
is about the same as the decline in na-
tional coal consumption at new plants.
The reduced coal consumption in new
plants results from a delay in new
plant construction due to the in-
creased cost of generation from new
coal plants. Reduced coal consumption
by new. plants means, a shift to more
coal and oil burned in existing plants
or new turbines, and this causes the
increase in emissions from existing
and oil-fired plants which was men-
tioned earlier. Table 5 shows that in
1995 the emission reduction due to the
proposed standards is still of the same
magnitude as the 1990 reduction. Also,
since coal capacity is similar under all
options by 1995, the coal consumption
impact of the proposed standards is
less pronounced. Changes in coal con-
sumption in 1995 are almost entirely
due to variations in the utilization of
the new plants.
Table 6 illustrates the effect of the
proposed standards on 1990 national
coal production, western coal shipped
east, and utility oil and gas consump-
tion. This table shows some large dif-
ferences between the two analyses
which are caused by different model
assumptions. For example, in the
model, higher oil prices decrease oil
demand and increase coal use. Increas-
ing transportation costs increases the
delivered price of western coal and re-
duces demand. These two factors
along with the lower growth rate ac-
count for most of the difference in
fuel use estimates between the April
and August results. However, the con-
clusions drawn from the analyses are
similar. For example, in terms of coal
production, both analyses show that
total production will increase in all re-
gions of the country as compared to
1975 levels.
Compared to production under the
current standards, the April analysis
predicts an increase in eastern coal
production under all but the 340 ng/J
(0.80 Ib/million Btu) option. Midwest-
ern production increases under all op-
tions, and western production de-
creases .under all but the 340 ng/J
(0.80 lb/mlllion Btu) option. Western
coal shipped east is lower under all op-
tions than under the current standard,
but is still 14 tc 20 times higher than
1975 levels. Finally, the April analysis
projects that oil consumption by utili-
ties would be increased by the pro-
posed standards. The increase varies
from 300,000 barrels per day for the
full control option to 100,000 barrels
per day for the 210 ng/J (0.50 V3/mil-
lion Btu) and 340 ng/J (0.80 Ib/million
Btu) options.
The August figures predict a smaller
increase in 1990 eastern coal produc-
tion than would be expected under the
current standards. Midwestern produc-
tion increases by 15 to 43 million tons
and western production decreases up
to 56 million tons. The amount of
western coal shipped east is reduced
by 30 million tons by both full control
and 210 ng/J (0.50 Ib/million Btu) op-
tions, and is essentially unchanged by
the higher options. Due to the high
assumed oil price, oil consumption is
reduced from current levels, but the
1990 difference between the options
and the current standards is still an
increase of 200,000 to 300,000 barrels
per day. This increased oil consump-
tion results from the predicted shift
toward existing oil-fired plants and
turbines as a result of .higher pollution
control costs for new coal plants.'
Table 8 shows that as high oil prices
are assumed (August analysis), there is
no difference in 1995 oil consumption
among the options. Finally, the DOI/
DOE coal leasing study (see "Other
Studies") shows a difference of about
50,000 barrels per day in 1990 between
full and partial scrubbing.
The economic effects of the pro-
posed standards are shown in table 7
for 1990. Utility capital expenditures
between 1979 and 1990 increase under
all options as compared to the $500 to
$750 billion estimated to be required
in the absence of a change in the
standard. The capital estimates in
tables 7 and 8 are increments over the
expenditures under the current stand-
ard and include both plant capital (for
new capacity) and pollution control
expenditures. As shown in table 2, the
model estimates total industry capac-
ity is to be 10 GW to 15 OW greater
under the partial control option, and
the cost of this extra capacity makes
the total utility capital expenditures
higher under the 210 ng/J (0.50 lb/
million titu) and 340 ng/J (0.80 Ib/mil-
lion Btu) options, even though pollu-
tion control capital is lower than
under the full control option.
Annualized cost includes a levelized
capital charge, fuel costs, and oper-
ation and maintenance costs associat-
ed with utility equipment. All of the
options cause an increase in annua-
llzed cost over the current standards.
This increase varies, depending on the
assumptions modeled, from $300 mil-
lion to $2 billion or a 1- to 2-percent
increase over the $90 to $100 billion.
The average monthly residential
electric bill is predicted to increase
only slightly by any of the options, up
to a maximum 2-percent increase
shown for full control in the April
analysis. The large total increase in
the monthly bill over 1975 levels is due
In large part to a more than 50-percent
increase in the amount of electricity
used by each customer. Pollution con-
trol expenditures, including those to
meet the current standards, account
for about 15 percent of the increase in
the average monthly bill while the re-
mainder of the cost increase is due to
capacity expansion and general cost
escalations.
The average monthly bill is deter-
mined by estimating utility revenue
requirements which are a function of
capital expenditures, fuel coats, and
operation and maintenance costs.
Therefore, due to changes in the pat-
tern of expenditures, the selection of
the specific year examined has an
Impact on the costs shown. For exam-
ple, the August analysis shows slightly
higher cost in 1990 for the partial con-
trol options as compared to full con-
trol. This is due to the larger amount
of new capacity and the higher associ-
ated capital costs under these options.
By 1995, the amount of new coal ca-
pacity under each option has approxi-
mately equalized, and the estimates
show full control to be most expensive
but by only 12 cents a month over the
average bill under the 340 ng/J (0.80
Ib/million Btu) option (table 8).
The Incremental costs per ton of SO,
removal are also shown in table 7. The
figures are determined by dividing the
change in annualized cost by the
change in annual emissions, as com-
pared to the current standards. These
ratios are a measure of the cost effec-
tiveness of the options, where lower
ratios represent a more efficient re-
source 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 effective-
ness is the average dollar-per-ton cost
at the plant level. This figure com-
pares total pollution control cost with
total SOi 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 $260
per ton on high-sulfur coal to $1,600
per ton on low-sulfur coal. The partial
scrubbing range is from $900 per ton
on low-sulfur coal to $2,000 per ton on
very low sulfur coal.
The economic analysis also estimat-
ed the present value cost in order to5*
facilitate comparison of the options by
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPHMKR 19, Wi
111-77
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42164
PROPOSED RULES
reducing the streams of capital, fuel,
and operation and maintenance ex-
penses to one number. A present value
estimate allows expenditures occur-
ring at different times to be evaluated
on a similar basis by discounting the
expenditures back to a fixed year. Two
types of present value costs have been
estimated in the analysis.
First, an estimate was made of the
present value of costs which will be
faced by the consumers. Essentially,
this represents the present value of
utility revenue requirements. This cal-
culation for the August results shows
a 1990 present value of $26 billion for
the full control option and $15 billion
for the 340 ng/J (0.80 Ib/million Btu)
option as compared to the current
standards.
Second, an "economic" or "real re-
source" present value was estimated.
Real resource present value is de-
signed to measure the level of national
resources committed to the standards.
In computing this resource commit-
ment, construction costs, labor costs,
and other resource costs were consid-
ered, but financing flows and transfer
payments were excluded. Thus,
allowance for funds during construc-
tion, depreciation, interest, taxes, and
other indirect flows were excluded.
This second type of present value
figure gives an estimate of the costs to
society of the options. The calculation
of this value based on the August
analysis results in a 1990 present value
of $9.8 billion for full control and
$10.4 billion for the 340 ng/J (0.80 lb/
million Btu) option. Both types of
present value costs were estimated as
an increment over the current stand-
ards for the years 1990 and 1995.
These figures include capital costs of
plants installed through that date and
operation and maintenance costs for
30 years after the cutoff date. Com-
ments are solicited regarding the cal-
culation and use of present values for
this decision. Comments are also solic-
ited on the appropriateness of using
present value costs to the utility or
present value resources costs to soci-
ety.
A summary of the 1995 impacts of
the proposed standards is shown in
table 8 based on the August analysis.
The total coal capacity figure shows
that by 1995 all the options have equal
capacity. Thus, the options reflect dif-
ferences in amount of low-sulfur coal
use, control, equipment, and variation
in capacity utilization. In general, full
control results In slightly lower emis-
sions, less Western coal shipped East,
higher capital expenditures, and
slightly higher average residential
bills than would result under the par-
tial control options.
Other studies. In addition to the
studies described above, EPA is aware
of three other major studies of the im-
pacts resulting from several recom-
mended standards for powerplants.
One of these studies was performed as
a joint effort of the Departments of
the Interior and Energy for studying
coal leasing policies. Another analysis
was done by the Department of
Energy, and the third study was spon-
sored by a segment of the electric util-
ity industry. These studies were per-
formed for the purpose of analyzing
the impacts of their respective recom-
mended standards along with the EPA
options discussed above. The resul's of
these studies have been considered by
EPA in developing the proposed stand-
ards. More detail on the resultr of
these studies is given in the supple-
ment to the- background document
(EPA 450/2-78-007a-l).
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
III-7I
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42165
Table 1. COMPARISON OF ASSUMPTIONS
April 1978 and August 1978
Assumption
Growth rates
Nuclear capacity
Oil prices ($ 1975)
General Inflation rate
Annual emissions @ 0.5 floor
Coal transportation
Coal mining labor costs
Miscellaneous
April
August
1975-1985:
1985-1995:
5.8X/yr
5.5X
1985: 108 GW
1990: 177
1995: 302
1985: $13/bbl
1990: $13
1995: $13
5.5«/yr
0.5 Ib S02/m1111on Btu
Increases at general
Inflation rate
Increases at general
Inflation rate
1975-1985: 4.8X/yr
1985-1905: 4. OX
1985: 97 GW
1990: 167
1995: 230
1985: $15/bbl
1990: $20
1995: $28
5.5X/yr
0.32 Ib S02/m1ll1on Btu
Increases at general Inflation
rate plus 1%
Increases at general Inflation
rate plus IX
A number of miscellaneous changes were made between the April 1978
study and the August 1978 study. These changes were either correc-
tions or refinements of values used 1n the April study. Examples
of these changes Included revisions to the level of SIP control
assumed In the model, revisions to the scrubbing costs, changes In the'
assumptions regarding Industrial coal consumption, and changes to the
coal supply curves used In the April study.
Plant Category
S1P/NSPS Plants6
New Plants'?
Oil/Gas Plants
Table 2. SUMMARY OF NATIONAL 1990 S02 EMISSIONS FROM UTILITY BOILERS*
(million tons)
Level of Control
1975 Current
Actual Standards
APR
16.8
4.2
2.3
AUG
16.0
4.4
1.1
Full
Control
APR
17.2
1.5
2.5
AUG
16.2
1.2
1.4
Partial Control
210 ng/J 290 ng/J
APR
16.9
2.1
2.3
AUG
16.2
1.3
1.2
APR. AUG
16.1
1.5
1.2
340 ng/J
APR
16.7
3.3
2.3
AUG
16.1
1.8
1.2
Total National Emissions 18.6 23.3 21.4 21.1 18.9 21.3 18.8 - 18.9 22.3 19.1
Total Coal Capacity (GW) 205
465 451
444 428 460 439
- 440 460 444
SOURCE: Background Information for Proposed SO? Emission Standards - Supplement. EPA 450/2-78-007 a-1,
Chapters 2 and 3, August 1978.
Results of EPA analyses completed in April 1978 and August 1978.
Plants subject to existing state regulations or the current NSPS of 1.2 Ib SO? /mill Ion Btu.
cPlants subject to the revised standards.
KOIRAl MOKTER, VOL. 43, NO. 181— TUESDAY, SEfTWMtCK 1*,
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42166
PROPOSED RULES
Table 3. SUMMARY OF 1990 REGIONAL S02 EMISSIONS FOR UTILITY BOILERS3
(million tons)
Level of Control
1975 Current Full
Actual Standards Control
Total National Emissions 18.6
Regional Emissions
Eastb
Midweslc
West South Central
West6
Total Coal Capacity
SOURCE: Background
Chapters 2
9.1
0.0
d 0.2
0.5
^GWJ 205
Information for
APR
23.3
10.8
8.7
2.6
1.3
465
Proposed
- -P
210 nq/J
AUG APR AUG APR
21.4 21.1 18.9 21.3
10.2 9.7 9.0 9.6
7.8 8.5 7.6 8.4
2.3 1.8 1.5 2.0
1.3 1-1 0.8 1.2
451 444 428 460
SO? Emission Standards-Supplement
AUG
18.8
9.0
7.6
1.4
0.9
439
, EPA
290 ng/J
APR AUG
18.9
8.9
7.6
1.5
0.9
- 440
450/2-78-0071-1,
340 ng/J
APR AUG
22.3 19.1
10.2 9.0
8.6 7.6
2.3 1.6
1.3 1.0
460 444
and 3, August 1978.
Results of EPA analyses completed in April 1978 and August 1978.
New England, Middle Atlantic, South Atlantic, and East South Central Census Regions.
cEast North Central and West North Central Census Regions.
West South Central Census Region.
eMountain and Pacific Census Regions.
Table 4. SUMMARY OF 1990 SO, EMISSIONS BY PLANTS SUBJECT TO THE PROPOSED STANDARDS:
* AUGUST 1978 ANALYSIS
Level of Control
East8
Total New Plant Emissions (million tons)
Coal Consumption {1015 Btu) .
Emission Factor (05/10* Btu)
Midwest0
Total New Plant Emissions (million tons)
Coal Consumption (1011 Btu) .
Emission Factor (IS/100 Btu)D
West South. Central*1
Total Hew Plant Emissions (million tons)
Coal Consumption (1015 Btu) .
Emission Factor (*S/106/Btu)D
West6
Total New Plant Emissions (million tons)
Coal Consumption (1015 Btu) .
Emission Factor (#S/106/Btu)
SOURCE: Background Information for Proposed
Current
Standards
2.1
3.47
0.60
0.60
1.17
0.48
1.2
1.93
0.60
0.6
1.25
0.40
SO, Emission
Full
Control
0.7
3.41
0.21
0.2
0.79
0.21
0.2
1.67
0.14
0.1
1.19
0.09
Standards -
210 ng/J 290 ng/J 340 ng/J
0.7
3.43
0.21
0.2
0.80
0.21
0.3
1.97
0.14
0.2
1.18
0.14
Supplement. EPA
0.7
3.48
0.22
0.2
0.81
0.23
0.4
1.96
0.18
0.2
1.19
0.19
450/2-78-007a-l,
0.8
3.47
0.23
0.2
0.81
0.26
0.5
1.95
0.24
0.3
1.24
0.24
*New England, Middle Atlantic. South Atlantic, and
East South Central Census Regions.
Ratios may not be obtained exactly from figures
shown here due to rounding.
cEast North Central and West North Central
Census Regions.
West bouth Central Census Kegion.
fountain and Pacific Census Regions.
FEDERAL REGISTER, VOL. 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-80
-------
PROPOSED RULES
Table 5. SUMMARY OF 1995 SO, EMISSIONS bY PLANTS SUBJECT TO THE
PROPOSED STANDARDS* AUGUST 1978 ANALYSIS
Level of Control
42167
East8
Total New Plant Emissions (million tons)
Coal Consumption (10" Btu) h
Emission Factor (»S/I06 Btu)°
M1dwestc
Total New Plant {missions (million tons)
Coal Consumption (10" Btu) h
Emission Factor (OS/108 Btu)D
west South Central*1
Total New Plant Emissions (million tons)
Coal Consumption (1019 Btu) h
Emission Factor (IS/10' Btu)
West6
Total New Plant Emissions (million tons)
Coal Consumption (10" Btu) K
Emission Factor (#S/10e Btu)
SOURCE: Backaround Information for Prooosed
Current
Standards
4.0
6.73
0.60
1.2
2.21
0.53
1.6
2.63
0.60
1.1
2.28
0.44
Full
Control
1.3
6.J9
0.21
0.4
1.94
0.21
0.4
2.77
0.15
0.2
2.32
0.09
SO- ^mission Standards
210 ng/J 290 ng/J 340
1.3
6.47
0.21
0.4
1.92
0.21
0.4
2.73
0.15
0.3
2.29
0.13
- Supplement.
1.4
6.49
0.21
0.5
1.99
0.23
O.S
2.70
0.19
0.4
2.27
0.19
EPA 450/2-7B-007a-l ,
ng/J
1.5
6.6/
0.22
0.5
2.00
0.26
0.7
2.68
0.25
0.5
2.27
0.22
*New England, Middle Atlantic. South Atlantic. cEast North Central and West North Central
and East South Central Census Regions. Census Regions.
Ratios may not be obtained exactly from West South Central Census Region.
figures shown here due to rounding. "Mountain and Pacific Census Regions.
U.S. Coal Production
(million tons)
East
Midwest
West
TOTAL
Western coal shipped east
(million tons)
011/gas consumption in power
plants (million bbl/day)
TABLE 6. SUMMARY OF IMPACTS ON FUELS IN 1990*
Level of Control
1975 Current Full Partial Control
Actual Standards Control 210 ng/J 290 ng/J 340 ng/J.
APIL AU.6 APR. AUfi. APR AljG APR^ AUQ APR AUG
396
151
100
647
21
3.1
441
298
1027
1767
455
3.0
465 467 449 464 450
275 375 318 353 316
785 870 736 938 752
1767 1525 1711 1502 1755 1517
149 299 118 346 117
1.2 3.3 1.5 3.1 1.4
- 450 418 449
- 294 307 290
- 779 1055 784
- 1523 1780 1523
- 147 429 152
- 1.4 3.1 1.4
SOURCE: Background Information for Proposed SO? Emission Standards - Supplement, LPA 450/2-78-007a-l,
Chapter I & 3, August 197d —
'Results of EPA analyses completed In April 1978 and August 1978.
FEDERAL REGISTER, VOL. 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-81
-------
42168
PROPOSED RULES
Table 7. SUMMARY OF 1990 ECONOMIC IMPACTS
a
Level of Control
Current Full --partial Control
Standards Control 210 ng/J 290 ng/J
APR,
Average monthly resi-
dential bills
(I/month) 45.31
Incremental Utility
capital expenditures,
cumulative 1976-1990
($ billions)
liicroiiK'ntal Annual ized
cost (i bill ions)
Incremental Cost of
S02 Reduction ($/ton)
SOURCE: Background Information for Proposed
EPA 450/Z-78-007a-l, Chapters^ & 3
Results of EPA analyses completed in April
AUG. .APR AUG_ .APRn AUG_ APR AUG.
43.89 46.39 44.22 46.20 44.48 - 44.38
10 0 15 8-4
2.0 1.9 1.3 1.7 - 1.3
l>85 754 640 642 - 511
S00 Emission Standards - Supplement,
, Adgust l'J/0.
19/0 and August 1978.
34U mj/J
APg. AUG
45.47 44.38
3 5
0.3 1.1
303 486
Table 8. SUMMARY OF 1995 IMPACTS: AUGUST 19/8 ANALYSIS
1975
Actual
National Emissions 18.6
(million tons)
Now Plant [missions3 -
(million tons)
U.S. Coal Production 647
(million tons)
Western Coal Shipped East 21
(million tons)
Oil/Gas Consumption 3.1
(million bbl/day)
Incremental Cumulative Capital -
Expenditures (1975 $ billion)
Incremental Annualized Cost —
(1975 $ billion)
Average Monthly Residential _
Bill (19/5 S/month)
Total Coal Capacity (GU) 198
SOURCE: Background Information for Proposed
Level of Control
C rr t F 1 1 D • i •
Standards Control 210 ng/J 290 ng/J
23.3 18.5 18.5 18.7
7.9 2.4 2.5 2.8
1865 1865 1858 1868
210 130 133 190
0.8 0.9 0.9 0.9
32 26 20
2.6 2.3 2.0
45.34 46.22 46.13 46.12
507 500 580 580
SO? Emission Standards-Supplement, EPA 450/2-78-007a-l
340 ng/J
19.0
3.2
1066
196
0.9
19
1.9
46.10
580
Plants subject to the revised standards.
FEDERAL REGISTER, VOL. 43, NO. 182—TUESDAY, SEPTEMKR 19, 1978
111-82
-------
PROPOSED RULES
42169
PARTICULATE MATTER STANDARDS
The proposed standards would limit
the emissions of participate matter to
13 ng/J (0.03 Ib/million Btu) heat
input and would require a 99-percent
reduction in uncontrolled emissions
from solid fuels and a 70-percent re-
duction for liquid fuels. No partlculate
matter control would be necessary for
units firing gaseous fuels alone, and
thus a percent reduction would not be
required for gaseous fuels. The 20-per-
cent opacity (6-minute average) stand-
ard that is currently applicable to
steam electric generating units (40
CFR Part 60, Subpart D) would be re-
tained under the proposed standards.
An opacity standard is proposed to
insure proper operation and mainte-
nance of the partlculate matter con-
trol system. If an affected facility
were to comply with all applicable
standards except opacity, the owner or
operator may request the Administra-
tor under 40 CFR 60.11(e) to establish
a source specific opacity standard for
that affected facility.
The proposed standards are based on
the performance of a well designed
and operated baghouse or electrostatic
precipitator (ESP). EPA has deter-
mined that these control systems are
the best adequately demonstrated sys-
tems of continuous emission reduction
(taking into, consideration the cost of
achieving such emission reduction, and
any nonair quality health and environ-
mental Impact and energy require-
ments).
EPA has evaluated data from more
than 50 emission test runs conducted
at eight baghouse-equipped, coal-fired
steam generating units. The data from
two tests exceeded the proposed stand-
ard, however, it is EPA's judgment
that the emission levels at the two
units which had measured emission
levels above the proposed standards
could be reduced to below the pro-
posed standards through an improved
maintenance program. EPA believes
that baghouses with an air-to-cloth
ratio of 0.6 actual cubic meters per
minute per square meter (2 ACFM/ft")
would achieve the proposed standards
at pressure drops of less than 1.25 kilo-
pascals (5 in. H,O). EPA has concluded
that this air/cloth ratio and pressure
drop are reasonable when considering
cost, energy, and nonair quality im-
pacts.
EPA collected emission data from 21
ESP-equipped, coal-fired steam gener-
ating units. The nominal sulfur con-
tent of the coals being fired ranged
from 0.4 percent to 1.9 percent. None
of the 21 units tested were designed to
achieve an emission level equal to or
below the proposed standard of 13 ng/
J (0.03 Ib/million Btu) heat Input;
however, emissions from 9 of the 21
units were below the proposed stand-
ard. All of the units tested which were
firing coal with a sulfur content great-
er than 1 percent and had a hot side
ESP with a specific collection area
greater than 89 square meters per
actual cubic meter per second (452 ft1/
1,000 ACFM), or a cold side ESP with
a specific collection area greater than
85 square meters per actual cubic
meter per second (435 ft1/1,000
ACFM), had emission levels below the
proposed standards. EPA evaluated
emission levels from units burning rel-
atively low-sulfur coal because it is
more difficult for an ESP to collect
partlculate matter emissions generat-
ed by the combustion of low-sulfur
coal than high-sulfur coal. ESP's re-
quire a larger specific collection area
when applied to units burlng low-
sulfur coal than to units burning high-
sulfur coal, because the resistivity of
the fly ash is higher with low-sulfur
coal. To meet the proposed standard,
EPA believes that an ESP used on low-
sulfur coal would have to have a spe-
cific collection area from around 130
(hot side) to 200 (cold side) square
meters per actual cubic meter per
second (650 to 1,000 ft* per 1,000
ACFM) while an ESP used on high-
sulfur coal (3.5 percent sulfur) would
only require around 72 square meters
per actual cubic meter per second (360
ft8 per 1,000 ACFM).
ESP's have been traditionally used
to control particulate emissions from
powerplants. High-sulfur coal pro-
duces fly ash with a low electrical re-
sistivity which can be readily collected
with an ESP. However, low-sulfur coal
produces fly ash with high electrical
resistivity, which is more difficult to
collect. The problem of high electrical
resistivity fly ash can be reduced by
using a hot side ESP (ESP located
before combustion air preheater)
when firing low-sulfur coal. Higher fly
ash collection temperatures Improve
ESP performance by reducing fly ash
resistivity for most types of low-sulfur
coal (for example, increasing the fly
ash collection temperature from 177°
C (350° F) to 204" C (400° F) can
reduce electrical resistivity of fly ash
from low-sulfur coal by approximately
50 percent).
While EPA believes that ESP's can
be applied to high-sulfur coal at rea-
sonable costs to meet the proposed
standards, it recognizes that applying
a large, high efficiency ESP to a facili-
ty using low-sulfur coal to meet the
proposed standards will be more ex-
pensive. In view of this, EPA believes
that a baghouse control system could
be applied on utility-size facilities
firing low-sulfur coal at a lower cost
than an ESP. Although the largest
baghouse-controlled coal-fired steam
ge'nerator for which EPA has partlcu-
late matter emission data is 44 MW,
several larger installations are current-
ly under construction, and EPA plans
to test a 360-MW powerplant con-
trolled with a baghouse which recent-
ly began operation. Since baghouses
are designed and constructed in mod-
ules rather than as one larger unit,
there should be no technological bar*
riers to scaling them up to a utility
sized facility. Twenty-four baghouse-
equipped coal-fired utility steam gen-
erators are scheduled to be operating
by the end of 1978 and an additional
30 units are planned to start operation
after 1978. About two-thirds of these
planned units will be larger than 150-
MW electrical output capacity, and
more than one-third of these planned
baghouse systems will be for units
being fired with coal containing more
than 3 percent sulfur. EPA therefore
believes that baghouses have been
adequately demonstrated for even the
largest utility-sized facility.
EPA collected emission test data
from seven coal-fired steam generators
controlled by wet particulate matter
scrubbers. Data from five of the seven
resulted In emission levels less than 21
ng/J heat input (0.05 Ib/million Btu).
Data from only one of the seven were
less than 13 ng/J (0.02 Ib/million Btu)
heat input. In view of this, EPA be-
lieves ' that wet particulate matter
scrubbers would not be capable of
complying .with the proposed stand-
ards under most conditions.
EPA considered proposing the stand-
ard at a level o*21 ng/J (0.05 Ib/mil-
lion Btu) in order to allow the applica-
tion of wet particulate matter scrub-
bers in addition to baghouses and
ESP's'. This option was rejected, be-
cause EPA believes that allowing
scrubbers would cause an increase in
the emissions of fine particulate
matter without compensating advan-
tages. In addition to 60 percent higher
emissions, a particulate matter scrub-
ber would require three times as much
energy to operate as a dry control
system, and would also Increase water
consumption and waste water treat-
ment requirements. An increase in fine
particulate emissions would have an
adverse effect on visibility. The prima-
ry suggested advantage to allowing the
use of scrubbers for particulate matter
control would be to allow a single
scrubber to control both SO, and par-
ticulate matter emissions which would
result in a cost savings.
The Department of Energy (DOE)
and others believe that "the proposed
standard of 3 ng/J (0.03 Ib/million
Btu) will preclude the use of ESP's on
facilities using low-sulfur coal and re-
' quire baghouse control which they be-
lieve has not been demonstrated on
utility-size facilities. Because of this,
DOE recommends that the standard
be no less than 21 ng/J (0.05 Ib/mil-
lion Btu). The Utility Air Regulatory
Group (UARQ) also maintains that
baghouses have not been adequately
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-83
-------
42170
PROPOSED RULES
demonstrated, particularly when
firing high-sulfur coal. They further
believe that ESP's, cannot achieve the
proposed standard of 13 ng/J at rea-
sonable cost. In view of this, UARG
recommends an emission limitation of
34 ng/J (0.08 Ib/million Btu). In doing
so, they maintain a 34-ng/J standard
would encourage baghouses but not
eliminate precipitators from use.
EPA has investigated the possibility
that PGD control systems affect par-
ticulate matter emissions. Three possi-
ble mechanisms were investigated: (1)
PGD system sulfate carryover from
the scrubber slurry, (2) particulate
matter removal by the PGD system,
and (3) particulate matter generation
by (.he FGD system through condensa-
tion of sulfuric acid mist (HaSO,).
To address the first mechanism,
EPA obtained data from three differ-
ent steam generators that were all
equipped with FGD systems and that
had low particulate matter emission
levels at, the PGD inlet. The data from
all three facilities indicated that par-
ticulate emissions did not increase
through the PGD system. Proper mist
eliminator design and maintenance is
important, in preventing scrubber
liquid entraininent which could cause
the outlet particulate loading to
exceed inlet particulate loading.
In relation to the second mecha-
nism, PGD system removal of particu-
late matter, the data from the three
PGD systems available to EPA indicat-
ed that particulate matter emissions
were reduced by the PGD systems in
all three cases. That is, the particulate
matter discharge concentration from
the FGD system was less than the
concentration at the PGD inlet. This
property has been particularly noted
at steam generators equipped with
ESP's upstream of PGD systems.
Thf third mechanism is the poten-
tial condensation of sulfuric acid mist
(HjSO,) from sulfur trioxide (SO,) in
the flue gas. At a typical steam gener-
ator, 97 to 95) percent of the fuel
sulfur is converted to SO2 and 1 to 3
percent is converted to SO,. Typical
stack gas temperatures at a coal-fired
steam generator without an PGD
system are between 150° C and 200' C
(300' P to 400° P). At these tempera-
tures, most SO., remains in a gaseous
state and does not form sulfuric acid.
At lower temperatures, water vapor
condenses and combines with SO., to
form sulfuric acid. The dewpoint tem-
perature for sulfuric acid ranges be-
tween 120' C (250' F) and 175° C (350°
P). The lower temperature would cor-
respond to low-sulfur coal and higher
temperature would correspond to
high-sulfur coal.
Available test data indicate that an
PGD system would remove about 50
percent of the SOS in the flue gas and
thus reduce the potential for sulfuric
acid mist formation. However, if sulfu-
ric acid mist is formed in the flue
gases, there is a potential for its Inter-
ference with the particulate matter
performance te'st. Under method 5, a
sample is extracted at a probe tem-
perature of about 160° C (320° P). This
assures that SO3 does not condense on
the sampling filter when sampling
powerplants that do not have PGD
systems. However, when sampling
powerplants with FGD systems (par-
ticularly when combusting high-sulfur
coal), there is a potential for sulfuric
acid mist to form at the reduced flue
gas temperatures. If acid mist forms, it
may Interact within the sampling
train to form sulfate compounds that
are not vaporized at the 160° C (320°
F) sampling temperature. Also, sulfu-
ric acid mist may remain deposited
within the test probe itself. In either
case, the net result could be a high
measurement of particulate matter.
EPA obtained data from three FGD
equipped powerplants to determine
acid mist formation potential. All of
these plants were firing low-sulfur
coal. The data indicate that SO, con-
version to sulfuric acid mist is not a
problem. EPA believes these data sup-
port the conclusion that an FGD
system on low-sulfur coal-fired power-
plants does not increase particulate
emissions through sulfuric acid forma-
tion. Thus, EPA believes compliance
with the proposed particulate matter
standard is demonstrated to be achiev-
able when firing low-sulfur coal.
In a case where an FGD system Is
used with higher sulfur coal, sufficient
data have not become available to
fully assess the effect of sulfuric acid
formation on measured particulate
matter. The proposed standard is
based on emission test data at the par-
ticulate matter control device dis-
charge prior to any PGD system. EPA
plans to continue investigating .this
subject and will consider any data
available on the impact of sulfuric
acid mist on the particulate matter
standard.
The 1977 amendments require that
EPA specify, in addition to an emis-
sion limitation, a percent reduction in
uncontrolled emission levels for fossil
fuel-fired stationary sources. The pro-
posed standard would require a 99-per-
cent reduction for solid fuels and a 70-
percent reduction for liquid fuels. Be-
cause of the difficulty of sampling par-
ticulate matter upstream of the con-
trol device (due to the complex partic-
ulate matter sampling conditions), the
proposed standard would not require
direct performance testing for the par-
ticulate matter emission reduction
level. The percent reduction is not
controlling, and performance testing
for the emission limitation would sat-
isfy the requirements for performance
testing.
EPA Is requesting comments on the
proposed level of the particulate
matter standard and the basis for the
standard,
NO,
The proposed NO, emission stand-
ards are based on emission levels
achievable with a properly designed
and operated steam generator whitiM
utilizes combustion modification tech-
niques to reduce NO, formation. The
proposed standards are as follows:
(1) 86 ng/J heat input (0.20 Ib/mil-
lion Btu) from the combustion of any
gaseous fuel, except gaseous fuel de-
rived from coal;
(2) 130 ng/J heat input (0.30 Ib/mil-
lion Btu) from the combustion of any
liquid fuel, except shale oil and liquid
fuel derived from coal;
(3) 210 ng/J heat input (0.50 Ib/mil-
lion Btu) from the combustion of sub-
bituminous coal, shale oil, or any solid,
liquid, or gaseous fuel derived from
coal;
(4) 340 ng/J (0.80 Ib/million 3tu)
from the combustion in a slag tap fur-
nace of any fuel containing more t han
25 percent, by weight, lignite wi ich
has been mined in North Dakota,
South Dakota, or Montana;
(5) Combustion of a fuel containing
more than 25 percent, by weight, coal
refuse would be exempt from the NO,
standards and monitoring require-
ments;
(6) 260 ng/J (0.60 Ib/million Btu)
from the combustion of any solid fuel
not specified under (3), (4), or (5);
(7) Percent reductions in uncon-
trolled NO, emission levels would be
required; however, the percent reduc-
tion would not be controlling, and
compliance with the NOX emission
limits (ng/J) would assure compliance
with the percent reduction require-
ments, the National Appeals Board
Most new electric utility steam gen-
erating untis are expected to burn pul-
verized coal. Consequently, the NO,
studies used to develop the proposed
standards have concentrated on the
combustion of pulverized coal. The
proposed standards for pulverized coal
are based on the application of com-
bustion modification techniques (i.e.,
staged combustion, low excess air, and
reduced heat release rate) which EPA
has concluded represent the best dem-
onstrated system of continuous emis-
sion reduction (taking into considera-
tion the cost of achieving such emis-
sion reduction, any nonair quality
health and environmental impact, and
energy requirements) for electric util-
ity power plants.
The proposed standards would re-
quire continuous compliance (based on
a 24-hour average), except during peri-
ods of startup, shutdown, or malfunc-
tion as provided under 40 CFR 60.8.
Percent reduction requirements are in-
FEDERAL REGISTER, VOl 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-84
-------
PROPOSED RULES
42171
eluded in the proposed standards as a
result of provisions in the 1977
Amendments. As with the proposed
particulate matter standard, the per-
cent reductions for NO, are not con-
trolling, and compliance testing for
the NO, emission limitations (ng/J)
would satisfy all compliance testing re-
quirements for NO,.
Combustion modification techniques
limit the formation of NO, in the
boiler by reducing flame temperatures
and by minimizing the availability of
oxygen during combustion. Elevated
temperatures and high oxygen levels
would otherwise enhance the forma-
tion of NO,. The levels to which NO,
emissions can be reduced with combus-
tion modifications depend on the type
of fuel burned, the boiler design, and
boiler operating practices. All four of
the major boiler manufacturers utilize
combustion modification techniques in
their modern units; however, some
manufacturers' techniques may be
more effective than others.
EPA has conducted NO, emmisslon
tests at six modern electric utility
steam generating units which burn
pulverized coal, representing two of
the major boiler manufacturers. These
tests indicate that during low NO, op-
eration of modern units, emission
levels below 210 ng/J heat input (0.50
Ib/million Btu) are easily attainable.
If the potential side effects associated
with low NO, operation were not con-
sidered, it would be reasonable to es-
tablish an NO, emission limit for pul-
verized coal-fired units at 210 ng/J
heat input.
The side effects EPA has considered
include: Boiler tube wastage (corro-
sion); slagging; increased emissions of
particulates, carbon monoxide, polycy-
cllc organic matter, and other hydro-
carbons; boiler efficiency losses;
carbon loss in the ash; low steam tem-
peratures; and possible operating haz-
ards (including boiler explosions). In
EPA's judgment only boiler tube wast-
age could be a potential problem at
NO, emission levels necessary to meet
a standard of 210 ng/J.
Tube wastage is the deterioration of
boiler tube surfaces due to the corro-
sive effects of ash in the presence of a
reducing atmosphere. A reducing
atomsphere often results from oper-
ation of a boiler under conditions re-
quired to minimize NO, emissions. The
severity of tube wastage is believed to
vary with several factors, but especial-
ly with the quality of the coal burned.
For example, high sulfur Eastern coal
generally causes more of a tube wast-
age problem than low sulfur Western
coal. Serious tube wastage can shorten
the life of a boiler and result in expen-
sive repairs.
Because of the potential problem
from tube wastage, EPA does not be-
lieve that an emission limit below the
proposed level of 260 ng/J heat input
for Eastern bituminous coals would be
reasonable even though emission data
alone would tend to support a lower
limit. For low rank Western coals,
however, there is a much smaller tube
wastage potential at low NO, levels,
and a lower emission limit is justified.
Hence, EPA is proposing an emission
limit of 210 ng/J heat imput for units
burning low rank Western coals. These
coals are classified in the proposed
standards as subbituminous, according
to ASTM methods. EPA believes that
the proposed distinction made be-
tween low rank Western (subbitumin-
ous) coal and other coals represents
the best method for distinguishing be-
tween coals with low and high tube
wastage potentials.
Although most new utility power
plants will fire pulverized coal, other
fuels may also be burned. Emission
limits for these fuels are also pro-
posed.
The proposed NO, emission limits
for units which burn liquid and gas-
eous fuels are at the same levels as the
emission limits originally promulgated
in 1971 under subpart D for large
steam generators which burn oil and
gas. EPA did not conduct a detailed
study of combustion modification or
NO, flue gas treatment for oil- or gas-
fired boilers because few, if any, oil- or
gas-fired electric utility power plants
are expected to be built in the future.
Several studies have been conducted
which indicate that emissions from
the combustion of liquid and gaseous
fuels which are derived from coal,
such as solvent refined coal and low
Btu synthetic gas, may exceed the pro-
posed emission limits for liquid fuels
(130 ng/J) and gaseous fuels (86 ng/J).
The reason is because fuels derived
from coal will have fuel bound nitro-
gen contents which approach the
levels found in coal rather than in nat-
ural gas and oil. Based on limited
emission data from pilot-scale facilities
and on the known emission character-
istics of coal, EPA believes that an
achievable emission limit for solid,
liquid,.of gaseous fuels derived from
coal would be 210 ng/J (0.60 Ib/million
Btu). Tube wastage of other boiler
problems are not expected -to occur
from boiler operation at levels as low
as 210 ng/J when firing these fuels be-
cause of their low sulfur and ash con-
tents.
Very little is known about the emis-
sion characteristics of shale oil. How-
ever, since shale oil typically has a
higher fuel-bound nitrogen content
than fuel oil, it may be impossible for
a well-controlled unit burning shale oil
to achieve the proposed 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, EPA pro-
poses to limit NO, emissions from
units burning shale oil to 210 ng/J,
the same limit proposed for subbitu-
minous coal. There is no evidence that
tube wastage or other boiler problems
would result from operation of a boiler
at 210 ng/J when shale oil is burned.
The combustion of coal refuse was
exempted from the subpart D stand-
ards because the only furnace design
believed capable of burning coal
refuse, the slag tap furnace, inherent-
ly produces NO, emissions in excess of
the NO. standard. Since no new infer- •
mation has become available, EPA
would continue the coal refuse exemp-
tion under the proposed standards.
The proposed emission limits for lig-
nite combustion were developed earli-
er as amendments to the original
standards under subpart D. Since no
new information on NO, emission
rates resulting from lignite combus-
tion in electric utility power plants has
become available, the lignite limits
have been incorporated into these pro-
posed standards without revision.
While EPA believes that the pro-
posed emission limitations for bitumi-
nous and subbituminous coals can be
achieved without adverse effects,
UARQ recommends that the present
NO, emission limitation of 300 ng/J
(0.7 Ib/million Btu) be retained. In so
doing, they argue that the potential
adverse side effects that may result
from operating a boiler under condi-
tions required to meet the proposed
standards have not been adequately
studied over the long term. They also
expressed concern that the proposed
standards could have an anticompeti-
tive effect, since they believe there
may be only one boiler vendor who
could meet the proposed standards on
a continuous basis. Finally, they ques-
tion whether there Is sufficient con-
tinuous monitoring experience to war-
rant basing compliance on continuous
monitoring results.
STUDIES
The background information includ-
ing environmental and economic as-
sessments for the proposed standards
is divided into 4 documents, each with
a title and a document number as fol-
lows:
"Electric Utility Steam Generating Units:
Background Information for Proposed NO,
Emission Standards," EPA 4BO/2-78-008&;
"Electric Utility Steam Generating Units:
Background Information for proposed Par-
ticulate Matter Emission Standards," EPA
450/2-78-006*;
"Electric Utility Steam Generating Units:
Background Information for Proposed SO,
Emission Standards," EPA 4SO/2-78-007a;
and
"Electric Utility Steam Generating Units:
Background Information for Proposed SO.
FEDERAL REGISTER, VOt 43, NO. 187—TUESDAY, SEPTEMBER 19, 1978
111-85
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PROPOSED RULES
Emission Standards—Supplement," EPA
450/2-78-007a-l.
Much of the supporting information
within the background Information
documents was obtained from consul-
tant studies sponsored by EPA. Re-
ports covering these studies are includ-
ed in the docket at EPA headquarters
and are available for inspection during
normal office hours at each EPA re-
gional office. The titles of the consul-
tant studies are as follows:
1. "Flue Gas Desulfurlzation Systems:
Design and Operating Parameters, SO, Re-
moval Capabilities, Coal Properties and
Reheat."
2. "Flue Gas Desulfurlzation System Ca-
pabilities for Coal-Fired Steam Generators."
3. "Boiler Design and Operating Variables
Affecting Uncontrolled Sulfur Emissions
from Pulverized Coal-Fired Steam Gener-
ators."
4. "Effects of Alternative New Source Per-
formance Standards on Flue Gas Desulfurl-
/.atlon System Supply and Demand."
5. "Evaluation of Physical Coal Cleaning
as an SO. Emission Control Technique."
6. "The Impact of Modification/Recon-
struction of Steam Generators on SO, Emis-
sions."
7. "The Energy Requirements for Control-
ling SO, Emissions from Coal-Fired Steam/
Electric Generators."
8. "The Solid Waste Impact of Controlling
SO, Emissions from Coal-Fired Steam-Elec-
tric Generators."
9. "Water Pollution Impact of Controlling
SO, Emissions from Coal-Fired Steam/Elec-
tric Generators."
10. "Particulate and Sulfur Dioxide Emis-
sion Control Costs for Large Coal-Fired
Boilers."
11. "Review of New Source Performance
Standards for SO, Emissions from Coal-
Fired Utility Boilers."
12. "The Effect of Flue Gas Desulfuriza-
tion Availability on Electric Utilities."
13. "Effects of Alternative New Source
Performance Standards for Coal-Fired Elec-
tric Utility Boilers on the Coal Markets and
Utility Capacity Expansion Plans."
14. "Flue Gas Desulfurization System
Manufacturers Survey."
15. "Assessment of Manufacturer Capacity
to Meet Requirements for Particulate Con-
trol in Utility and Industrial Boilers."
16. "Flue Gas Desulfurlzation Cost for
Large Coal-Fired Boilers, August 10, 1978."
17. "The Ability of Electric Utilities with
FGD to Meet Energy Demands."
In addition to the consultant studies,
EPA studies were performed. One
study involved the installation and op-
eration of continuous SO, monitors on
the inlet and outlet of commercial-
scale POD units. The purposes of the
study were to determine: (1) The sta-
tistical characteristics of coal-fired
boiler and FGD operation, (2) the vari-
ability of SO, inlet concentrations, (3)
the ability of PGD to "damp out" SO,
variability, and (4) SO, emissions as a
function of averaging period.
A second EPA study included a dif-
fusion modeling analysis to estimate
the maximum ground-level concentra-
tion of SO, that would occur around
small, medium, and large power plants
for emission rates with and without
flue gas reheat. The study also exam-
ined the estimated SO, concentrations
that would occur around multi-boiler
facilities. Surfaqe and upper-air mete-
orological data for eight different geo-
graphical areas were used in the study.
EPA has also supplemented the eco-
nomic, energy, and environmental
•impact assessment set forth in the
background information document for
the SO, standard (EPA 450/2-78-007a)
by conducting two additional analyses.
The first was initiated in February
1978, and results became available in
late April. The second, which was com-
pleted in August, used revised assump-
tions pertaining to utility growth
rates, oil prices, etc. The results of
these studies are presented in sections
2 and 3 of the "Electric Utility Steam
Generating Units: Background Infor-
mation for Proposed SO, Emission
Standards—Supplement," EPA 450/2-
78~007a-l.
EPA has also taken into considera-
tion studies prepared by other Gov-
ernmental Agencies. One study is
"The Demand for Western Coal and
its Sensitivity to Key Uncertainties,"
draft report, 2nd edition, June 1978.
which assessed the potential impact of
this proposal on coal demand. This
report was prepared by a consultant
for the Department of Interior and
the Department of Energy. In addition
the analysis of alternative standards
prepared by the Department of
Energy, and transmitted to EPA by
Mr. John F. O'Leary, Deputy Secre-
tary, on July 6 and August 11, 1978,
was also considered.
A task force of American experts in
scrubber technology visited Japan to
evaluate Japanese scrubber perform-
ance. The findings (Maxwell, Elder
and Morasky, "Sulfur Oxides Control
Technology in Japan," June 30, 1978)
were also considered by EPA.
PERFORMANCE TESTING
PARTICULATE STANDARDS
Compliance with the proposed par-
ticulate matter standards would be de-
termined by using EPA method 5 oper-
ated at a filter temperature up to
160°C (320°F). As an option, EPA
method 17 may be used for stack gas
temperature less than 160°C. EPA
method 3 would be used to determine
oxygen or carbon dioxide concentra-
tions. These concentration measure-
ments would then be used to compute
Particulate emissions in units of the
standard as specified in proposed EPA
method 19.
Compliance with opacity standards
could be determined at any time by
visual observations using EPA method
9. Except during startups, shutdowns,
and malfunctions, all data from visual
observations would be ued for deter-
mining compliance with the proposed
qpacity standard.
A continuous monitoring system for
opacity would be required in the stack
except when firing only gaseous fuels.
The opacity data from the continuous
monitor would not be used to deter-
mine compliance with the opacity
standard. It would be used to assist in
assuring the particulate matter con-
trol system is properly operated and
maintained.
SO, AND NO, STANDARDS
Performance tests. Compliance with
the proposed SO, and NO, standards
would be determined using the data
obtained from the required continuous
monitoring systems. If an FGD system
were used for SO« control, continuous
SO, emission monitors would be re-
quired both upstream and downstream
of the FGD system and used to deter-
mine compliance with the proposed 85
percent SO, reduction. As an option.
compliance with the proposed SO
standards could be determined usint/
both an "as fired" fuel sampler to de
termine the sulfur content and heat-
ing value of the fuel fired to the
boiler, and a continuous SO, emission
monitor after the FGD system to
measure SO, emissions discharged into
the atmosphere. In addition to credit-
ing the SO, removed by the FGD
system, this option would provide
credit for sulfur removed by coal pul-
verizers and by the bottom ash and fly
ash. The SO, percent reduction re-
quirement and emission limitation
would both be based on emission levels
averaged over a 24-hour (daily) period.
If fuel is treated prior to combustion
to reduce SO, emissions, a sulfur re-
moval credit would also be allowed.
Procedures for determining sulfur re-
moval credits are proposed under
§ 60.48a with EPA method 19.
Performance testing to determine
compliance with the NO, emission lim-
itation (ng/J) would be determined on
a continuous basis through the use of
a continuous NO, emission monitor.
NO, emission data would be averaged
over a 24-hour (daily) period. Perform-
ance testing to determine compliance
with the percent reduction require-
ments for NO, would not be required.
An affected facility would be assumed
to be in compliance with the NO, re-
duction requirements provided the fa-
cility is in compliance with the appli-
cable NO, emission limitation.
When the NO, or SO, continuous
monitoring system fails to operate
properly, the source owner or operator
would obtain emission data by:
1. Operation of a second monitoring
system, or
2. Conducting manual tests using
EPA reference methods during the
period the continuous monitoring
system is inoperative.
FEDERAL REGISTER, VOl 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-86
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PROPOSED RULES
42173
Operation of a second monitoring
system would mean that the source
owner would have a second system in
operation at all times. Conducting the
manual tests would mean that the
source owner would have trained man-
power available on an immediate basis
to collect samples while the continu-
ous monitoring system is inoperative.
Manual test runs would be required on
an hourly basis.
Since compliance with the proposed
SO, and NO, standards would be de-
termined by continuous monitors,
EPA is currently developing additional
quality assurance procedures. These
procedures would not change the pres-
ent performance specifications for
continuous monitoring systems, but
would provide additional periodic field
tests to assure the accuracy of the
monitoring data. Appendix E under 40
CFR Part 60 is being reserved for
these additional quality assurance pro-
cedures. Electric utility powerplants
that would be subject to the proposed
standard would be subject to the qual-
ity assurance procedures under appen-
dix E when completed. This should
not pose a problem since new sources
affected by this proposed action are
not expected to begin operation until
about 1984.
Fuel pretreatment. Pretreatment of
a fuel to remove sulfur or Increase
heat content would be credited toward
the SO, percent reduction require-
ment. For example, by pretreatment
of a 2.3 percent sulfur fuel (equivalent
to 1,000 ng/J) to 1.7 percent sulfur
(750 ng/J; 25 percent sulfur removal),
the POD system SO. control require-
ment would be reduced from 85 per-
cent to 80 percent (750 ng/J reduced
to 150 ng/J). An 85 percent emission
reduction (1,000 ng/J to 150 ng/J)
would be necessary for an FOD system
if the fuel were fired untreated.
Fuel pretreatment credits would be
given for removal of sulfur from fuel,
including the resulting Increase in fuel
heat content. Examples of the type of
equipment or processes for which
credit would be given are:
1. Physical coal cleaning.
2. Solvent refining of coal.
3. Liquidation of coal.
4. Gasification of coal.
Rotary breakers or coarse screens
used to separate rock and other mate-
rial from raw coal prior to processing
or shipment are considered an integral
part of the coal mining process and
would not be considered as fuel pre-
treatment (see section 4.5.2.2 of EPA
450/2-78-007a-l).
The proposed standard would not re-
quire fuel to be pretreated before
firing but would allow credit for pre-
treatment if used. The amount of
sulfur removed by a fuel pretreatment
process would be determined following
procedures in EPA method 19 (appen-
dix A). The owner or operator of the
electric utility who would use the
credit would be responsible for insur-
ing that the EPA method 19 proce-
dures are followed in determining SO,
removal credit for pretreatment equip-
ment.
MISCELLANEOUS
As prescribed by section 111, estab-
lishment of standards of performance
for electric utility steam generating
units was preceded by the Administra-
tor's determination that these sources
contribute significantly to air pollu-
tion which causes or contributes to the
endangerment of public health or wel-
fare. In accordance with section 117 of
the Act, publication of this proposal
was preceded by consultation with ap-
propriate advisory committees, Inde-
pendent experts, and Federal depart-
ments and agencies. The Administra-
tor will welcome comments on all as-
pects of the proposed regulation, in-
cluding economic and technological
issues, and on the proposed test meth-
ods.
Under EPA's "new" sunset policy for
reporting requirements In regulations,
the reporting requirements in this reg-
ulation will automatically expire 5
years from the date of promulgation
unless EPA takes affirmative action to
extend them. To accomplish this, a
provision automatically terminating
the reporting requirements at that
time will be included in the text of the-
final regulations.
It should be noted that standards of
performance for new fossil fuel fired
stationary sources established under
section 111 of the Clean Air Act re-
flect:
• • • 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 Ad-
ministrator determines has been adequately
demonstrated. [Section UKaXl))
Although there may be emission
control technology available that can
reduce emissions below those levels re-
quired to comply with standards of
performance, this technology might
not be selected as the basis of stand-
ards of performance due to costs asso-
ciated with Its use. Accordingly, stand-
ards of performance should not be
viewed as the ultimate in achievable
emission control. In fact, the Act re-
quires (or has potential for requiring)
the imposition of a more stringent
emission standard in several situa-
tions.
For example, applicable costs do not
play as prominent a role in determin-
ing the "lowest achievable emission
rate" for new or modified sources lo-
cated in nonattalnment areas, i.e.,
those areas where statutorily-mandat-
ed 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 re-
flects 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 limita-
tion which is contained in the Implementa-
tion plan of any State for such class or cate-
gory of source, unless the owner or operato.r
of the proposed source demonstrates that
such limitations are not achievable, or
(B) The most stringent emission limita-
tion 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 per-
formance standard (section 171(3)).
A similar situation may arise under
the prevention of significant deteriora-
tion of air quality provisions of the
Act (part C). These provisions require
that certain sources (referred to in sec-
tion 189(1)) employ "best available
control technology" (as defined in sec-
tion 1«9(S» for all pollutants regulat-
ed under the Act. Best available con-
trol technology (BACT) must be deter-
mined 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 pol-
lutants which will exceed the emis-
sions allowed by any applicable stand-
ard 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 pro-
vide for the attainment and mainte-
nance of national Ambient Air Quality
Standards designed to protect public
health and welfare. For this purpose,
SIPs must in some cases require great-
er emission reductions than those re-
quired 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. According-
ly, 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 integra-
tion with other programs, the exis-
FIOERAL REGISTER, VOl 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-87
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42174
PROPOSED RULES
tence of alternative methods, enfor-
ceability, and improvements in emis-
sion control technology.
Executive Order 12044, dated March
24, 1978, whose objective is to improve
Government regulations, requires ex-
ecutive branch agencies to prepare
regulatory analyses for regulations
that may have major economic conse-
quences. The proosed standards meet
the criteria for preparation of a regu-
fatory analysis as outlined in the Ex-
ecutive order. Therefore, a regulatory
analysis has been prepared as re-
quired. The analysis is contained in
the background information docu-
ments for the proposed standards. The
regulatory analysis is not being pub-
lished as a separate document because
the work was begun before the Presi-
dent's Executive order was published.
However, in order to present a better
understanding of the analyses con-
tained in the background information
documents, a summary of the analyses
is included in the preamble. The sum-
mary discusses in detail the alterna-
tives considered.
Section 317 of the Clean Air Act re-
quires the Administrator to prepare an
economic impact assessment for revi-
sions determined by the Administrator
to be substantial. The Administrator
has determined that the proposed
amendments are substantial and has
prepared an economic impact assess-
ment and included the required infor-
mation in thebackground information
documents.
Dated: September 11, 1978.
DOUGLAS M. COSTLE,
Administrator.
It is proposed that 40 CFR Part 60
be amended by revising the heading
and § 60.40 of Subpart D, by adding a
new Subpart Da, by adding a new ref-
erence method to Appendix A, and by
reserving Appendix E as follows:
1. The heading for Subpart D is re-
vised to read as follows:
Subpart D—Standard! of Performance for
Fossil-Fuel-Fired Steam Generators Con-
structed After August 17, 1971
2. Section 60.40 is amended by
adding paragraph (a)(3) as follows:
§60.40 Applicability and designation of
affected facility.
(a)* * *
(3) Is not subject to the provisions of
Subpart Da,
(Sec. Ill, 301(a> of the Clean Air Act as
amended (42 U.S.C. 7411, 7601
-------
PROPOSED RULES
42175
ment which is owned by the utility
company and which is being operated
or is capable of being operated (includ-
ing fossil-fuel-fired steam generators,
internal combustion engines, gas tur-
bines, and nuclear power plants). The
electrical generating capacity of elec-
tric generating equipment under mul-
tiple ownership is prorated based on
ownership.
(3), (a)(5) or (b) of this
section;
(5) 340 ng/J heat input (0.80 Ib/mil-
llon Btu) derived from the combustion
in a slag tap furnace of any fuel con-
taining more than 25 percent, by
weight, lignite which has been mined
in North Dakota, South Dakota, or
Montana;
(6) 75 percent of the potential com-
bustion concentration (25 percent re-
KDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1971
111-89
-------
42176
PROPOSED RULES
duction) when combusting gaseous
fuel;
(7) 70 percent of the potential com-
bustion concentration (30 percent re-
duction) when combusting liquid fuel;
and
(8) 35 percent of the potential com-
bustion concentration (65 percent re-
duction) when combusting solid fuel.
(b) Cotnbuetten of *• fuel .containing
more than 25 percent, by weight, coal
refuse is exempt from both the provi-
sions of §60.47a(a)(3) and paragraph
(a) of this section.
(c) The requirements under para-
graph (a) of this section do not apply
when an affected facility is operated
under an NO, commercial demonstra-
tion permit issued by the Administra-
tor in accordance with the provisions
of§60.45a.
+!/<210>+z<26<»/100
where:
ASmi I* the applicable standard for nitrogen
oxides when multiple fuels are combust-
ed simultaneously (ng/J heat input);
w is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 86 ng/J heat input standard;
X is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 130 ng/J heat input standard;
y is the percentage of total heat input de-
rived from the combustion of fuels sub-
ject to the 210 ng/J heat input standard;
and
a is the percentage of total heat Input de-
rived from the combustion of fuels sub-
ject to the 260 ng/J heat input standard.
§ 60.4Sa Commercial demonstration
permit.
(a) An owner or operator of an af-
fected facility proposing to demon-
strate an emerging technology may
apply to the Administrator for a com-
mercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance
with paragraph (d) of this section.
Commercial demonstration permits
may only be issued by the Administra-
tor, and this authority will not be dele-
gated.
(b) An owner or operator who is
issued an 8Oi commercial demonstra-
tion permit by the Administrator is
not subject to the SO. control require-
ments under §60.43a(a)(3) but must,
as a minimum, reduce SO. emissions to
20 percent of the potential combustion
concentration (80 percent SO. control
on a 24-hr basis)
(c) An owner or operator who is
issued an NO, commercial demonstra-
tion permit by the Administrator is
not subject to the NO, control require-
ments under f 60.44a but must, as a
minimum, reduce NO, emissions to 300
ng/J heat input (0.70 Ib/million Btu;
24-hour average).
(d) Commercial demonstration per-
mits may not exceed the following
equivalent MW electrical generation
capacity for any one technology cate-
gory, and the total equivalent MW
electrical generation capacity for all
commerical demonstration plants may
not exceed 15,000 MW.
Technology
Pollut- Equivalent
ant MW electrical
capacity
Solvent refined coal (I) SO, 6,000-10,000
Pluidlzed bed combustion SO, 400-3.000
(atmospheric).
Fluldlzed bed combustion SO, 400-1.200
(pressurized).
Coal llquifaotlon NO. 780-10,000
Total allowable lor all 15,000
technologies.
§ 60.46a Compliance provisions.
(a) Compliance with the particulate
matter emission limitation under
§60.42(aXl) constitutes compliance
with the percent reduction require-
ments for particulate matter under
§60.42a(a) (2) and (3).
(b) Compliance with the nitrogen
oxides emission limitation under
§60.44a(a)(l), (2), (3), (4), and (5) as
applicable, constitutes compliance
with the percent reduction require-
ments under §60.44a(a)(6), (7), and (8).
(c) Following the initial performance
tests for sulfur dioxide and nitrogen
oxides required under §60.8, each 24-
hour period constitutes a separate per-
formance test. The nitrogen oxides
emission standards under §60.44a
apply at all time except during periods
of startup, shutdown, or malfunction.
The sulfur dioxide emission standards
under §60.43a apply at all times except
during periods oil startup, shutdown,
or when both emergency conditions
exist and the procedures under para-
graph (d) of this section are imple-
mented.
(d) During emergency conditions an
affected facility with a malfunctioning
flue gas desulfurization system may
continue operation if sulfur dioxide
emissions are minimized by:
•> (1) Continued operation of all oper-
able flue gas desulfurization system
modules,
(2) Only by-passing flue gases
around totally inoperable flue gas de-
sulfurization system modules, and
(3) Designing, constructing, and op-
erating a spare flue gas desulfurization
system module in affected facilities
larger than 365 MW heat input (1,250
million Btu/hrX
f60.47a Emission monitoring.
(a) The owner or operator of an af-
fected facility shall Install, calibrate,
maintain, and operate a continuous
monitoring system for measuring the
opacity of emissions discharged to the
atmosphere, except where gaseous
fuel is the only fuel combusted. If
opacity interference exists In the stack
(for example, from the use of an POO
system), the opacity is monitored up-
stream of the interference (at the inlet
to the POD system). If opacity inter-
ference is experienced at all locations
(both at the inlet and outlet of the
sulfur dioxide control system), alter-
nate parameters indicative of the par-
ticulate matter control system's per-
formance are monitored (subject to
the approval of the Administrator).
(b) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system for measuring
sulfur dioxide emissions, except where
natural gas is the only fuel combusted,
as follows: '
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet
of the sulfur dioxide control device.
(2) For a facility which qualifies
under the provisions of §60.43a(c),
sulfur dioxide emissions are only mon-
itored as discharged to the atmo-
sphere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeting the requirements of method
19 (Appendix A) may be used to deter-
mine potential sulfur dioxide emis-
sions in place of a continuous sulfur
dioxide emission monitor at the inlet
to the sulfur dioxide control device as
required under paragraph (bXl) of
this section.
(4) If a facility which complies with
§60.43a(a) solely through the provi-
sions under §60.43a(d), then sulfur
dioxide emissions are only monitored
at the outlet of the sulfur dioxide
contol device.
(c) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system for measuring ni-
trogen oxides emissions discharged to
the atmosphere.
(d) The owner or operator of an af-
fected facility shall install, calibrate,
maintain, and operate an oxygen or
carbon dioxide monitoring system to
measure the oxygen or carbon dioxide
content of the flue gas at each loca-
tion where sulfur dioxide or nitrogen
oxides emissions are monitored.
(e) The owner pr operator of an af-
fected facility shall operate continu-
ous emission monitoring systems
during all periods the affected facility
is operated except for the following:
U) A maximum of sixty (60) minutes
each day for dally zero and calibration
checks or adjustments. ;
PCOERAL MWSTER, VOl 49, NO. 182-TUESDAY, SIFTfMMR W, 1978
111-90
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(2) A maximum of eight (8) hours
per month for routine maintenance.
(f) During periods of operation of
the affected facility when continuous
monitoring systems (and spare moni-
toring systems If used) are not oper-
able, the owner or operator of the af-
fected facility shall conduct perform-
ance tests consisting of manual testing
each hour until the continuous moni-
tor system is returned to service. Each
hourly test Is performed as follows:
(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 sam-
pling time shall be 20 minutes and the
minimum sampling volume 0.02 dsem
(0.71 dscf) for each sample. The arith-
metic mean of two samples taken at
approximately 30-minute intervals
constitutes one run. The arithmetic
mean of the runs obtained during a 24-
hour period is reported as the average
for that period. For determination of
FOD removal efficiency, inlet and
outlet sampling is conducted simulta-
neously.
(3) For method 7, each run consists
of at least four grab samples taken at
approximately 15-mlnute intervals.
The arithmetic mean of the four sam-
ples constitutes the 1-hour run. The
arithmetic mean of the runs obtained
during a 24-hour period is reported as
the average for that period.
(4) For method 3, the oxygen or
carbon dioxide sample is obtained si-
multaneously at the same location in
the duct as the samples collected using
methods 6 and 7. For method 7, the
oxygen sample is obtained using the
grap sampling and analysis procedures
of method 3.
(5) For each run using method 19 in
appendix A to this part, the emissions
expressed in ng/J (Ib/million Btu) are
determined. The arithmetic mean of
the runs performed during a 24-hour
period is reported as the average for
that period.
(g) The following procedures are
used for monitoring system perform-
ance evaluations under §60.13(c) and
calibration checks under §60.13(d):
(1) Reference method 6 or 7, as ap-
plicable, is used for conducting per-
formance evaluations of sulfur dioxide
and nitrogen oxides continuous moni-
toring systems.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under per-
formance 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 moni-
toring system measuring nitrogen
oxides is determined as follows:
PROPOSED RULES
[Parts per million!
FOHSI! fuel
Span value for
nitrogen oxides
Oas 500
Liquid 600
Solid 1,000
Combinations 600(i+»)4 1.0002
where:
i-the fraction of total heat input derived
from gaseous fossil fuel,
j/~the fraction total heat input derived
from liquid fossil fuel, and
3 = 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 monitor-
ing system at the inlet to the sulfur-
dioxide-control device is 200 percent of
the potential emissions of the fuel
fired, and at the outlet of the sulfur-
dioxide-control device is 50 percent of
potential emissions. When the percent
fuel sulfur content changes by 0.5 (24-
hour average) or more, the continuous
monitoring system shall be respanned.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
§60.48a Compliance determination proce-
dures and methods.
(a) The following procedures and
reference methods are used to deter-
mine compliance with the standards
for particulate matter under § 60.42a:
(1) Method 3 is used for gas analysis
when applying method 6 or method
17.
(2) Method 5 is used for determining
particulate matter emissions and asso-
ciated moisture content. Method 17
may be used for stack gas tempera-
tures less than 160° C (320° F).
(3) For method 5 or method 17,
method 1 is used to select the sam-
pling 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 ne-
cessitated 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
(320° F).
(5) For determination of particulate
emissions, the oxygen or carbon-diox-
ide sample is obtained simultaneously
with each run of method 5 or method
17 by traversing the duct at the same
sampling location. Method 1 is used
for selection of the number of traverse
42177
points except that no more than 12
sample points are required.
(6) For each run using method 5 or
method 17, the emission rate ex-
pressed in ng/J is determined using
the oxygen or carbon-dioxide results
and particulate results obtained under
this section, and using the dry F-
factor and dry basis emission rate cal-
culation procedure contained In
method 19 (appendix A).
(b) The following procedures and
methods are used to determine compli-"
ance with the sulfur dioxide standard
under § 60.43a:
(1) Determine the percent of poten-(
tlal combustion concentration (percent'
PCC) emitted to the atmosphere as
follows:
(i) Determine the percent sulfur re-
duction achieved by any fuel pretreat-
ment using the procedures in method
19 (appendix A; optional procedure).
Calculate the average percent reduc-
tion on a quarterly basis using fuel
analysis data.
(ii) Determine the percent sulfur
dioxide reduction achieved by any
sulfur dioxide control system using
continuous sulfur dioxide emission
monitors or an "as fired" fuel monitor
(optional procedure) in conjunction
with a continuous sulfur-dioxide-emis-
sion monitor and following the proce-
dures in method 19 (appendix A). If 24
hours of data are not available (such
as during startup or shutdown), all
available valid data are averaged for
each 24-hour period.
(Hi) Determine atmospheric sulfur
dioxide emissions as a percent of the
potential combustion concentration
(percent PCC) as follows: Use the re-
sults obtained in paragraphs (b)(l) (1)
(optional) and (ii) of this section and
the procedures in method 19 (appen-
dix A) to calculate the overall percent
reduction (percent R0) of the potential
sulfur dioxide emissions. Results are
calculated for each 24-hour period
using the quarterly average percent
sulfur reduction determined for fuel
pretreatment from the previous quar-
ter and the sulfur dioxide reduction
for each 24-hour period determined
for each day in the current quarter.
Calculate the percent of potential
combustion concentration emitted to
the atmosphere using the following
equation:
Percent PCC=100-percent 60
(2) Determine sulfur dioxide and ni-
trogen oxides emission rates using
method 19 (appendix A). Emission
rates are calculated for each 24-hour
period and shall be considered to con-
stitute a three-run performance test.
If 24 hours of data are not available in
a 24-hour period (such as during star-
tup or shutdown), all available valid
data for the period are averaged.
(c) The procedures and methods out-
lined in method 19 (appendix A) are
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-91
-------
42178
PROPOSED RULES
used in conjunction with the 24-hour
nitrogen-oxides emission data collect-
ed under § 60.47a to determine compli-
ance with the applicable nitrogen
oxides standard under § 60.44a.
(d) Electric utility combined cycle
gas turbines are performance tested
for particulate matter, sulfur dioxide,
and nitrogen oxides using the proce-
dures of method 19 (appendix A). The
sulfur dioxide and nitrogen oxides
emission rates from the gas turbine
used in method 19 (appendix A) calcu-
lations are determined when the gas
turbine is performance tested under
subpart OG. The potential uncon-
trolled particulate matter emission
rate from a gas turbine is defined as 17
ng/J (0.04 Ib/million Btu) heat input.
(Sec. 114, Clean Air Act as amended (42
U.8.C. 7414).)
§ 60.49a Reporting requirements.
(a) For sulfur dioxide, nitrogen
oxides, and particulate matter emis-
sions, the performance test data from
the initial performance test and from
the performance evaluation of con-
tinuous monitors are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides, all emission data (24-hour daily
average) collected subsequent to the
initial performance test are submitted
to the Administrator. The required
data include the following information
for each 24-hour period:
(1) Calendar date;
(2) Sulfur dioxide and nitrogen,
oxides emission rates (ng/J or Ib/mil-
iion Btu, 24-hour average);
(3) Percent reduction of the poten-
tial combustion concentration of
sulfur dioxide (24-hour average) (not
required for nitrogen oxides);
(4) Number of hours of valid emis-
sion data collected during each 24-
hour daily period;
(5) Identification of periods when
emissions exceed the applicable stand-
ards under either § 60.43a or § 60.44a;
(6) Identification of periods of star-
tup or shutdown that resulted in emis-
sions exceeding the applicable stand-
ards under either § 60.43a or § 60.44a;
(7) Identification of periods when
control system malfunction resulted in
emissions in excess of applicable nitro-
gen oxides standards under § 60.44a;
(8) Identification of "F" factor used
for calculations, and type of fuel com-
busted; and
(9) Identification of periods when
any continuous monitoring systems
are not operating and identification of
pollutant to be monitored.
(c) If any standards under § 60.43a
are exceeded during emergency condi-
tions because of control system mal-
function, the owner or operator of the
affected facility shall submit a signed
statement:
(1) Indicating if conditions of
§§60.*ia(n) and 60.46a(d) were met
during each period; and
(2) Listing the:
(i) Time periods the emergency con-
dition existed;
(ii) Electrical output and demand on
the owner's or operator's electric util-
ity system and the affected facility;
(iii) Amount of power purchased
from the interconnected reliability
council 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 modification.
(d) If fuel pretreatment credit
toward the sulfur dioxide emission
standard under § 60.43a is claimed, the
owner or operator of the affected fa-
cility shall submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the cal-
endar quarter, and whether the credit
was determined in accordance with the
provisions of §60.48a and method 19
(appendix A); and
(2) Listing the quantity heat content
and date each pretreated fuel ship-
ment was received during the previous
quarter, the name and location of the
fuel pretreament facility, and the total
quantity and total heat content of'all
fuels received at the affected facility
during the previous quarter.
(e) 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
standard under §60.42a(b). Opacity
levels in excess of the applicable opac-
ity standard and the date of such ex-
cesses are submitted to the Adminis-
trator each calendar quarter.
(f) The owner or operator of an af-
fected facility shall submit the written
reports required under this section
and subpart A to the Administrator
for every calendar quarter. All quar-
terly 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-DIOX-
IDE REMOVAL EFFICIENCY AND PARTICULATE.
SULFUR DIOXIDE AND NITROGEN OXIDES EMIS-
SION RATES FftOM ELECTRIC UTILITY STEAM
GENERATORS
1. Principle and applicability.
1.1 Principle.
1.1.1 Fuel samples from before and after
fuel pretrc (\Unent systems are collected and
analyzed for sulfur and heat content, and
the percent sulfur dioxide (ng/Joule. Ib/mil-
lion 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 de-
vices are used to calculate sulfur-dioxide re-
moval efficiencies. (Minimum requirement.)
As an alternative to sulfur-dioxide monitor'
ing upstream of sulfur-dioxide-control de-
vices, fuel sample* may be collected in an as-
fired condition and analyzed for sulfur and
beat content. (Optional procedure.)
1.1.3 An overall sulfur dioxide emission
reduction efficency Is calculated, from the
efficiency of fuel pretreatment systems and
the efficiency of sulfur dioxide control de-
vices.
1.1.4 Particulate, sulfur dioxide, nitrogen
oxides, and oxygen or carbon dioxide con-
centration 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 applica-
ble for determining sulfur removal efficien-
cies of fuel pretreatment and sulfur-dioxide-
control devices and the overall reduction of
potential sulfur dioxide emissions from elec-
tric utility steam generators. This method is
also applicable for the determination of par-
ticulate, sulfur dioxide, and nitrogen oxides
emission rates.
2. Determination of sulfur-dioxide remov-
al efficiency of fuel • pretreatment syttems
(optional).
2.1 Solid fossil fuel.
2.1.1 Sample increment collection. Use.
ASTM D 2234,* type I, conditions A. B, or C,
and systematic spacing. Determine the
number and weight of increments required
per gross sample representing each coal lot
according to table 2 or paragraph 7.1.S.2 of
ASTM D 2234.* Collect one gross sample for
each raw coal lot and one gram 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 de-
fined as the weight of product coal pro-
duced 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 processed 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 powerplant may be
used if representative sampling can be con-
ducted for the raw coal and product coal.
NOTE.—Alternate definitions of fuel lot
sizes may be specified subject to prior ap-
proval of the Administrator.
2.1.3 Gross sample analysis. Determine
the percent sulfur content (percent S) and
gross calorific value (OCV) 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* or D 2015* for gross calorific value; de-
termination.
2.2 Liquid fossil fuel.
•Use the most recent revision or designa-
tion of the ASTM procedure specified.
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-92
-------
PROPOSED RULES
42179
2.2.1 Sample collection. Use ASTM D
270* following the practices outlines for con-
tinuous sampling for each gross sample rep-
resenting 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 (shipload, bargeload, etc.) is de-
fined 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 definitions of fuel lot
sizes may be specified subject to prior ap-
proval of the Administrator.
2.2.3 Sample analysis. Determine the per-
cent sulfur content (percent S) and gross
calorific value (QVC). Use ASTM D 240* for
the sample analysis. This value can be as-
sumed to be on a dry basis.
2.3 Calculation of sulfur-dioxide removal
efficency due to fuel pretreatment. Calcu-
late the percent sulfur dioxide reduction
due to fuel pretreatment using the follow-
ing equation:
XR, • 100
*s°/6cv°i
I5775CVT
Where:
%R,=Sulfur dioxide removal efficiency due
pretreatment: percent.
%S0" Sulfur content of the product fuel lot
on a dry basis: weight percent.
%S,=Sulfur dioxide content of the inlet fuel
lot on a dry basts; weight percent.
GCV.=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 follow-
ing equation to calculate the sulfur content
per unit of heat content of the total fuel lot,
%S/GCV:
XS/GCV
E y (XS./GCVJ
k-1 * k K
Where:
Y»=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 effi-
ciency of the sulfur dioxide control device.
3.1 Sampling. Determine Sd and CO, or
Ot oxygen concentrations at the inlet and
outlet of the sulfur dioxide control system
according to methods specified In the appli-
cable subpart of the regulations.
(NOTE.—The downstream data are used to
calculate the SO, emission rate. See section
5.) The Inlet sulfur dioxide concentration
may be determined through fuel analysis
(optional, see section 3.3).
3.2 Calculation. Calculate the percent re-
moval efficiency using the following equa-
tions as applicable:
2.0(XS.)
x 10' for S.I. units.
X R
9(02)
100
so.
X R
'g(C02) » 100
(S02do x * C02dA
A55^ "TO
Where:
%R,(O,)=Sulfur dioxide removal efficiency
of the sulfur dioxide control device, Or-
based calculation; percent.
%R,(CO,)=Sulfur dioxide removal efficien-
cy of the sulfur dioxide control device,
COi-based calculation; percent.
SOH=SO, concentration, dry basis; ppmv.
%CO«=CO,concentration, dry basis; bolume
percent.
%OM=CO, concentration, dry basis; volume
percent.
i=Inlet.
o=Outlet.
NOTE.—For devices measuring concentra-
tion on a wet basis, appropriate equations
which account for moisture differences are
approved In principle. See the appropriate
paragraph In section 5.3. Methods for meas-
uring moisture content are subject to ap-
proval of the Administrator.
3.3 As-fired fuel analysis (optional proce-
dure). If the owner or operator of an elec-
tric utility steam generator chooses to deter-
mine the sulfur dioxide Input 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 col-
lected In accordance with the applicable
paragraph In section 2. The sampling can be
conducted upstream of any fuel processing,
e.g., plant coal pulverization. For the pur-
poses of this section, fuel lot size Is defined
as the weight of fuel consumed on one day
(24 hours) and is directly related to the ex-
haust gas monitoring data at the outlet of
the sulfur dioxide control system.
3.3.1 Fuel analysis. Fuel samples must be
analyzed for suflur content and gross calo-
rific value. The ASTM procedures for deter-
mining sulfur content are defined In the ap-
plicable paragraphs of section 2.
3.3.2 Calculation of sulfur dioxide input
rate. The sulfur dioxide Input rate deter-
mined from fuel analysis Is calculated by:
2.0(XS,)
x 10*
for English units.
Where:
/,=Sulfur dioxide input rate from as-flr«d
fuel analysis, ng/J (lb/million Btu).
%S/=8ulfur 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 emis-
sion reduction using as-fired fuel analysis.
The sulfur dioxide emission reduction effi-
ciency Is calculated using the sulfur, input
rate from paragraph 3.3.2 and the sulfur
dioxide emission rate, Etoi, determined in
the applicable paragraph of Section 5.3. The
equation for sulfur dioxide emission reduc-
tion efficiency is:
XRg(f).100x (1.0-
Where:
%R,v>=Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
as-fired fuel analysis data; percent.
£MI=Sulfur dioxide emission rate from
sulfur dioxide control system; ng/J (lb/
million Btu).
7,=Sulfur dioxide input rate from as-fired
fuel analysis; ng/J (Ib/million Btu).
4. Calculation of overall reduction in po-
tential sulfur dioxide emission.
4.1 The overall percent sulfur dioxide re-
duction calculation uses the sulfur dioxide
concentration at the inlet to the sulfur diox-
ide control device as the base value. Any
sulfur reduction realized through fuel clean-
Ing is introduced Into the equation as an
average percent reduction, %Rf.
4.2 Calculate the overall percent sulfur
reduction as:
•UK,
IR
XR0.100[1.0- (1.0 -^) 0.0 -
Where:
%Ro= Overall sulfur dioxide reduction; per-
cent.
ulfur dioxide removal efficiency of
fuel pretreatment from Section 2; per-
cent. Refer to applicable subpart for
definition of applicable averaging
period.
ROHtAL MOUTH, VOL 43, NO. 182-TUESDAY, SEPTEMBER 19, 1978
111-93
-------
42180
PROPOSED RULES
%/Z,=Sulfur dioxide removal efficiency of
sulfur dioxide control device either O. or
COrbased calculation or calculated from
fuel analysis and emission data, from
Section 3; percent. Refer to applicable
subpart for definition of applicable averag-
ing period.
5. Calculation of particulate, sulfur diox-
ide, and nitrogen oxides emission rates.
5.1 Sampling. Use the outlet SO, and O.
or COi concentrations data obtained in sec-
tion 3.1. Determine the particulate, NO,,
and Ot or CO. concentrations according to
methods specified in an applicable subpart
of the regulations.
5.2 Determination of an F factor. Select
an average F factor (section 5.24) or calcu-
late an applicable F factor (section 5.2.2). If
combined fuels are fired, the selected or cal-
culated F factors are prorated using the pro-
cedures In section 6.2.3. F factors are ratios
of the gas volume released during combus-
tion of a fuel divided by the heat content of
the fuel. A dry F factor (Fa is the ratio of
the volume of dry flue gases generated to
the calorific value of the fuel combusted; a
wet F factor (F,,) is the ratio of the volume
of wet flue gases generated to the calorific
value of the fuel combusted; and the carbon
F factor is the ratio of the volume of
carbon dioxide generated to the calorific
value of the fuel combusted. When pollut-
ant and oxygen concentrations have been
determined In section 5.1, wet or dry. F fac-
tors are used. (F, factors and associated
emission calculation procedures are not ap-
plicable and may not be used after wet
scrubbers; Fc or Fa factors and associated
emission calculation procedures are used
after wet scrubbers.) When pollutant and
carbon dioxide concentrations have been de-
termined In section 5.1, Fc factors are used.
5.2.1 Average F factors. Table 1 shows
average Fa, P., and Pc factors (scm/J, act/
million Btu) determined for commonly used
fuels. For fuels not listed in table 1, the F
factors are calculated according to the pro-
cedures outlined in Section 5.2.2 of this sec-
tion.
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 proce-
dures 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.
For SI Units:
227.OUH) + 95.7UC) + 35.4(%S) X 8.6(%N) - 28.5(%0)
-
347.4UH)+95.7(%C)+35.4(%S)+8.6(XN)-28.$(!I!0)-H3.0(«H20)**
GCV.
20.0(%C)
~~§CV
For English Units:
F =, 106C3.64(%H)-H.53(XCH0.57(%$)+0.14(%N)-0.46(%0)]
rd GCV
** The %H20 term may be omitted If %H and XO Include the unavail-
able hydrogen and oxygen In the form of rLO.
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
HI-94
-------
TABLE 1. F FACTORS FOR VARIOUS FUELS
Fuel -Type
Coal
Anthracite9
Bituminous3
Lignite
01lb
Gas
Natural
Propane
Butane
Wood
Unnrl Rart
dson
J
2.72
2.64
2.66
2.48
2.35
2.35
2.35
2.49
? RQ
X
X
X
X
X
X
X
X
V
io-7
1C'7
io-7
ID'7
io-7
ID'7
io-7
io-7
in'*
dscf
IO6 Btu
(10140)
(9820)
(9900)
(9220)
(8740)
(8740)
(8740)
(9280)
IQKO.(\\
wsctn
J
2.84 x
2.87 x
3.22 x
2.78 x
2.86 x
2.75 x
2.80 x
io-7
io-7
ID'7
io-7
io-7
io-7
io-7
wscf
106 Btu
(10680)
(10680)
(12000)
(10360)
(10650)
(10240)
(10430)
,
son
J
0.486 x
0.486 x
0.515 x
0.384 x
0.279 x
0.322 x
0.338 x
0.494 x
n.AQQ x
io-7
io-7
ID'7
io-7
io-7
io-7
ID'7
io-7
in-7
scf
10*~Btu
(1810)
(1810)
(1920)
(1430)
(1040)
(1200)
(1260)
(1840)
nafitrt
PROPOSED RUL
m
a As classified according to ASTM D 388-66
Crude, residual, or distillate
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
00
-------
42182
PROPOSED RULES
106[S.S7(UII'!
l4(INW.46(V>lrtl.?HW,0)']
-- "~~
CONVERSION FACTORS FOR CONCENTRATION
10*1°. Ml !SCiJ
Where:
Fd, Pw, and Pc have the units of scm/J or
scf/million Btu; %H. %C, %3, %N, %O,
and %H,O are the concentrations by
weight (expressed in percent) of hydro-
• gen, carbon, sulfur, nitrogen, oxygen,
and water from an ultimate analysis of
the fuel; and OCV is the gross calorific
value of the fuel in kj/kg or Btu/lb and
consistent with the ultimate analysis.
J Follow ASTM D 2015* for solid fuels, D
240* for liquid fuels, and D 1826* for
gaseous fuels as applicable in determin-
ing OCV.
5.2.3 Combined fuel firing F factor. For
affected facilities firing combinations of
fossil fuels or fossil fuels and wood residue,
the Fa, F«, and Pc factors determined by Sec-
tions 5.2.1 or 5.2.2 of this section shall be
prorated in accordance with the applicable
formula as follows:
From—
To—
Multiply
by-
g/scm
mg/scm
Ib/scf
ppmCSO,)...
ppmCNO,)..
ppm...
ppm(NO,K.
ng/scm 10*
ng/scm 10*
ng/scm 1.802x10"
ng/scm 2.660x10"
ng/scm 1.912x10'
Ib/scf 1.660X10-'
Ib/scf 1.194X 10-'
5.3.1 Oxygen-based F factor proce-
dure.
5.3.1.1 Dry basis. When both per-
cent oxygen <%OZ<1) and the pollutant
concentration
or measured on a dry basis, the following
equation is applicable:
cwFd
20.9
•(1 - B'V L20.9 - W,
'2d
NOTE.—See section 5.3.1.2 on the usage of
B... When the pollutant concentration (G<)
is measured on a dry basis and the oxygen
concentration <%O«) is measured on a wet
basis, the following equation is applicable:
cdFd
20.9
FEDERAL REGISTER, VOL 43, NO. 182—TUESDAY, SEPTEMBER 19, 1978
111-96
-------
PROPOSED RULES
42183
5.3.2.2 Wet basis. When both the percent
carbon dioxide (%CO») and the pollutant
concentration (C»> are measured on a wet
basis, the following equation Is applicable:
E '
Ve
5.3.2 Carbon Dioxide-Based F Factor rate from the steam generator is calculated
Procedure. «»:
5.3.2.1 Dry Basis. When both the percent
carbon dioxide <%COM) and the pollutant
concentration (d) are measured in the flue
gas on a dry basis, the following equation is
applicable:
where
Ew.Pollutant emission rate from steam gen-
erator effluent, ng/J (Ib/mllllon Btu).
EC"Pollutant emission rate in combined
cycle effluent; ng/J (Ib/mllllon Btu).
£„=Pollutant emission rate from gas tur-
bine effluent; ng/J (Ib/mllllon Btu).
Xv=Fraction of total heat input from sup-
plemental fuel fired to the steam gener-
ator.
A:,,=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
supplemental fuel fired to the steam gener-
ator and the heat input to the steam gener-
ator 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 tempera-
ture 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 direct-firing 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 ex-
haust 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 concen-
trations is not necessary.
APPENDIX E—[RESERVED]
5. Appendix E is added to part 60
and reserved.
(Sec. Ill, 114, and 301(a), Clean Air Act as
amended (42 U.S.C. 7411. 7414, and 7601(a)).
[FR Doc. 78-26005 Filed 9-18-78; 8:45 am]
5.3.2.3 Dry/Wet basis. When the pollut-
ant concentration (C.) is measured on a wet
basis and the percent carbon dioxide
(%CO«i) is measured on a dry basis, the fol-
lowing equation Is applicable:
100
NOTE.—See section 5.3.1.2 on the limita-
tion on the usage of Bn.
When the pollutant concentration
-------
42184
PROPOSED RULES
court order to promulgate final regula-
tions within 6 months of today's pro-
posal. This is also the maximum
period of time for promulgation per-
mitted by section 307(d)(l> of the
Clean Air Act. To comply with the
schedule set forth in the court's order,
but at the same time to maximize the
public's involvement in the rulemak-
ing, the Agency will provide over 14
weeks for public input.
The public involvement period will
be structured as follows: Written com-
ments may be submitted by any inter-
ested member of the public for a
period of 60 days. Following the public
comment period, 2 days of hearings
will be held. The hearings will be legis-
lative in nature with Agency officials
empaneled to receive testimony and
ask questions of all witnesses. Persons
interested in testifying at the hearing
should advise the Agency as instructed
above. Though no cross-examination
will take place at the hearings, written
questions directed at witnesses testify-
ing at the hearing may be submitted
to the panel by members of the audi-
ence.
It is the expectation of the Agency
that the hearing testimony will con-
centrate on clarifying, supplementing,
and rebutting previously submitted
written statements. The Agency recog-
nizes that interested persons will re-
quire a period of time prior to the
hearing to read the written submto-
sions of other interested parties so
that an Informed comment may be
made at the public hearing. In addi-
tion, all written comments received
will be placed in the docket (docket
No. OAQPS-78-1) as soon after receipt
as practicable. All comments received
will be on file no later than 2 calendar
days after the close of the 60-day com-
ment period. The docket is available
for public inspection and copying be-
tween 8 a.m. and 4 p.m., Monday
through Friday, at EPA's Central
Docket Section, Room 2903B, Water-
side Mall, 401 M Street SW., Washing-
ton. D.C. 20460.
As required by section 307
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RULES AND REGULATIONS
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C—AIR PROGRAMS
|FRL 423-6]
PART 51—REQUIREMENTS FOR THE
PREPARATION. ADOPTION AND SUB-
MITTAL OF IMPLEMENTATION PLANS
Emission Monitoring of Stationary Sources
On September 11, 1974. the Environ-
mental Protection Agency (EPAi pro-
posed revisions to 40 CFR Part 51, Re-
quirement5; for the Preparation, Adop-
tion, and Submittal of Implementation
Plans EPA proposed to expand 5 51.19 to
require States to revise (heir State Im-
plementation Plans (SIP's) to include
legally enforceable procedures requiring
certain specified categories of existing
stationary sources to monitor emissions
on a continuous basis. Revised SIP's sub-
mitted by States in response to the pro-
posed revisions to 40 CFR 51.19 would
• have (D required owners or operators
of specified categories of stationary
sources to install emission monitoring
equipment within one year of plan ap-
proval. (2) specified the categories of
sources subject to the requirements. (3)
identified for each category of sources
the pollutant(s) which must be moni-
tored, (4) set forth performance specifi-
cations for continuous emission monitor-
Ing instruments, (5) required that such
instruments meet performance specifi-
cations through on-site testing by the
owner or operator, and (6) required that
data derived from such monitoring be
summarized and made available to the
State on a quarterly basis.
As a minimum, EPA proposed that
States must adopt and implement legally
enforceable procedures to require moni-
toring of emissions for existing sources
In the following source categories 'but
only for sources required to limit emis-
sions to comply with an adopted regula-
tion of the State Implementation Plan):
(a) Coal-fired steam generators of
more than 250 million BTU per hour heat
input (opacity, sulfur dioxide, oxides of
nitrogen and oxygen);
(b) Oil-fired steam generators of more
than 250 million BTU per hour heat In-
put (sulfur dioxide, oxides of nitrogen
and oxygen). An opacity monitor was re-
quired only if an emission control device
is needed to meet partlculate emission
regulations, or If violations of visible
emission regulations are noted;
(c) Nitric acid plants (oxides of
nitrogen);
(d) Sulfuric acid plants (sulfur di-
oxide) ; and
(e) Petroleum refineries' fluid catalytic
cracking unit catalyst regenerators
(opacity).
Simultaneously, the Agency proposed
similar continuous emission monitoring
requirements for new sources for each of
the previously identified source categor-
ies, subject to the provisions of federal
New Source Performance Standards set
forth in 40 CPR Part 60. Since many of
the technical aspects of the two proposals
were similar, 11 not the same, the pro-
posed regulations for Part 51 ii.c.,_those
relating to SIP's and existing sources>
included by rek'iTiirr many specific tech-
nical details set forth in 40 CFR Part 60,
(39 FR 32852).
At the time of the proposal of the con-
tinuous emission monitoring regulations
in the FEDERAL REGISTER, the Agency in-
vited comments on the proposed rule-
making action Many interested parties
submitted comments. Of the 76 comments
received, 35 were from electric utility
companies, 26 were from oil refineries or
other industrial companies, 12 were from
governmental agencies, and 3 were from
manufacturers and/or suppliers of emis-
sion monitors No comments were re-
ceived from environmental groups. Fur-
ther, prior to the proposal of the regula-
tions in the FEDERAL REGISTER, the Agency
sought comments from various State and
local air pollution control agencies and
Instrument manufacturers. Copies of
each of these comments are available
for public inspection at the EPA Freedom
of Information Center, 401 M Street,
S.W., Washington, D.C. 20460. These
comments have been considered, addi-
tional information collected and assessed,
and where determined by the Adminis-
trator to be appropriate, revisions and
amendments have been made in for-
mulating these regulations promulgated
herein.
General Discussion oj Comments. In
general, the comments received by the
Agency tended to raise various objections
with specific portions of the regulations.
Some misinterpreted the proposed reg-
ulations, not realizing that emission
monitoring under the proposal was not
required unless a source was required to
comply with an adopted emission limita-
tion or sulfur in fuel limitation that was
part of an approved or promulgated State
Implementation Plan. Many questioned
the Agency's authority and the need to
require sources to use continuous emis-
sion monitors. Others stated that the
proposed regulations were inflationary,
and by themselves could not reduce emis-
sions to the atmosphere nor could they
improve air quality. A relatively common
comment was that the benefits to be de-
rived from the proposed emission moni-
toring program were not commensurate
with the costs associated with the pur-
chase, installation, and operation of such
monitors. Many'stated that the proposed
regulations were not cost-effectively ap-
plied and they objected to all sources
within an identified source category be-
ing required to monitor emissions, with-
out regard for other considerations. For
instance, some suggested that it was un-
necessary to monitor emissions from
steam generating plants that may soon
be retired from operation, or steam gen-
erating boilers that are infrequently used
(such as for peaking and cycling opera-
tions) or for those sources located in
areas of the nation which presently have
ambient concentrations better than na-
tional ambient air quality standards. This
latter comment was especially prevalent
in relation to the need for continuous
emission monitors designed to measure
emissions of oxides of nitrogen. Further,
commentors generally suggested that
state and local control agencies, rather
than EPA should be responsible for
determining which sources should moni-
tor emissions. In this regard, the com-
mentors suggested that a determination
of the sources which should install con-
tinuous monitors should be made on a
case-by-case basjs. Almost all objected to
the data reporting requirements stating
that the proposed requirement of sub-
mission of all collected data was excessive
and burdensome Comments from state
and local air pollution control agencies in
general were similar to those from the
utility and industrial groups, but in addi-
tion, some indicated that the manpower
needed to implement the programs re-
quired by the proposed regulations was
not available.
Rationale tor Emission Monitoring
Regulation. Presently, the Agency's reg-
ulations setting forth the requirements
for approvable SIP's require States to
have legal authority to require owners
or operators of stationary sources to in-
stall, maintain, and use emission moni-
toring devices and to make periodic
reports of emission data to the State
(40 CFR Sl.ll(a) (6)). This requirement
was designed to partially implement the
requirements of Sections 110
(li) and (iii) of the Clean Air Act, which
state that implementation plans must
provide "requirements for installation
of equipment by owners or operators of
stationary sources to monitor emissions
from such sources", and "for periodic
reports on the nature and amounts of
such emissions". However, the original
implementation plan requirements did
not require SIP's to contain legally en-
forceable procedures mandating contin-
uous emission monitoring and recording.
At the time the original requirements
were published, the Agency had accumu-
lated little data on the availability and
reliability of continuous monitoring de-
vices. The Agency believed that the
state-of-the-art was such that It was
not prudent to require existing sources
to Install such devices.
Since that time, much work has been
done by the Agency and others to field
test and compare various continuous
emission monitors. As a result of this
work, the Agency now believes that for
certain sources, performance specifica-
tions for accuracy, reliability and dura-
bility can be established for continuous
emission monitors of oxygen, carbon
dioxide, sulfur dioxide, and oxides of
nitrogen and for the continuous meas-
urement of opacity. Accordingly. It is
the Administrator's judgment that Sec-
tions 110(a)(2)(F) (11) and (Hi) should
now be more fully imolemented.
The Administrator believes that a
sound program of continuous emission
monitoring and reporting will play an
Important role in the effort to attain
and maintain national standards. At tJie
present time, control agencies rely upon
infrequent manual source tests and
periodic field Inspections to provide
much of the enforcement information
necessary to ascertain compliance of
sources with adopted regulations. Man-
ual source tests are generally performed
on a relatively infrequent basis, such as
FEDERAL IECISTII, VOL. 40, NO. If4—MONDAY, OCTOIER *, 1975
III-99
-------
RULES AND REGULATIONS
once per year, and in some cases, affected
sources probably have never been tested.
Manual stack tests are generally per-
formed under optimum operating con-
ditions, and as such, do not reflect the
full-time emission conditions from a
source. Emissions continually vary with
fuel firing rates, process material feed
rates and various other operating condi-
tions. Since manual stack tests are only
conducted for a relatively short period
of time (e.g.. one to three hours*, they
cannot be representative of all operating
conditions. Further, frequent manual
stack tests (such as conducted on ti
quarterly or more frequent basis* are
costly and may be more expensive than
continuous monitors that provide much
more Information. State Agency en-
forcement by field inspection is also
sporadic, with only occasional Inspection
of certain sources, mainly for visible
emission enforcement.
Continuous emission monitoring and
recording systems, on the other hand,
can provide a continuous record of emis-
sions under all operating conditions. The
continuous emission monitor is a good
indicator of whether a source is using
good operating and maintenance prac-
tices to minimize emissions to the at-
mosphere and can also provide a valu-
able record to indicate the performance
of a source in complying with applicable
emission control regulations. Addition-
ally, under certain instances, the data
from continuous monitors may be suf-
ficient evidence to issue ft notice of vio-
lation. The continuous emission record
can also be utilized to signal a plant
upset or equipment malfunction so that
the plant operator can take corrective
action to reduce emissions. Use of emis-
sion monitors can therefore provide val-
uable information to-minimize emissions
to the atmosphere and to assure that
full-time control efforts, such as good
maintenance and operating conditions,
are being utilized by source operators.
The,Agency believes that it is necessary
to establish national minimum require-
ments for emission monitors for specified
sources rather than allow States to de-
termine on a case-by-case basis the spe-
cific sources which need to continuously
monitor emissions. The categories speci-
fied in the regulations represent very sig-
nificant sources of emissions to the at-
mosphere. States in developing SIP's
have generally adopted control regula-
tions to minimize emissions from these
sources. Where such regulations exist, the
Agency believes that continuous emission
monitors are necessary to provide infor-
mation that may be used to provide an
indication of source compliance. Further,
It is believed that if the selection of
sources on a case-by-case basis were left
to the States, that some States would
probably not undertake an adequate
emission monitoring program. Some
State Agencies who commented on the
proposed regulations questioned the
tute-ofithe-art of emission monitoring
*nd «ui«d their opinion that the pro-
PJ»*d requirements were premature
Thmtore. It Is the Administrator's
that, in order to assure an
adequate nationwide emission moni-
toring program, minimum emission mon-
itorinp requirements must bo established.
The source catepories affected by the
regulations were selected because they
are significant sources of emissions and
because the Agency's work at the time of
the proposal of these regulations in the
field of continuous emission monitoring
evaluation focused almost exclusively on
these source categories. The Agency is
continuing to develop data on monitoring
devices for additional source categories.
It is EPA's intent to expand the minimum
continuous emission monitoring require-
ments from time to time when the eco-
nomic and technological feasibility of
continuous monitoring equipment is
demonstrated and where such monitor-
ing is deemed appropriate for other sig-
nificant source categories.
Discussion ot Major Comments. Many
rommentors discussed the various cost
aspects of the proposed regulations, spe-
cifically stating that the costs of con-
tinuous monitors were excessive and in-
flationary. A total of 47 commentors ex-
pressed concern for the cost and/or cost
effectiveness of continuous monitors.
Further, the Agency's cost estimates for
purchasing and installing monitoring
systems and the costs for data reduction
and reporting were questioned. In many
cases, sources provided cost estimates for
installation and operation of continuous
monitors considerably in excess of the
cost estimates provided by the Agency.
In response to these comments, a fur-
ther review was undertaken by the Agen-
cy to assess the cost impact of the regu-
lations. Three conclusions resulted from
this review. First, it was determined that
the cost ranges of the various emission
monitoring systems provided by the
Agency are generally accurate for new
sources. Discussions with equipment
manufacturers and suppliers confirmed
this cost information. Approximate in-
vestment costs, which include the cost
of the emission monitor, installation cost
at a new facility, recorder, performance
testing, data reporting systems and asso-
ciated engineering costs are as follows:
for opacity, $20,000; for sulfur dioxide
and oxygen or oxides of nitrogen and
oxygen, $30,000; and for a source that
monitors opacity, oxides of nitrogen, sul-
fur dioxide and oxygen, $55,000. Annual
operating costs, which include data re-
duction and report preparation, system
operation, maintenance, utilities, taxes,
insurance and annualized capital costs
at 101"/' 'or 8 years arc: $8,500; $16,000;
and $30.000 respectively for the cases
described above.* 1>
Secondly, the cost review indicated
that the cost of installation of emission
monitors for existing sources could be
considerably higher than for new sources
because of the difficulties in providing
access to a sampling location that can
provide a representative sample of emis-
sions. The cost estimates provided by the
Agency in the proposal were specifically
developed for new sources whose in-
stallation costs are relatively stable since
provisions for monitoring equipment can
be incorporated at the time of plant de-
sign. This feature is not available for ex-
isting sources, hence higher costs get
erally result. Actual costs of installatlr
at existing sources may vary from 01
to five times the cost of normal install^
tion at new sources, and in some caM
even higher costs can result. For exam
pie, discussions with instrument suppli
ers indicate that a typical cost of instal
lation of an opacity monitor on an exisi
ing source may be two to three times tli
purchase price of the monitor. Difficul
ties also exist for Installation of gaseou
monitors at existing sources.
It should be noted that these installn
tion costs Include material costs for scaf
folding, ladders, sampling ports an'
other items necessary to provide acces
to a location where source emissions cai
be measured. It is the Agency's opinio:
that such costs cannot be solely attrib
uted to these continuous emission moni
toring regulations. Access to samplini
locations is generally necessary to dc
termine compliance with applicable stall
or local emission limitations by routinr
manual stack testing methods. There-
fore, costs of providing access to a rep-
resentative sampling location are more
directly attributed to the cost of com-
pliance with, adopted emission limita-
tions, than with these continuous emis-
sion monitoring regulations.
Lastly, the review of cost information
indicated that a number of commentors
misinterpreted the extent of the pro-
posed regulations, thereby providing cost
estimates for continuous monitors which
were not required. Specifically, all com-
mentors did not recognize that the pro-
posed regulations required emission mon-
itoring for a source only if an applicable
State or local emission limitation of an
approved SIP affected such a source. For
example, if the approved SIP did not
contain an adopted control regulation to
limit oxides of nitrogen from steam-
generating, fossil fuel-fired boilers of a
capacity in excess of 250 million BTU per
hour heat input, then such source need
not monitor oxides of nitrogen emis-
sions. Further, some utility industry com-
mentorn included the costs of continuous
emission monitors for sulfur dioxide. The
propossd regulations, however, generally
allowed the use of fuel analysis by speci-
fied ASTM procedures as an alternative
which, in most cases, is less expensive
than continuous monitoring. Finally, the
proposed regulations required the con-
tinuous monitoring of oxygen in the
exhaust gas only if the source must
otherwise continuously monitor oxides of
nitrogen or sulfur dioxide. Oxygen in-
formation is used solely to provide a cor-
rection for excess nir when converting
the measurements of gaseous pollutants
concentrations in the exhaust gas stream
to units of an applicable emission limi-
tation. Some commentors did not recog-
nize this point (which was not specifical-
ly stated in the proposed regulations)
and provided cost estimates for oxygen
monitors when thev were not required by
the proposed regulations.
While not all commentors' cost esti-
mates were correct, for various reasons
noted above, it is clear that the costs
associated with implementing these
emission monitoring regulations are sig-
MDERAl IIOISTIR, VOL 40, NO. 1*4—MONDAY, OCTOMR *, WS
III-100
-------
RULES AND REGULATIONS
nlficant The Administrator, however.
believes that the benefits to be derived
from emission monitoring are such that
the costs are not unreasonable. The Ad-
ministrator does, however, agree with
many commentors that the proposed reg-
ulations, in some cases, were not applied
cost-effectively and, as such, the regula-
tions promulgated herein have been
modified to provide exemptions to cer-
tain sources from these minimum re-
quirements.
One comment from another Federal
Agency concerned the time period that
emissions are to be averaged when re-
porting excess emissions. Specifically, the
commentor assumed that the emission
control regulations that have been
adopted by State and local agencies were
generally designed to attain annual am-
bient air quality standards. As such, the
commentor pointed out that short-term
emission levels in excess of the adopted
emission standard should be acceptable
for reasonable periods of time.
The Administrator docs not agree with
this rationale for the following reasons.
First, it is not universally true that an-
nual Ambient standards were the design
basis of emission control regulations. In
many cases, reductions to attain short-
term standards require more control
than do annual standards. Even if the
regulations were based upon annual
standards, allowing excess emissions of
the adopted emission control regulation
on a short-term basis could cause non-
complianue with annual standards. More
importantly, however, a policy of legally
allowing excesses of adopted control reg-
ulations would in effect make the current
emission limitation unenforceable. If the
suggestion were implemented, a question
would arise as to what is the maximum
emission level that would not be consid-
ered an excess to the adopted regulation.
The purpose of the adopted emission lim-
itation was to establish the acceptable
emission level. Allowing emissions in ex-
cess of that adopted level would cause
confusion, ambiguity, and in many cases
could result in an unenforceable situa-
tion. Hence the Administrator does not
concur with the commentor's suggestion.
Modifications to the Proposed Regu-
lations. The modification to the regu-
lations which has the most significant
Impact involves the monitoring require-
ments for oxides of nitrogen at fossil
fuel-fired steam generating boilers and
at nitric acid plants. Many commentors
correctly noted that the Agency in the
past (June 8, 1973, 38 FR 15174) had In-
dicated that the need for many emis-
sion control regulations for oxides of
nitrogen were based upon erroneous
data Such a statement was made after
a detailed laboratory analysis of the ref-
erence ambient measurement method
for nitrogen dioxide revealed the method
to give false measurements. The
sampling technique generally indicated
concentrations of nitrogen dioxide
higher than actually existed in the
atmosphere. Since many control agen-
cies prior to that announcement had
adopted emission regulations that were
determined to be needed based upon
these erroneous data, and since new data.
collected by other measurement tech-
niques, indicated that in most areas of
the nation such control regulations were
not necessary to satisfy the requirements
of the SIP. the Agency suggested that
States consider the withdrawal of
adopted control regulations for the con-
trol of oxides of nitrogen from their SIP's
(May 8, 1974, 39 FR 16344). In many
States, control agencies have not taken
action to remove these regulations from
the SIP. Hence, the commentors pointed
out that the proposed regulations to re-
quire continuous emission monitors on
sources affected by such regulations is
generally unnecessary.
Because of the unique situation in-
volving oxides of nitrogen control regu-
lations, the Administrator has deter-
mined that the proposed regulations to
continuously monitor oxides of nitrogen
emissions may place an undue burden on
source operators, at least from a stand-
point of EPA specifying minimum moni-
toring requirements. The continuous
emission monitoring requirements for
such sources therefore have been modi-
fied. The final regulations require the
continuous emission monitoring of
oxides of nitrogen only for those sources
in Air Quality Control Regions (AQCR'si
where the Administrator has specifically
determined that a control strategy for
nitrogen dioxide is necessary. At the
present time such control strategies are
required only for the Metropolitan Los
Anceles Intrastate and the Metropoli-
tan Chicago Interstate AQCR's.
It should be noted that a recent com-
pilation of valid nitrogen dioxide air
quality data suggests that approximately
14 of the other 245 AQCR's in the nation
may need to develop a control strategy
for nitrogen dioxide. These AQCR's are
presently being evaluated by the Agency.
If any additional AQCR's are identified
as needing a control strategy for nitro-
gen dioxide at that time, or any time
subsequent to this promulgation, then
States in which those AQCR's are lo-
cated must also revise their SIP's to
require continuous emission monitoring
for oxides of nitrogen for specified
sources. Further, it should be noted that
the regulations promulgated today are
minimum requirements, so that States,
if they believe the control of oxides of
nitrogen from sources is necessary may,
as they deem appropriate, expand the
continuous emission monitoring require-
ments to apply to additional sources not
affected by these minimum requirements.
Other modifications to the proposed
regulation resulted from various com-
ments. A number of commentors noted
that the proposed regulations included
some sources whose emission impact on
air quality was relatively minor. Specifi-
cally, they noted that fossil fuel-fired
steam generating units that were used
solely for peaking and cycling purposes
should be exempt from the proposed reg-
ulations. Similarly, some suRpcsted that
smaller sized units, particularly fitcam-
eeneratlng units less than 2,500 million
BTU per hour heat input, should also
be exempted. Others pointed out that
units soon to be retired from operation
should not be required to install con-
tinuous monitoring devices and that
sources located in areas of the nation
that already have air quality better than
the national standards should be relieved
of the required monitoring and reporting
requirements. The Agency has considered
these comments and has made the fol-
lowing judgments.
In relation to fossil fuel-fired steam
generating units, the Agency has deter-
mined that such units that have an an-
nual boiler capacity factor of 30% or less
as currently defined by the Federal Power
Commission shall be exempt from the
minimum requirements for monitoring
and reporting. Industrial boilers used at
less than 307r of their annual capacity,
upon demonstration to the State, may
also be granted an exemption from these
monitoring requirements. The rationale
for this exemption is based upon the fact
that all generating units do not produce
power at their full capacity at all times.
There are three major classifications of
power plants based on the degree to
which their rated capacity is utilized on
an annual basis. Baseload units are de-
signed to run at near full capacity almost
continuously. Peaking units are operated
to supply electricity during periods of
maximum system demand. Units which
are operated for intermediate service
between the extremes of baseload and
peaking are termed cycling units.
Generally accepted definitions term
units generating 60 percent or more of
their annual capacity as baseload, those
generating less than 20 percent as peak-
ing and those between 20 and 60 percent
as cycling. In general, peaking units are
older, smaller, of lower efficiency, and
more costly to operate than base load or
cycling units. Cycling units are also gen-
erally older, smaller and less efficient
than base load units. Since the expected
life of peaking units is relatively short
and total emissions from such units are
small, the benefits gained by installing
monitoring instruments are small in '
comparison to the cost of such equip-
ment. For cycling units, the question of
cost-effectiveness is more difficult to as-
certain. The units at the upper end of
the capacity factor range (i.e., near 60%
boiler capacity factor) are candidates for
continuous emission monitoring while
units at the lower end of the range (i.e.,
near 20% boiler capacity factor) do not
represent good choices for continuous
monitors. Based upon available emission
Informntion. It has been calculated that
fossil fuel-fired steam generating plants
with a 307< or less annual boiler capacity
fnctor contribute approximately less
than 5% of the total sulfur dioxide from
all such power plants. (2) Hence, the
final regulations do not affect any boiler
that has an annual boiler capacity factor
of loss than 30%. Monitoring require-
ments will thus be more cost effectively
applied to the newer, larger, and more
efficient units that burn a relatively
lamer portion of the total fuel supply.
Some commentors noted that the age
of the facility should be considered in
relation to whether a source need com-
KDIRAL IEOISTIR, VOL 40, NO. lt«—MONDAY, OCTOIfR t, WS
III-101
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RULES AND REGULATIONS
ply with the proposed regulations. For
fossil fuel-fired steam generating: units.
the exemption relating to the annual
boiler capacity factor previously dis-
cussed should ReneraJly provide relief for
older units. It is appropriate, however,
that the age of the facility be consid-
ered for other categories of sources af-
fected by the proposed regulations. As
such, the final regulations allow that any
source that is scheduled to be retired
within five years of the inclusion of mon-
itoring requirements for the source in
Appendix P need not comply with the
minimum emission monitoring require-
ments promulgated herein. In the Ad-
ministrator's judgment, the selection of
five years as the allowable period for
this exemption provides reasonable re-
lief for those units that will shortly be
retired. However, it maintains full re-
quirements on many older units with a
number of years of service remaining.
In general, older units operate less effi-
ciently and are less well controlled than
newer units so that emission monitoring
is generally useful. The exemption pro-
vided in the final regulations effectively
allows such retirees slightly more than a
two-year period of relief, since the sched-
ule of implementation of the regulations
•would generally require the installation
of emission monitors by early 1978.
States mast submit, for EPA approval.
the procedures they will implement to
use this provision. States are advised
that such exemptions should only be pro-
vided where a bona fide intent to cease
operations has been clearly established.
In cases where such sources postpone
retirement. States shall have established
procedures to require such sources to
monitor and report emissions. In this re-
gard, it should be noted that Section
113'c) f2) of the Act provides that any
person who falsifies or misrepresents a
record, report or other document filed or
required under the Act shall, upon con-
viction, be subject to fine or imprison-
ment, or both.
A further modification to the proposed
regulations affects the minimum size of
the units within each of the source cate-
gories to which emission monitoring and
reporting shall be required. As suggested
by many commentors. the Agency has in-
vestigated the cost effectiveness of re-
quiring all unite within the identified
source categories to install emission mon-
itors. Each pollutant for each source
category identified in the proposed reg-
ulations was evaluated. For fossil fuel-
fired steam generating units, the pro-
posal required compliance for all boilers
with 250 million BTU per hour heat in-
put, or greater. For opacity, the proposed
regulations required emission monitoring
for all coal-fired units, while only those
oil-fired units that had been observed as
violators of visible emission regulations
or must use an emission control device to
meet particulate matter regulations were
required to install such devices. Oas-
flred units were exempted by the pro-
posed regulations.
After investigating the particulate
emission potential of these sources, it has
been determined that no modification In
the size limitation for boilers in relation
to opacity is warranted. The rationale
for this judgment is that the smaller-
sized units affected by the proposed reg-
ulation tend to be less efficiently oper-
ated or controlled for particulate matter
than are the larger-sized units. In fact,
smaller units generally tend to emit more
particulate emissions on an equivalent
fuel basis than larger-sized units. (2)
Because of the potential of opacity regu-
lation violations, no modifications have
been made to the regulations as to the
size of steam generating boilers that
must measure opacity.
Emissions of oxides of nitrogen from
boilers are a, function of the temperature
in the combustion chamber and the cool-
ing of the combustion products. Emis-
sions vary considerably with the size and
the type of unit. In general, the larfter
units produce more oxides of nitrogen
emissions. The Agency therefore finds
that the minimum size of a unit affected
by the final regulations can be increased
from 250 to 1,000 million BTU per hour
heat input, without significantly reduc-
ing the total emissions of oxides of nitro-
gen that would be affected by monitoring
and reporting requirements. Such a mod-
ification would have the effect of exempt-
ing approximately 56% of the boilers
over 250 million BTU per hour heat input
capacity, on a national basis, while main-
taining emission monitoring and report-
ing requirements for approximately 78%
of the potential oxides of nitrogen emis-
sions from such sources.<2'< Further, in
the 2 AQCR's where the Administrator
has specifically called for a control
strategy for nitrogen dioxide, the boilers
affected by the regulation constitute 507r
of the steam generators greater than 250
million BTU per hour heat input, yet
they emit 80 °>, of the nitrogen oxides
from such steam generators in these
2 AQCR's.(2)
Also, certain types of boilers or burn-
ers, due to their design characteristics,
may on a regular basis attain emission
levels of oxides of nitrogen well below
the emission limitations of the applica-
ble plan. The regulations have been re-
vised to allow exemption from the
requirements for installing emission
monitoring and recording equipment for
oxides of nitrogen when a facility is
shown during performance tests to op-
erate with oxides of nitrogen emission
levels 30% or more below the emission
limitation of the applicable plan. It
should be noted that this provision ap-
plies solely to oxides of nitrogen emis-
sions rather than other pollutant emis-
sions, since oxides of nitrogen emissions
are more directly related to boiler de-
sign characteristics than are other
pollutants.
Similar evaluations were made for
nitric acid plants, sulfuric acid plants
and catalytic cracking unit catalyst re-
generators at petroleum refineries. For
each of these industries it was found that
modifications to the proposed regulations
could be made to Increase the minimum
size of the units affected by the proposed
regulations without significantly de-
creasing the total emissions of various
pollutants that would be affected by
these monitoring and reportinc require-
ments. Specifically, for nitric acid plants
it was found that by modifying the pro-
posed regulations to affect only those
plants that have a total daily production
capacity of 300 tons or more of nitric acid
(rather than affecting all facilities as
proposed) that approximately 79% of
the nitric acid production on a national
basis would be affected by the provisions
of these monitoring and reporting re-
quirements. On the other hand, such a
modification reduces the number of
monitors required for compliance with
these regulations by approximately 46%.
(2) At the present time, only nitric acid
plants in AQCR's where the Administra-
tor has specifically called for a control
strategy for nitrogen dioxide will be can-
didates for continuous emission monitor-
ing requirements for the reasons men-
tioned previously. In the 2 AQCR's where
such a control strategy has been called
for, there is only one known nitric acid
plant and that is reported to be less than
300 tons per day production capacity—
hence no nitric acid plants at the pre ;ent
time will be affected by these monito ing
requirements.
Similarly, evaluations of sulfuric r*cid
plants and catalytic cracking catalyst re-
generators at petroleum refineries re-
sulted in the conclusion that minimum
sizo limitations of 300 tons per day pro-
duction rate at sulfuric acid plants, and
20,000 barrels per day of fresh feed to
any catalytic cracking unit at petroleum
refineries could be reasonably estab-
lished. Such modifications exempt ap-
proximately 37% and 39% respectively
of such plants on a national basis from
these emission monitoring and reporting
reauirements, while allowing about 9%
of the sulfur dioxide emissions from sul-
furic acid plants and 12% of the par-
ticulate matter emissions from catalytic
cracking units to be emitted to the at-
mosphere without being measured and
reported. f2) The Agency believe that
such modifications provide a reasonable
balance between the costs associated
with emission monitoring and reporting,
and the need to obtain such information.
A number of commentors suggested
that sources be exempt from the pro-
posed emission monitoring regulations if
?uch sources are located within areas of
the nation that are already attaining .
national standards. The Administrator
does not believe that such an approach
would be consistent with Section 110 of
the Clean Air Act, which requires con-
tinued maintenance of ambient stand-
ards after attainment. In many areas,
the standards are being attained only
through effective implementation of
emission limitations. Under the Clean Air
Act. continued compliance with emis-
sion limitations In these areas is just as
important as compliance in areas which
have not attained the standards.
Another major comment concerned
the proposed data reporting require-
ments. Thirty-four (34) commentors ex-
pressed concern at the amount of data
which the proposed regulations required
to be recorded, summarized, and submit-
KDIIAL UGISTIR, VOL. 40, NO. 1*4—MONDAY, OCTOIIR *, WS
III-102A
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RULES AND REGULATIONS
ted to the State. It was generally indi-
cated by the commentors that the datn
reportinp requirements were excessive.
Commentors questioned the purpose of
reporting all measured datn while some
State agencies indicated they hnve lim-
ited resources to handle such informa-
tion. EPA believes that, in some cases.
the cornmentors misconstrued the data
reporting reaulrements for cxistinR
sources. In light of each of these com-
ments, the final regulations, with respect
to the data reporting requirements for
gaseous pollutants and opacity, have
been modified
For gaseous emissions, the proposed
regulations required the reporting of all
one-hour averages obtained by the emis-
sion monitor. Because of the comments
on this provision, the Agency has reex-
amincd the proposed data reporting re-
quirements. As a result, the Agency has
determined that only information con-
cerning emissions in excess of emission
limitations of the applicable plan is nec-
essary to satisfy the intent of these reg-
ulations. Therefore, the data reporting
requirements for gaseous pollutants
have been modified. The final regulations
require that States adopt procedures that
would require sources to report to the
State on emission levels in excess of the
applicable emission limitations 'i.e., ex-
cess emissions> for the time period spec-
ified in the regulation with which com-
pliance is determined. In other words, if
an applicable emission limitation re-
quired no more than 1.0 pounds per-hour
SO., to be emitted for any two-hour aver-
aging period, the data to be reported by
the source should identify the emission
level (i.e., emissions stated in pounds per
hour) averaged over a two-hour time
period, for periods only when this emis-
sion level was in excess of the 1.0 pounds
per hour emission limitation. Further,
sources shall be required to maintain a
record of all continuous monitoring ob-
servations for gaseous pollutants rand
opacity measurements) for a period of
two years and to make such data avail-
able to the State upon request. The final
regulations have also been amended to
add a provision to require sources to re-
port to the State on the apparent reason
lor all noted violations of applicable reg-
ulations.
The proposed data reporting require-
ments for opacity have also been modi-
tied. Upon reconsideration of the extent
of the data needed to satisfy the Intent
of these regulations, it is the Adminis-
trator's judgment that for opacity States
must obtain excess emission measure-
ments during each hour of operation.
However, before determining excess
emissions, the number of minutes gen-
erally exempted by State opacity regu-
lations should be considered. For ex-
ample, where a regulation allows two
minutes of opacity measurements in
excess of the standard, the State
need only require the source to re-
. port all opacity measurements in excess
of the standard during any one hour,
minus the two-minute exemption. The
excess measurements shall be reported
in actual per cent opacity averaged for
one clock minute or such other time pe-
riod deemed appropriate by the State.
Averages may bo calculated cither by
arithmetically avcraping a minimum of
4 equally spaced dnta points per minute
or by integration of the monitor output.
Some commentors raised questions
concerning the provisions in the proposed
regulations which allow the use of fuel
analysis for computing emissions of sul-
fur dioxide in lieu of installing a con-
tinuous monitoring device for this pol-
lutant. Of primary concern with the fuel
analysis approach among the corn-
mentors was the frequency of the analy-
sis to determine the sulfur content of the
fuel. However, upon inspection of the
comments by the Agency, a more sig-
nificant issue has been uncovered. The
issue involves the determination of what
constitutes excess emissions when a fuel
analysis is used as the method to measure
source emissions. For example, the sulfur
content varies significantly within a load
of coal, i.e., while the average sulfur
content of a total load of coal may be
within acceptable limits in relation to a
control regulation which restricts the
sulfur content of coal, it is probable that
portions of the coal may have a sulfur
content above the allowable level. Simi-
larly, when fuel oils of different specific
gravities are stored within a common
tank, such fuel oils tend to stratify and
may not be a homogeneous mixture.
Thus, at times, fuel oil in excess of allow-
able limits may be combusted. The ques-
tion which arises is whether the combus-
tion of this higher sulfur coal or oil is a
violation of an applicable sulfur content
regulation. Initial investigations of this
issue have indicated a relative lack of
specificity on the subject.
The Agency is confronted with this
problem not only in relation to specifying
procedures for the emission reporting re-
quirements for existing sources but also
in relation to enforcement considerations
for new sources affected by New Source
Performance Standards. At this time, a
more thorough investigation of the situ-
ation in necessary prior to promulgation
of procedures dealing with fuel analysis
for both oil and coal. At the conclusion
of this investigation, the Agency will set
forth its findings and provide guidance
to State and local control agencies on
this issue. In the meantime, the portion
of the proposed regulations dealing with
fuel analysis is being withheld from pro-
mulgation at this time. As such, States
shall not be required to adopt provisions
dealing with emission monitoring or re-
porting of sulfur dioxide emissions from
those sources where the States may
choose to allow the option of fuel anal-
ysis as an alternative to sulfur dioxide
monitorinc. However, since the fuel
analysis alternative may not be utilized
by a source that has installed sulfur di-
oxide control equipment (scrubbers),
States shall set forth legally enforceable
procedures which require emission moni-
tors on such sources, where these emis-
sion monitoring regulations otherwise
require their installation.
Other Modifications to Proposed Reg-
ulations. In addition to reducing the
number of monitors required under the
proposed regulations, a number of modi-
fications to various procedures In the
proposed regulations have been con-
sidered and are included in the final
regulations. One modification which has
been made is the deletion of the require-
ment to install continuous monitors at
"the most representative" location. The
final regulations require the placement
of an'emission monitor at "a representa*
tive" location in the exhaust gas system:
In many cases "the most representative"
location may be difficult to locate and
may be inaccessible.without new plat-
forms, ladders, etc.. being iastalled. Fur-
ther, other representative locations can
provide adequate Information on pollut-
ant emissions if minimum criteria for
selection of monitoring locations are ob-
served. Guidance in determining a repre-
sentative sampling' location is contained
within the Performance Specification
for each pollutant monitor in the emis-
sion monitoring regulations for New
Source Performance Standards (Appen-
dix B, Part 60 of this Chapter). While
these criteria are designed for new
sources, they are also useful in deter-
mining representative locations for ex-
isting sources.
A further modification to the proposed
regulation is the deletion of the require-
ment for new performance tests when
continuous emission monitoring equip-
ment is modified or repaired. As pro-
posed, the regulation would have re-
quired a new performance test whenever
any part of the continuous emission
monitoring system was replaced. This
requirement was originally incorporated
in the regulations to assure the use of
a well-calibrated, finely tuned monitor.
Commentors pointed out that the re-
quirement of conducting new perform-
ance tests whenever any part of an in-
strument is changed or replaced is costly
and in many cases not required. Upon
evaluation of this comment, the Admin-
istrator concurs that performance tests
are not required after each repair or re-
placement to the system. Appropriate
changes have been made to the regula-
tions to delete the requirements for new
performance tests. However, the final
regulations require the reporting of the
various repairs made to the emission
monitoring system durine each quarter
to the State. Further, the State must
have procedures to require sources to re-
port to the State on a quarterly basis in-
formation on the amount of time and the
reason why the continuous monitor was
not in operation. Also the State must
have legally enforceable procedures to
reauire a source to conduct a new per-
formance test whenever, on the basis of
available information, the State deems
sur-h test is necessary.
The time period proposed for the in-
stallation of the reouired monltorine
system. I.e., one vear after plan approval.
wns thoucht hv 21 commentors to be too
hripf. nrimarilv because of lack of avail-
able instrument's, the lack of trained per-
sonnel and thr time available for Instal-
lation of the required monitors. Equip-
ment suppliers were contacted by the
Acnncv and thev confirmed the avail-
ability of emission monitors. However.
FfDMAL ICCISTER, VOL. 40, NO 1M—MONDAY, OCTOtCX 6, 1*7S
III-102B
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RULES AND REGULATIONS
the Administrator has determined that
the time necessary for purchase, instal-
lation and performance testing of such
monitors may require more than one
year for certain installations, especially
where caseous monitors arc required. In
order to provide sources with ample time,
the Agency has modified the final regula-
tions to allow States to adopt procedures
that will provide sources 18 months after
the approval or promulgation of the re-
vised SIP to satisfy the installation and
performance testing procedures required
by these continuous monitoring regula-
tions. A provision is also included to al-
low, on a cnse-by-case basis, additional
extensions for sources where good faith
efforts have been undertaken to purchase
and install equipment, but where such
Installation cannot be accomplished
within the time period prescribed by
the regulations,
A number of State and local agencies
also commented on the lack of time pro-
vided sources to install the monitors re-
quired by the proposed regulations.
These agencies also indicated that they
must Acquire sufficient skilled manpower
to implement the regulations, such as
personnel to provide guidance to sources.
to monitor performance tests and to
analyze the emission data that are to be
submitted by the sources. Further, some
State agencies indicated that more than
six months was needed to develop the
necessary plan revisions. Most State
agencies who commented stated that one
year should be provided to allow States
to revise their SIP's. The Administrator
is aware of the various priorities which
confront State and local agencies at this
time
-------
RULES AND REGULATIONS
frequency requirements, sulfuric ncid and
nitric arid plant conversion factors;
and, for opacity monitoring equipment,
changes in the cycling time and in alicn-
mcnt procedures The reader Is cau-
tioned, however, that specific reference
to regulations In the Part 60 Preamble
Is strictly to federal New Source Perform-
ance Regulations rather than State and
local control agency regulations which
affect existing sources and which are part
of an applicable plan.
In addition to the many technical
comments received, a number of local
Issues were raised. Several commentors
questioned EPA's statutory authority to
promulgate these regulations and pointed
out other alleged legal defects in the pro-
posal. The Administrator has considered
these comments, and has found them un-
persuasive.
One commentor argued that new 40
CFR 51.19(e) will require "revisions" to
existing state plans; that "revisions" may
be called for under Section 110(a) (2(H>
of the Clean Air Act only where EPA has
found that there are "improved or more
expeditious methods" for achievinc am-
bient standards or that a state plan is
"substantially inadequate" to achieve the
standards: that the new regulation is
based upon neither of these findings; and
that therefore there is no statutory au-
thority for the regulation. This argu-
ment fails to take cognizance of Section
110(a) (2) (F) (ii) of the Act. which man-
dates that all state implementation plans
contain self-monitoring requirements.
The fact that EPA originally accepted
plans without these requirements be-
cause of substantial uncertainty as to the
reliability of self-monitoring equipment
does not negate the mandate of the
statute.
In essence, new {I 51.19(e) does not call
for "revisions" as contemplated by the
Act. but for supplements to the original
plans to make them complete. At any
rate, it is the Administrator's Judgment
that the new self-monitoring require-
ments will result in a "more expeditious"
achievement of the ambient standards.
Since these requirements are valuable
enforcement tools and indicators of mal-
functions, they should lead to a net de-
crease in emissions.
Other commentors argued that even if
EPA has statutory authority to require
self-monitoring, It has no authority to
impose specific minimum requirements
for state plans, to require "continuous"
monitoring, or to require monitoring of
oxygen, which is not a pollutant. These
comments fail to consider that a basic
precept of administrative law is that an
agency may fill in the broad directives of
legislation with precise regulatory re-
quirements. More specifically, the Ad-
ministrator has authority under Section
301 (a) of the Clean Air Act to promul-
gate "such regulations as are necessary
to carry out his functions under the Act".
Courts have long upheld the authority of
agencies to promulgate more specific re-
quirements than are set forth In en-
abling legislation, so long as the require-
ments are reasonably related to the pur-
poses of the legislation. Since the Act
requires self-monitoring without further
guidance. EPA surely has the authority
to set specific requirements in order to
carry out its function of assuring that the
Act is properly implemented
In EPA's Judcment, the requirements
set forth in 5 51.19'e) are necessary to
assure that each state's self-monitoring
program is sufficient to comply with the
Act's mandate. The fact that oxypen and
carbon dioxide are not air pollutants
controlled under the Act is legally ir-
relevant, since in EPA's judgment, they
must be monitored in order to convert
measured emission data to units of emis-
sion standards.
Other commentors have argued that
the self-monitorinc requirements violate
the protection against self-incrimination
provided in the Fifth Amendment to the
U.S Constitution, and that the informa-
tion obtained from the monitoring is so
unreliable as to be invalid evidence for
use in court.
There are two reasons why the self-
incrimination argument is invalid. First,
the self-incrimination privilege does not
apply to corporations, and it is probable
that a great majority of the sources cov-
ered by these requirements will be owned
by corporations. Secondly, courts have
continually recognized an exception to
the privilege for "records required by
law", such as the self-monitoring and
reporting procedures which are required
by the Clean Air Act. As to the validity
of evidence issue, in EPA's opinion, the
required performance specifications will
assure that self-monitoring equipment
will be sufficiently reliable to withstand
attacks in court.
Finally, some comments reflected a
misunderstanding of EPA's suggestion
that states explore with counsel ways to
draft their regulations so as to automati-
cally incorporate by reference future
additions to Appendix P and avoid the
time-consuming plan revision process.
(EPA pointed out that public participa-
tion would still be assured, since EPA's
proposed revisions to Appendix P would
always be subject to public comment on
a nation-wide basis.)
EPA's purpose was merely to suggest
an approach that a state may wish to
follow if the approach would be legal
under that state's law. EPA offers no
opinion as to whether any state law
would allow this. Such a determination
is up to the individual states.
Summary of Revisions and Clarifica-
tions to the Proposed Regulations.
Briefly, the revisions and clarifications to
the proposed regulations include:
(1) A clarification to indicate that con-
tinuous emission monitors are not re-
quired for sources unless such sources
are subject to an applicable emission
limitation of an approved SIP.
(21 A revision to require emission
monitors for oxides of nitrogen in only
those AQCR's where the Administrator
has specifically called for a control
strategy for nitrogen dioxide.
(3> A revision to Include n general pro-
vision to exempt any source that clearly
demonstrates that it will cease operation
within five years of the inclusion of moni-
toring requirements for the source in
Appendix P.
MI Revisions to exempt smaller-sized
sources and infrequently used sources
within the specified source cateRories.
(51 A revision to the data reporting
requirements to.requlre the submitlal by
the source of the State, emission data in
excess of the applicable emission limita-
tion for both opacity and gaseous pol-
lutants, rather than all measured data, as
proposed A provision has been added to
require information on the cause of all
noted violations of applicable regulations.
<6> A clarification to indicate that the
continuous monitoring of oxygen is not
required unless the continuous monitor-
ing of sulfur dioxide and/or nitrogen
oxides emissions is required by the appli-
cable SIP.
(7) A revision to allow the placement
of continuous emission monitors at "a
representative location" on the exhaust
gas system rather than at "the most
representative location" as required by
the proposed regulations.
<8» A revision to delete the require-
ments of new performance tests each
time the continuous monitoring equip-
ment is repaired or modified. However, a
new provision is included to require that
a report of all repairs and maintenance
performed during the quarter shall be re-
ported by the source to the State.
(9) A modification to provide sources
18 months rather than one year after
approval or promulgation of the revised
SIP to comply with the continuous moni-
toring regulations adopted by the States.
(10) A modification to provide States
one year, rather than the six months
after the promulgation of these regula-
tions in the FEDERAL REGISTER to submit
plan revisions to satisfy the requirements
promulgated herein.
Requirements of States. States shall be
required to revise their SIP's by Octo-
ber 6, 1976 to include legally enforceable
procedures to require emission monitor-
ing, recording and reporting, as a mini-
mum for those sources specified in the
regulations promulgated herein. While
minimum requirements have been estab-
lished, States may, as they deem appro-
priate, expand these requirements.
The regulations promulgated herein
have been revised In light of the various
comments to generally provide a more
limited Introduction into this new meth-
odology. Cooperation among affected
parties, i.e., State and local control agen-
cies, sources, instrument manufacturers
nnd suppliers, and this Agency is neces-
sary to move successfully forward In
these areas of emission monitoring and
reporting prescribed in the Clean Air
Act. Assistance can be obtained from the
EPA Regional Offices in relation to the
technical and procedural aspects of these
regulations.
Copies of documents referenced'in this
Preamble are available for public Inspec-
tion at the EPA Freedom of Information
Center, 401 M Street, S.W., Washington.
D.C. 20460. The Agency has not pre-
pared an environmental impact state-
ment for these regulations since they
HDIIAL IfOISTfR, VOL. 40, NO. 1M—MONDAY, OCTO1ER ft, 1«75
III-104
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RULES AND REGULATIONS
were proposed (September 11,1974 > prior
to the effective date for requiring volun-
tary environmental impnct statements
on EFA's regulatory actions (see 39 FR
16186, May 7, 1974).
The regulations set forth below are
promulgated under the authority of sec-
tions 110(F)-Uii> and 30H(O
Of the Cle«n Air Act, as amended 142
U.S.C. lB57c-5(aM2>-(iui. 1857g
(a) I and are effective November 5, 1975.
Dated: September 23, 1975.
JOHN QUARLES,
Acting Administrator.
REFERENCES
I. Jenkins, R E . Strategies and Air Stand-
ards Division. OAQPS, EPA. Memo to R L.
A)ax. Emission Standards and Engineering
Division. OAQPS. EPA. Emission Monitoring
Costs. February 27, 1975
2. Young, D. E., Control Programs Develop-
ment Division, OAQPS, EPA. Memo to E. J.
Llllls. Control Programs Development Di-
vision, OAQPS, EPA. Emission Source Data
for In-Slack Monitoring Regulations. June 4,
1975.
1. Section 51.1 is amended by adding
paragraphs (z), (aa), (bb), (cc), (dd),
and (ee) as follows:
§51.1 Definilion».
• • • • •
(z) "Emission standard" means a reg-
ulation (or portion thereof) setting forth
an allowable rate of emissions, level of
opacity, or prescribing equipment or fuel
specifications that result in control of
air pollution emissions.
(aa) "Capacity factor" means the
ratio of the average load on a machine or
equipment for the period of time consid-
ered to the capacity rating of the ma-
chine or equipment.
(bb) "Excess emissions" means emis-
sions of an air pollutant in excess of an
emission standard.
(cc) "Nitric acid plant" means any fa-
cility producing nitric acid 30 to 70 per-
cent in strength by either the pressure or
atmospheric pressure process.
(dd) "Sulfuric acid plant" means any
facility producing sulfuric acid by the
contact process by burning elemental suit
fur, alkylation acid, hydrogen sulflde, or
acid sludge, but does not include facili-
ties where conversion to sulfuric acid is
utilized primarily as a means of prevent-
ing emissions to the atmosphere of sul-
fur dioxide or other sulfur compounds.
(ee) "Fossil fuel-fired steam gener-
ator" means a furnace or boiler used in
the process of burning fossil fuel for the
primary purpose of producing steam by
heat transfer.
2. Section 51.19 is amended by adding
paragraph (e> as follows:
| SI.19 Source ourvrillaiirr.
Legally enforceable procedures to
require stationary sources subject to
emission standards as part of an appli-
cable plan to install, calibrate, maintain,
wul operate equipment for continuously
monitoring and recording emissions; and
to provide other information as specified
to Appendix P of this part.
(1) Such procedures shall identify the
types of sources, by source category and
capacity, that must install such instru-
ments, and shall identify for each source
category the pollutants which must be
monitored.
(2) Such procedures shall, as a mini-
mum, require the types of sources set
forth in Appendix P of this part (as such
appendix may be amended from time to
time) to meet the applicable require-
ments set forth therein.
(3) Such procedures shall contain pro-
visions which require the owner or op-
erator of each source subject to continu-
ous emission monitoring and recording
requirements to maintain a file of all
pertinent information. Such information
shall include emission measurements,
continuous monitoring system perform-
ance testing measurements, performance
evaluations, calibration checks, and ad-
justments and maintenance performed
on such monitoring systems and other re-
ports and records required by Appendix
P of this Part for at least two years fol-
lowing the date of such measurements or
maintenance.
(4) Such procedures shall require the
source owner or operator to submit in-
formation relating to emissions and
operation of the emission monitors to the
State to the extent described in Appendix
P as frequently or more frequently as
described therein.
(5) Such procedures shall provide that
sources subject to the requirements of
851.l9(e>(2> of this section shall have
installed all necessary equipment and
shall have begun monitoring and record-
ing within 18 months of (1) the approval
of a State plan requiring monitoring for
that source or (2) promulgation by the
Agency of monitoring requirements for
that source. However, sources that have
ma^e good faith efforts to purchase, in-
stall, and begin the monitoring and re-
cording of emission data but who have
been unable to complete such installa-
tion within the time period provided may
be given reasonable extensions of time as
deemed appropriate by the State.
(6 > States shall submit revisions to the
applicable plan which implement the
provisions of this section by October 6,
1976.
3. In Part 51. Appendix P is added as
follows:
• • • • *
APPENDIX P—MINIMUM EMISSION MONITORING
REQUIREMENTS
1.0 Purpose. This Appendix P sets forth
the minimum requirements for continuous
emission monitoring and recording that each
State Implementation Plan must Include In
order to be approved under the provisions of
40 CFR 51.10(e). These requirements Include
the source categories to be affected: emission
monitoring, recording, and reporting re-
quirements Jor these sources: performance
specifications for accuracy, reliability, and
durability of acceptable monitoring systems.
and techniques to convert emission dnta to
units of the applicable State emission stand-
ard. Such data must be reported to the State
as an Indication of whether proper mainte-
nance and operating procedures arc befog
utilized by source operators to maintain
emission levels at or below emission stand-
ards. Such data may be used directly or in-
directly for compliance determination or any
other purpose deemed appropriate by the
State Though the monitoring requirements
are specified In detail, States are given some
flexibility to resolve difficulties that may
arise during the Implementation of these
regulations.
1.1 Applicability.
The State plan shall require the owner or
operator of nn emission source In a category
listed In this Appendix to: (1) Install, cali-
brate, operate, and maintain all monitoring
equipment necessary for continuously moni-
toring the pollutants specified In this Ap-
pendix for the applicable source category;
and (2) complete the Installation and per-
formance tests of such equipment and begin
monitoring and recording within 18 months
of plan approval or promulgation. The source
categories and the respective monitoring re-
quirements are listed below.
1.1.1 Fossil fuel-Tired steam generators, as
specified in paragraph 2.1 of this appendix,
shall be monitored for opacity, nitrogen
oxides emissions, sulfur dioxide emissions,
and oxygen or carbon dioxide.
1.1.2 Fluid bed catalytic cracking unit
catalyst regenerators, as specified In para-
graph 2.4 of this appendix, shall be moni-
tored for opacity.
1.1.3 Sulfuric acid plants, as specified In
paragraph 2.3 of this appendix, shall be
monitored for sulfur dioxide emissions.
1.1.4 Nitric acid plants, as specified In
paragraph 2.2 of this appendix, shall be
monitored for nitrogen oxides emissions.
1.2 Exemptions.
The States may Include provisions within
their regulations to grant exemptions from
the monitoring requirements of paragraph
1.1 of this appendix for any source which Is:
1.2.1 subject to a new source performance
standard promulgated In 40 CFR Part 60
pursuant to Section 111 of the Clean Air
Act: or
1.2.2 not subject to an applicable emission
standard of an approved plan; or
1.2.3 scheduled for retirement within 5
years after Inclusion of monitoring require-
ments for the source In Appendix P. provided
that adequate evidence and guarantees are
provided that clearly show that the source
will cease operations prior to such date.
1.3 Extensions.
States may allow reasonable extensions of
the time provided for Installation of monitors
for facilities unable to meet the prescribed
tlmeframe (I.e., 18 months from plan ap-
proval or promulgation) provided the owner
or operator of such facility demonstrates that
good faith efforts have been made to obtain
and Install such devices within such pre-
scribed tlmeframe.
1.4 Monitoring System Mo//unrtion.
The State plan may provide a temporary
exemption from the monitoring and report-
ing requirements of this appendix during any
period of monitoring system malfunction.
provided that the source owner or operator
shows, to tho satisfaction of the State, that
the malfunction was unavoidable and Is
being repaired as expedltlously as practicable.
2.0 Minimum Monitoring Requirement.
States must, as a minimum, require the
sources listed In paragraph 1.1 of this appen-
dix to meet the following basic requirements
2.1 Fossil furl-ftred steam generators.
Each fossil fuel-fired (team generator, ex-
cept as provided In the following subpara-
graphs, with an annual average capacity fac-
tor of greater than 30 percent, as reported to
the Federal Power Commission for calendar
year 1074. or as otherwise demonstrated to
tho State by the owner or operator, shall con-
form with the following monitoring require-
ments when such facility Is subject to an
emission standard of an applicable plan for
the pollutant In question.
KDKRAL HIOISTH, VOL. 40, NO. 194—MONDAY, OCTOIER *. If75
III-105
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RULES AND REGULATIONS
2 l.l A continuous monitoring system for
the measurement of opacity which meets the
performance specifications of paragraph
3.1.1 of this appendix ahull be. Installed, cali-
brated, maintained, and operated In accord-
ance with the procedure* of this appendix bj
the owner or operator of any such itenm
generator of greater than 250 million BTU
per hour heat Input except where:
3 I.I.I taaeoui fuel Is the only fuel burned,
cr
9.1.1 2 oil or a mixture of gas and oil are
the only fuels burned and the source Is able
to comply with the applicable paniculate
matter and opacity regulations without utili-
zation of paniculate matter collection
equipment, and where the source hns never
been found, through any administrative or
Judicial proceedings, to be In violation of any
visible emission standard of the applicable
plan.
2.1.2 A continuous monitoring system for
the measurement of sulfur dioxide which
meets the performance specifications of para-
graph 313 of this appendix shall be Installed,
calibrated, maintained, and operated on any
fossil fuel -fired sieam generator of greater
than 250 million BTU per hour heat Input
which has Installed sulfur dioxide pollutant
control equipment.
213. A continuous monitoring system for
the measurement of nitrogen oxides which
meets the performance specification of para-
graph 31 2 of this appendix shall be Installed.
calibrated, maintained, and operated on fos-
sil fuel-fired steam generators of greater
than 1000 million BTU per hour heat Input
when such facility Is located In an Air Qual-
ity Control Region where the Administrator
has specifically determined that a control
strategy for nitrogen dioxide Is necessary to
attain the national standards, unless the
source owner or operator demonstrates dur-
ing source compliance tests as required by
the State that such a source emits nitrogen
oxides at levels 30 percent or more below the
•mission standard within the applicable
plan.
2.1.4 A continuous monitoring system for
the measurement of the percent oxygen or
carbon dioxide which meets the perform-
ance specifications of paragraphs 314 or
3.1 5 of this appendix shall be Installed, cali-
brated, operated, and maintained on fossil
fuel-fired steam generators where measure-
ments of oxygen or carbon dioxide In the flue
g«s are required to convert either sulfur di-
oxide or nitrogen oxides continuous emis-
sion monitoring data, or both, to units of
the emission standard within the applica-
ble plan.
2.2 Nitric arid plants.
Each nitric acid plant of greater than 300
tons per day production capacity, the pro-
duction capacity being expressed as 100 per-
cent acid, located In an Air Quality Control
Region where the Administrator has specif-
ically determined that a control strategy for
nitrogen dioxide Is necessary to attain the
national standard shall Install, calibrate,
maintain, and operate a continuous moni-
toring system for the measurement of nitro-
gen oxides which meets the performance
specifications of paragraph 3.12 for each
nitric acid producing facility within such
plant.
3.3 Snlfuric acid plants
Each Sulfurlc acid plant of greater than
300 tons per day production capacity, the
production being expressed as 100 percent
•eld. shall Install, calibrate, maintain and
operate a continuous monitoring system for
the measurement of sulfur dioxide which
meets the performance specifications of 3 1.3
for each sulfurlc acid producing facility
within such plant.
2.4 Fluid bed catalytic cracking unit cata-
lyit regtncrators at petroleum refineries.
Each catalyst regenerator for fluid bed
catalytic cracking units of greater than 20.-
000 barrels per day fresh feed capacity shall
Install, calibrate, maintain, and operate a
continuous monitoring system for the meas-
urement of opacity which meets the per-
formance specifications of 3.1.1.
30 Minimum specifications
All State plans shall require owners or op-
erators of monitoring equipment Installed
to comply with this Appendix, except as pro-
vided In paragraph 3.2, to demonstrate com-
pliance with the following performance spec-
ifications.
3.1 Performance specifications.
The performance specifications set forth
In Appendix B of Part 60 arc Incorporated
herein by reference, and shall be used by
States to determine acceptability of monitor-
Ing equipment Installed pursuant to this
Appendix except that (1) where reference Is
made to the "Administrator" In Appendix B.
Part 60, the term "State" should be Inserted
for the purpose of this Appendix (e.g., In
Performance Specification 1. 1.2, "... moni-
toring systems subject to approval by the
Administrator." should be Interpreted as.
"... monitoring systems subject to approval
by the Stair"), and (2) where reference Is
made to the "Reference Method" In Appendix
B. Part 60, the State may allow the use of
either the State approved reference method
or the Federally approved reference method
as published In Part 60 of this Chapter. The
Performance Specifications to be used with
each type of monitoring system are listed
below.
3.1.1 Continuous monitoring systems for
measuring opacity shall comply with Per-
formance Specification 1.
31.2 Continuous monitoring systems for
measuring nitrogen oxides shall comply with
Performance Specification 2.
3.1.3 Continuous monitoring systems (or
measuring sulfur dioxide shall comply with
Performance Specification 2.
3.1.4 Continuous monitoring systems for
measuring oxygen sha'll comply with Per-
formance Specification 3.
3.1.5 Continuous monitoring systems for
measuring carbon dioxide shall comply with
Performance Specification 3.
3.2 Exemptions.
Any source which has purchased an emis-
sion monitoring system(s) prior to Septem-
ber 11, 1974, may be exempt from meeting
such test procedures prescribed In Appendix
B of Part 60 for a period not to exceed five
years from plan approval or promulgation.
3.3 Calibration Gases.
For nitrogen oxides monitoring systems In-
stalled on fossil fuel-fired steam generators
the pollutant gas used to prepare calibration
gas mixtures (Section 21, Performance Spec-
ification 2, Appendix B, Part 60) shall be
nitric oxide (NO). For nitrogen oxides mon-
itoring systems. Installed on nitric acid plants
the pollutant gas used to prepare calibration
gas mixtures (Section 2.1, Performance Spec-
ification 2, Appendix B, Part 60 of this Chap-
ter) shall be nitrogen dioxide (NO,). These
gases shall also be used for dally checks under
paragraph 3.7 of this appendix as applicable.
For sulfur dioxide monitoring systems In-
stalled on fossil fuel-fired steam generators
or sulfurlc acid plants the pollutant gas used
to prepare calibration gas mixtures (Section
2.1. Performance Specification 2. Appendix B.
Part 60 of this Chapter) shall be sulfur di-
oxide (SO,) Span and zero gases should be
traceable to Natlon.il Bureau of Standards
reference gnses whenever these reference
gases are available. Every six months from
date of manufacture, span and zero gases
shall be reanalyzed by conducting triplicate
analyses using the reference methods In Ap-
pendix A. Part 60 of this chapter as follows:
for sulfur dioxide, use Reference Method 6:
for nitrogen oxides, use Reference Method 7;
and for carbon dioxide or oxygen, use Ref-
erence Method 3 The gases may b; analyzed
at less frequent Intervals If longer shelf lives
are guaranteed by the manufacturer.
34 Cycling times
Cycling times Include the total time a
monitoring system require* to sample.
analyze and record an emission measurement
3.4.1 Continuous monitoring systems for
measuring opacity shall complete a mini-
mum of one cycle of operation (sampling.
analyzing, and data recording) for each suc-
cessive 10-second period
3.42 Continuous monitoring systems for
measuring oxides of nitrogen, carbon diox-
ide, oxygen, or sulfur dioxide shall complete
a minimum of one cycle of operation (sam-
pling, analyzing, and data recording) for
each successive 15-mlnuU period.
3.5 Monitor location.
State plans shall require all continuous
monitoring systems or monitoring devices to
be installed such that representative meas-
urements of emissions or process parameters
(I.e., oxygen, or carbon dioxide) from the af-
fected facility are obtained. Additional guid-
ance for location of continuous monitoring
systems to obtain representative samples are
contained In the applicable Performance
Specifications of Appendix B of Part 60 of
this Chapter.
3.6 Combined effluents
When the effluents from two or more af-
fected facilities of similar design and operat-
ing characteristics are combined before being
released to the atmosphere, the State plan
may allow monitoring systems to be Installed
on the combined effluent. When the affected
facilities are not of similar design and operat-
ing characteristics, or when the effluent from
one affected facility Is released to the atmos-
phere through more than one point, the State
should establish alternate procedures to Im-
plement the Intent of these requirements.
3.7 Zero and dri/t.
State plans shall require owners or opera-
tors of all continuous monitoring systems
Installed In accordance with the require-
ments of this Appendix to record the zero and
spun drift In accordance with the method
prescribed by the manufacturer of such In-
strument*; to subject the Instruments to the
manufacturer's recommended zero and span
check at least once dally unless the manu-
facturer has recommended adjustments at
shorter Intervals. In which case such recom-
mendations shall be followed: to adjust the
zero and span whenever the 24-hour zero
drift or 24-hour calibration drift limits of
the applicable performance specifications In
Appendix B of Part 60 are exceeded: and to
adjust continuous monitoring systems refer-
enced by paragraph 3.2 of this Appendix
whenever the 24-hour zero drift or 24-hour
calibration drift exceed 10 percent of the
emission standard.
3.8 Span.
Instrument span should be approximately
200 per cent of the expected Instrument data
display output corresponding to the emission
standard for the source.
3.9 Xlfernafii'c procedure! and require-
ments
In cases where States wish to utilize differ-
ent, but equivalent, procedures and require-
ments for continuous monitoring systems.
the State plan must provide a description of
Riich alternative proccduers for approval by
the Administrator. Some examples of'Situa-
tions thnt may require alternatives follow:
3.9.1 Alternative monitoring requirements
to accommodate continuous monitoring sys-
tems thnt require corrections for stack mois-
ture conditions (e.g., an Instrument measur-
ing it) earn generator BO emissions on a wet
basis could be used with an Instrument mea-
suring oxygen concentration on a dry bails
If acceptable methods of measuring stack
moisture conditions are used to allow ac-
FIDMAL IIOIITH, VOl. 40, NO. 1*4—MONDAY, OCTOM* *, 1*75
III-106
-------
RULES AND REGULATIONS
curate adjustment of the measured SO. con-
centration to dry basis )
39.2 Alternative locations for Installing
continuous monitoring siMem* or nionltor-
Jng drUces when Hie owner or operator run
demonstrate thnt insinuation at alternative
locations will enable accurate and represent-
ative measurements.
3.9.3 Alternative procedures for perform-
ing calibration checks te.g . some Instruments
may demonstrate superior drift characteris-
tics that require checking at less frequent
Intervals).
3.94 Alternative monitoring requirements
when the effluent from one affected facility or
the combined effluent from two or more
Identical affected facilities Is released to the
atmosphere through more than one point
(e.g.. an extractive, gaseous monitoring sys-
tem used at several points may be approved
II the procedures recommended arc suitable
for generating accurate emission averages).
3.9.5 Alternative continuous monitoring
systems that do not meet the spectral re-
sponse requirements In Performance Speci-
fication 1. Appendix B of Part 60, but ade-
quately demonstrate a definite and consistent
relationship between their measurements
and the opacity measurements of a system
complying with the requirements In Per-
formance Specification 1 The State mny re-
quire that such demonstration be performed
for each affected facility.
4 0 Minfmr/TJi data requirements.
The following paragraphs set forth the
minimum dnta reporting requirements neces-
sary to comply with 5 51 19(e) (3) and (4).
4 1 The State plan shall require owners
or operators of facilities required to Install
continuous monitoring systems to submit a
written report of excess emissions for each
calendar quarter and the nature and cause of
the excess emissions. If known The averaging
period used for data reporting should be
established by the State to correspond to the
averaging period specified In the emission
test method used to determine compliance
with an emission standard for the pollutant'
source category In question. The required re-
port shall Include, as a minimum, the data
stipulated In this Appendix.
4.2 For opacity measurements, the sum-
mary shall consist of the magnitude In actual
percent opacity of all one-minute (or such
other time period deemed appropriate by the
State) averages of opacity greater than the
opacity standard In the applicable plan lor
each hour of operation of the facility. Aver-
age values may be obtained by Integration
over the averaging period or by arithmeti-
cally averaging a minimum of four equally
spaced. Instantaneous opacity measurements
per minute. Any time period exempted shall
be considered before determining the excess
averages of opacity (e.g.. whenever a regu-
lation allows two minutes of opacity meas-
urements In excess of the standard, the State
shall require the source to report all opacity
averages. In any one hour. In excess of the
standard, minus the two-minute exemp-
tion). If more than one opacity standard
applies, excess emissions data must be sub-
mitted In relation to all such standards
4.3 For gaseous measurements the sum-
mary shall consist of emission averages. In
the units of the applicable standard, for each
averaging period during which the appli-
cable standard was exceeded.
4.4 The' date and time Identifying each
period during which the continuous moni-
toring system was Inoperative, except for
zero and span checks, and the nature of
system repairs or adjustments shall be re-
ported. The State may require proof of con-
tinuous monitoring system performance
whenever system repairs or adjustments have
been made.
4.5 When no excess emissions have oc-
curred and the continuous monitoring sjs-
lem(s) have noi hern Inoperative, repaired.'
or adjusted such Information shall be In-
cluded In the report
4 6 The State plan shall require owners or
operators of affected facilities to maintain
n file of all Information reported In the quar-
terly summaries, and all other dnta collected
either by the continuous monitoring system
or as necessary to convert monitoring data
to the units of the applicable standard for
a minimum of two years from the date of
collection of such data or submission of
such summaries
6.0 Data Rcdtirtion
The State plan shall require owners or
operators of affected facilities to use the
following procedures for converting moni-
toring data to units of the standard where
necessary.
5.1 For fossil fuel-fired steam generators
the following procedures shall be used to
convert gaseous emission monitoring dnta In
parts per million to g'million cal lib'million
BTU) where necessary:
5.1.1 When the owner or operator of a
fossil fuel-fired steam generator elects under
subparagraph 2 1.4 of this Appendix to meas-
ure oxygen In the flue gases, the measure-
ments of the pollutant concentration and
oxygen concentration shall each be on a dry
basis and the following conversion procedure
used:
20.0
5.1.2 When the owner or operator elects
under subparagraph 2.14 of this Appendix
to measure carbon dioxide In the flue gases.
the measurement of the pollutant concen-
tration and the carbon dioxide concentration
shall each be on a consistent basis (wet or
dry) and the following conversion procedure
used:
K-CF.' 10f)
5.1.3 The values used In the equations un-
der paragraph 51 are derived as follows:
E = pollutant emission, g/milllon
cal (Ib/mllllon BTU).
C = pollutant concentration, g'
dscm Ub/dscf). determined by
multiplying the average concen-
tration (ppm) for each hourly
period by 4.16viO-r' M g'dscm
per ppm (2.64 *• 10-" M Ib/dscf
per ppm) where M = pollutant
molecular weight, g/'g-mole (Ib/
Ib-mole). M = 64 for sulfur di-
oxide and 46 for oxides of nltro-
gon.
7,O., r/rCO. = Oxygen or carbon dioxide vol-
ume (expressed as percent) de-
termined with equipment spec-
ified under paragraph 4.1.4 of
this appendix.
F, Frrra factor representing a ratio of
the volume of dry flue gases
generated to the calorific value
of the fuel combusted (F), and
a factor representing a ratio of
the volume of carbon dioxide
generated to the calorific value
of the fuel combusted (F.) re-
spectively. Values of F and F.
are given In $ 60.45(f) of Part
60. as applicable.
8.2 For sulfurlc acid plants the owner or
operator shall;
52.1 establish n conversion factor three
times dally according to the procedures to
I 60 84(b) of this chapter:
5.2.2 multiply the conversion factor by the
average sulfur dioxide concentration In the
flue gases to obtain average sulfur dioxide
emissions In Kg/metric ton (Ib/short ton):
and
62 3 report the average sulfur dioxide
emission for each averaging period In excess
of the applicable emission standard In the
quarterly summary.
5.3 For nitric acid plants the owner or
operator shall:
5.3.1 establish a conversion factor accord-
ing to the procedures of I60.73(b) of this
chapter.
5 3.2 multiply the conversion factor by the
average nitrogen oxides concentration In the
flue gases to obtain the nitrogen oxides emis-
sions In the units of the applicable standard;
5 3.3 report the average nitrogen oxides
emission for each averaging period in excess
of the applicable emission standard. In the
quarterly summary.
5.4 Any State may allow data reporting
or reduction procedures varying from those
set forth In this Appendix If the owner or
operator of a source shows to the satisfaction
of the State that his procedures are at least
as accurate as those In this Appendix. Such
procedures may Include but are not limited
to. the following:
5.4.1 Alternative procedures for computing
emission averages that do not require nte-
grntlon of data (e.g.. some facilities may (em-
oastrate that the variability of their t mis-
sions Is sufficiently small to allow accurat: re-
duction of data based upon computing aver-
ages from equally spaced data points over the
averaging period).
5 4.2 Alternative methods of converting po!--
lutant concentration measurements to the
units of the emission standards.
60 Special Consideration.
The State plan may provide for approval, on
a case-by-case basis, of alternative monitor-
Ing requirements different from the provi-
sions of Parts l through 5 of this Appendix If
the provisions of this Appendix (I.e.. the In-
stallation of a continuous emission monitor-
ing system) cannot be Implemented by a
source due to physical plant limitations or
extreme economic reasons. To make use of
this provision. States must Include In their
plan specific criteria for determining those
physical limitations or extreme economic.
situations to be considered by the State. In
such cases, when the State exempts any
source subject to this Appendix by use of this
provision from Installing continuous emis-
sion monitoring systems, the State shall set
forth alternative emission monitoring and
reporting requirements (e.g., periodic manual
stack tests) to satisfy the Intent of these
regulations. Examples of such special coses
Include, but are not limited to, the following:
6.1 Alternative monitoring requirements
mny be prescribed when Installation of a con-
tinuous monitoring system or monitoring de-
vice specified by this Appendix would not pro-
vide accurate determinations of emissions
(e.g., condensed, uncomblned water vapor
may prevent an accurate determination of
opacity using commercially available con-
tinuous monitoring systems).
6.2 Alternative monitoring requirements
may be prescribed when the affected facility
Is Infrequently operated (e.g.. some affected
facilities may operate less than one month
per year).
6.3 Alternative monitoring requirements
may be prescribed when the State determines
that the requirements of this Appendix would
Impose an extreme economic burden on the
source owner or operator.
6.4 Alternative monitoring requirements
may be prescribed when the State determines
that monitoring systems prescribed by this
Appendix cannot be Installed due to physical
limitations at the facility.
|FK Doc 75-26566 Filed 10-3-76:8:45 am]
KDMAl REGISTER. VOL 40, NO If4—MONDAY. OCTOIER 6. If75
III-107
-------
ENVIRONMENTAL
PROTECTION
AGENCY
NATIONAL EMISSION
STANDARDS FOR
HAZARDOUS AIR
POLLUTANTS
-------
Subpart F—National Emission Standard
for Vinyl CMorMe
161.60 Applicability.
(a) This subpart applies to plants
which produce:
(1) Ethylene dlchlortde by reaction of
oxygen ftnd hydrogen chloride wttb
ethytene,
(1) Vtayl ohlortda by any proem
and/or
' (3) One or more potmen containing
any fraction of polymerized vinyl chlo-
ride.
Cb) This subpart does not apply to
* equipment used in research and develop-
ment If the reactor used to polymerize
the vinyl chloride processed in the equip-
ment has a capacity of no more than
0.19m1 (50 gal).
(c) Sections of this subpart other than
(! 61.61; 61.64 (a)(l), (b), (c).and (d>;
61.67; 61.68; 61.69; 61.70; and 61 71 do not
apply to equipment used in research and
development if the reactor used to po-
lymerize the vinyl chloride processed in
the equipment has a capacity of greater
than 0.19 m* (50 gal) and no more than
4.07m1 (1100 gal).
fi 61.61 Definition*.
Terms used In this subpart are defined
In the Act, in subpart A of this part, or
in this section as follows:
(a) "Ethylene dlchloride plant" in-
cludes any plant which produces ethyl-
ene dlchloride by reaction of oxygen and
hydrogen chloride with ethylene.
(b) "Vinyl chloride plant" Includes
any plant which produces vinyl chloride
by any process.
(c) "Polyvlnyl chloride plant" Includes
any plant where vinyl chloride alone or
in combination with other materials is
polymerized.
(d) "Slip gauge" means a gauge which
has a probe that moves through the gas/
liquid Interface in a storage or transfer
vessel and Indicates the level of vinyl
chloride In the vessel by the physical
state of the material the gauge dis-
charges.
(e) "Type of resin" means the broad
classification of resin referring to the
basic manufacturing process for produc-
ing that resin, Including, but not limited
to, the suspension, dispersion, latex, bulk,
and solution processes.
(f) "Grade of resin" means the sub-
division of resin classification which de-
scribes it as a unique resin, ie., the most
exact description of a resin with no fur-
ther subdivision.
(g) "Dispersion resin" means a resin
manufactured in such away as to form
fluid dispersions when dispersed in a
plastlcizer or plastlclzer/dlluent mix-
tures.
(h) "Latex resin" means a resin which
is produced by a polymerization process
which Initiates from free radical catalyst
sites and is sold undrled.
(1) "Bulk resin' 'means a resin which
to produced by a polymerization process
in which no water la used.
(J) "Inprocess wastewater" means any
water which, during manufacturing or
processing, comes into direct contact
with vinyl chloride or polyvlnyl chloride
or results from the production or use of
any raw material, intermediate product,
finished product, by-product, or waste
product containing vinyl chloride or
polyvlnyl chloride but which has not
been discharged to a wastewater treat-
ment process or discharged untreated at
wastewater.
(k) "Wastewater treatment proceas*
Includes any process which modifies
characteristics such as BOD, COD. T88,
and pH, usually for the purpose of meet-
ing effluent guidelines and standards; it
does not include any process the purpose
of which is to remove vinyl chloride from
water to meet requirements of this
subpart.
(1) "In vinyl chloride service" means
that a piece of equipment contains or
contacts either a liquid that is at least
10 percent by weight vinyl chloride or a
gas that is at least 10 percent by volume
vinyl chloride.
(m) "Standard operating procedure"
means a formal written procedure offi-
cially adopted by the plant owner or
operator and available on a routine basis
to those persons responsible for carrying
out the procedure.
(n) "Run" means the net period of
time during which an emission sample is
collected.
(o) "Ethylene dlchloride purification"
includes any part of the process of ethyl-
ene dlchloride production which follows
ethylene dlchloride formation and in
which finished ethylene dlchloride is
produced.
(p) "Vinyl chloride purification" In-
cludes any part of the process of vinyl
chloride production which follows vinyl
chloride formation and In which finished
vinyl chloride Is produced.
(q) "Reactor" Includes any vessel in
which vinyl chloride Is partially or totally
polymerized Into polyvlnyl chloride.
(r) "Reactor opening loss" means the
emissions of vinyl chloride occurring
when a reactor is vented to the atmos-
phere for any purpose other than an
emergency relief discharge as defined In
!61.65(a).
(s) "Stripper" Includes any vessel in
which residual vinyl chloride is removed.
from polyvlnyl chloride resin, except
bulk resin, In the slurry form by the use
of heat and/or vacuum. In the case of
bulk resin,' stripper Includes any vessel
which is used to remove residual vinyl
chloride from polyvlnyl chloride resin
Immediately following the polymeriza-
tion step In the plant process flow.
(t) "Standard temperature" means a
temperature of 20° C <69° P).
(u) "Standard pressure" means a
pressure of 760 mm of Hg (29.92 in. of
Hg).
g 61.62 Emiuion rtandard for ethylene
dichloride plant*.
(a) Ethylene dlchloride purification:
The concentration of vinyl chloride in
all exhaust gases discharged to the at-
mosphere from any equipment used in
ethylene dlchloride purification is not
to exceed 10 ppm, except as provided in
|61.ft5(a). This requirement does not
apply to equipment that has been opened,
is out of operation, and met the require-
ment in | 61.65(b) (6) (1) before being
opened.
(b) Oxychlortnatlon reactor: Except
as provided in |61.65(a), emissions of
vinyl chloride to the atmosphere from
each oxychtorinatlon reactor are not to
exceed 0.2 g/kg (0.0002 Ib/lb) of the 100
percent ethylene dichloride product froth
the oxychlorlnation process.
161.63 Emlwioa •Undard for
chloride plant*.
An owner or operator of a vinyl chlo-
ride plant shall comply with the require-
ments of this section and 161.65.
(a) Vinyl chloride formation and puri-
fication: The concentration of vinyl
chloride in all exhaust gases discharged
to the atmosphere from any equipment
used in vinyl chloride formation and/or
purification is not to exceed 10 ppm, ex-
cept as provided in 161.6S(a). This re-
quirement does not apply to equipment
that has been opened, is out of operation,
and met the requirement in I 61,iiS(b)
(6) (i) before being opened.
§ 61.64 Emission standard for polyvinyl
chloride plants.
An owner or operator of a polyvlnyl
chloride plant shall comply with the re-
quirements of this section and J 61.65.
(a) Reactor: The following require-
ments apply to reactors:
(1) The concentration of vinyl chlo-
ride in all exhaust gases discharged to
the atmosphere from each reactor is not
to exceed 10 ppm, except as provided in
paragraph (a) (2) of this section and
}61.65 (a).
(2) The reactor opening loss from each
reactor is not to exceed 0.02 g vinyl
chloride/Kg (0.00002 Ib vinyl chloride/
Ib) of polyvlnyl chloride product, with
the product determined on a dry solids
basis. This requirement applies to any
vessel which is used as a reactor or as
both a reactor and a stripper. In the
bulk process, the product means the
gross product of prepolymerlzation and
postpolymerization.
(3) Manual vent valve discharge: Ex-
cept for an emergency manual vent valve
discharge, there is to be no discharge to
the atmosphere from any manual vent
valve on a polyvinyl chloride reactor in
vinyl chloride service. An emergency
manual vent valve discharge means a
' discharge to the atmosphere which could
not have been avoided by taking meas-
ures to prevent the discharge. Within 10
days of any discharge to the atmosphere
from any manual vent valve, the owner
or operator of the source from which the
discharge occurs shall submit to the Ad-
ministrator a report in writing contain-
ing information on the source, nature
and cause of the discharge, the date and
time of the discharge, the approximate
total vinyl chloride loss during the dis-
charge, the method used for determining
the vinyl chloride loss, the action that
was taken to prevent the discharge, and
measures adopted to prevent future dis-
charges.
III-108
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(b) Stripper: The concentration of
vinyl chloride in all exhauat gases dis-
charged to the atmosphere from each
•tripper is not to exceed 10 ppm, except
a* provided in |61.65(a). This require-
ment does not apply to equipment that
ha* been opened, is out of operation, and
met the requirement in | 61.66(b) (6) (1)
before being opened.
(c) Mixing, weighing, and holding
containers: The concentration of vinyl
chloride in all exhaust gases discharged
to the atmosphere from each mixing,
weighing, or holding container in vinyl
chloride service which precedes the
•tripper (or the reactor if the plant ba*>
no •tripper) in the plant process flow to
not to exceed 10 ppm, except as provided
In | 61.65(a). Thi* requirement doe* not
apply to equipment that ha* been
opened. Is out of operation, and met the
requirement in 161.65(1)) (6) (1) before
being opened.
(d) Monomer recovery system. The
concentration of vinyl chloride in all ex-
haust gases discharged to the atmos-
phere from each monomer recovery sys-
tem is not to exceed 10 ppm, except as
provided in f 61.65(a). This requirement
does not apply to equipment that has
been opened, is out of operation, and met
the requirement in I 61.65(b) (0) (1) be-
fore being opened.
(e) Sources following the stripper(s):
The following requirements apply to
emissions of vinyl chloride to the at-
mosphere from the combination of all
sources following the stripper (s) [or the
reactor(s) if the plant has no strip-
per(s)l In the plant process flow in-
cluding but not limited it/, centrifuges,
concentrators, blend tanks, filters,.dry-
ers, conveyor air discharges, baggers,
storage containers, and Inprocesa waste-
water:
(1) In polyvlnyl chloride plants using
stripping technology to control vinyl
chloride emissions, the weighted average
residual vinyl chloride concentration in
all grades of polyvlnyl chloride resin
processed through the stripping opera-
tion on each calendar day, measured
immediately after the stripping opera-
tion is completed, may not exceed:
(i) 2000 ppm for polyvlnyl chloride
dispersion resins, excluding latex resins;
(11) 400 ppm for all other polyvlnyl
chloride resins, including latex resins,
averaged separately for each type of res-
in; or
(2) In polyvlnyl chloride plants con-
trolling vinyl chloride emissions with
technology other than stripping or in
addition to stripping, emissions of vinyl
chloride to the atmosphere may not
exceed:
(1)2 g/kg (0.002 Ib/lb) product from
the stripper(s) tor reactor(s) if the
plant has no strlpper(s) 1 for dispersion
polyvlnyl chloride resins, excluding latex
resins, with the product determined on a
dry solids basis;
(11) 0.4 g/kg (0.0004 Ib/lb) product
from the strippers [or reactor(s) if the
plant has no stripper(*) ] for alf other
polyvlnyl chloride resins, including latex
resins, with the product determined on
a dry solids basis.
| 61.65 EmUclon iund>rd for nhrlrit*
dichloride, vinyl chloride mid poly-
vinyl chloride pUntt,
An owner or operator of an ethylene
dlchlorlde, vinyl chloride, and/or poly-
vlnyl chloride plant shall comply with
the requirement* of this section.
(a) Relief valve discharge: Except for
an emergency relief discharge, there la
to be no discharge to the atmosphere
from any relief valve on any equipment
in vinyl chloride service. An emergency
relief discharge means a discharge which
could not have been avoided by taking
measures to prevent the discharge. With-
in 10 days of any relief valve discharge,
the owner or operator of the source from
which the relief valve discharge occurs
•hall submit to the Administrator a re-
port in writing containing information
on the source, nature and cause of the
discharge, the date and time of the dis-
charge, the approximate total vinyl chlo-
ride loss during the discharge, the meth-
od used for determining the vinyl chlo-
ride loss, the action that was taken to
prevent the discharge, and measures
adopted to prevent future discharges.
(b) Fugitive emission sources:
(1) Loading and unloading lines:
Vinyl chloride emissions from loading
and unloading lines in vinyl chloride
service which are opened to the atmos-
phere after each loading or unloading op-
eration are to be minimized as follows:
(1) After each loading or unloading
operation and before opening a loading
or unloading line to the atmosphere, the
quantity of vinyl chloride in all parts of
each loading or unloading line that are
to be opened to the atmosphere is to be
reduced so that the parts combined con-
tain no greater than 0.0038 m* (0.13 ft")
of vinyl chloride, at standard tempera-
ture and pressure; and
(11) Any vinyl chloride removed from
a loading or unloading line in accord-
ance with paragraph (b)(l)(l) of this
section is to be ducted through a control
system from which the concentration of
vinyl chloride in the exhaust gases doe*
not exceed 10 ppm, or equivalent as pro-
vided In | 01.06.
(2) Slip gauges: During loading or un-
loading operations, the vinyl chloride
emissions from each slip gauge in vinyl
chloride service are to be minimized by
ducting any vinyl chloride discharged
from the slip gauge through a control
system from which the concentration of
vinyl chloride in the exhaust gases doe*
not exceed 10 ppm, or equivalent as pro-
vided in | 01.00.
(3) Leakage from pump, compressor,
and agitator seals:
(1) Rotating pumps: Vinyl chloride
emissions from seals on all rotating
pumps in vinyl chloride service are to be
minimise by Installing seallea* pump*,
pumps with double mechanical seals, or
equivalent a* provided in 161.00. If
double mechanical seal* are used, vinyl
chloride emission from the seals are to
be minimized by maintaining the pres-
sure between the two seals so that any
leak that occur* is Into the pump; by
ducting any vinyl chloride between the
two seal* through a control system from
which the concentration of vinyl chlo-
ride in the exhaust gases does not ex-
ceed 10 ppm; or equivalent as provided
in | 01.00.
(11) Reciprocating pumps: Vinyl chlo-
ride emissions from seals on all recipro-
cating pump* in vinyl chloride service
are to be minimized by installing double
outboard seal*, or equivalent as provided
hi 161.06. If double outboard seal* are
used, vinyl chloride emissions from the
•eal* are to be minimized by maintaining
the pressure between the two seals *o
that any leak that occur* 1* into the
pump; by ducting any vinyl chloride be-
tween the two *eal* through a control
system from which the concentration of
vinyl chloride in the exhauat gases does
not exceed 10 ppm; or equivalent a*
provided in I 01.66.
(ill) Rotating compressor: Vinyl
chloride emissions from seals on an ro-
tating compressors in vinyl chloride
service are to be minimized by installing
compressors with double mechanical
seals, or equivalent as provided In I 61.66.
If double mechanical seals are used, vinyl
chloride emissions from the seals are to
be minimized by maintaining the pres-
sure between the two seals so that-any
leak that occurs is into the compressor;
by ducting any vinyl chloride between
the two seals through a control system
from which the concentration of vinyl
chloride in the exhaust gases does not
exceed 10 ppm; or equivalent as provided
in I 61.66.
(iv) Reciprocating compressors: Vinyl
chloride emissions from seals on all re-
ciprocating compressors in vinyl chloride
service are to be minimized by Installing
double outboard seals, or equivalent as
provided in t 61.66. If double outboard
seals are used, vinyl chloride emissions
from the seals are to be minimized by
maintaining the pressure between the
two seals so that any leak that occur* 1*
into the compressor; by ducting any
vinyl chloride between the two seal*
through a control system from which the
concentration of vinyl chloride in the
exhaust gases does not* exceed 10 ppm;
or equivalent as provided in i 61.66.
(v) Agitator: VlnylTchlorlde emission*
from seals on all agitators In vinyl chlo-
ride service are to be minimized by in-
stalling agitators with-double mechani-
cal seals, or equivalent as provided in
f 61.66. If double mechanical seals are
used, vinyl chloride emissions from the
seals are to be minimized by maintaining
the pressure between the two seals so
that any leak that occurs is into the agi-
tated vessel; by ducting any vinyl chlo-
ride between the two seals through a
control system from which the concen-
tration of vinyl chloride in the exhaust
gases does not exceed 10 ppm; or equiva-
lent as provided In I 61.66.
(4) Leakage from relief valves: Vinyl
chloride emission* due to leakage from
each relief valve oh equipment in vinyl
chloride service are to be minimized by
installing a rupture disk between the
equipment and the relief valve, by con-
necting the relief valve discharge to a
process line or recovery system, or equiv-
alent as provided in I 61.66.
III-109
-------
(5> Manual venting of gases: Except
as provided In I 61.64 <3>, aU gases
which are manually vented from equip-
ment In vinyl chloride service are to b«
ducted through a control system from
which the concentration of vinyl chloride
in the exhaust gases does not exceed 10
ppm; or equivalent as provided in 5 61.66.
(6) Opening of equipment: Vinyl
chloride emissions from opening at
equipment (Including loading or unload*
ing lines that are not opened to the at-
mosphere after each loading or unload-
,lng operation) are to be minimized u
follows:
(1) Before opening any equipment for
any reason, the quantity of rlnyl ohlo-
.rlde is to be reduced so that the equip-
ment contains no more than 2.0 percent
by volume vinyl chloride or 0.0950 m' (25
gal) of vinyl chloride, whichever is
larger, at standard temperature and
pressure; and
(11) Any vinyl chloride removed from
the equipment In accordance with para-
graph (b) (6) (1) of this section is to-be
ducted through a control system from
which the concentration of vinyl chlo-
ride in the exhaust gases does not exceed
10 ppm. or equivalent as provided in
{ 61.66.
(7) Samples: Unused portions of sam-
ples containing at least 10 percent by
weight vinyl chloride are to be returned
to the process, and sampling techniques
are to be such that sample containers in
vinyl chloride service are purged Into a
closed process system.
(8) Leak detection and elimination:
Vinyl chloride emissions due to leaks
from equipment in vinyl chloride service
are to be minimized by Instituting and
Implementing a formal leak detection
and elimination program. The owner or
operator shall submit a description of
the program to the Administrator for
approval. The program is to be sub-
mitted within 45 days of the effective
date of these regulations, unless a waiver
of compliance is granted under {61.11.
If a waiver of compliance Is granted, the
program is to be submitted on a date
scheduled by the Administrator. Ap-
proval of a program will be granted by
the Administrator provided he finds:
(i) It Includes a reliable and accurate
vinyl chloride monitoring system for de-
tection of major leaks and identification
of the general area of the plant where a
leak is located. A vinyl chloride monitor-
Ing system means a device which obtains
air samples from one or more points on
a continuous sequential basis and ana-
lyzes the samples with gas chromatog-
raphy or, if the owner or operator as-
sumes that all hydrocarbons measured
are vinyl chloride, with infrared spectro-
photometry flame ion detection, or an
equivalent or alternative method.
(11) It includes a reliable and accurate
portable hydrocarbon detector to be used
routinely to find small leaks and to pin-
point the major leaks Indicated by th«
vinyl chloride monitoring system. A
portable hydrocarbon detector means a
device which measures hydrocarbons
with a sensitivity of at least 10 ppm
and is of such design and size that it can
be used to measure emissions from local-
ized points.
(Ill) It provides for an acceptable cali-
bration and maintenance schedule for
the vinyl chloride monitoring system and
portable hydrocarbon detector. For the
vinyl chloride monitoring system, a dally
span check is to be 'conducted with a
concentration of vinyl chloride equal to
the concentration defined as a leak ac-
cording to paragraph (b) (8) (vi) of this
section. The calibration is to be done
with either:
(A) A calibration gas mixture pre-
pared from the gases specified in sections
8.2.1 and 5.2.2 of Test Method 106 and
in accordance with section 7.1 of Test
Method 106, or
(B) A calibration gas cylinder stand-
ard containing the appropriate concen-
tration of vinyl chloride. The gas com-
position of the calibration gas cylinder
standard Is to have been certified by the
manufacturer. The manufacturer must
have recommended a maximum shelf life
for each cylinder so that the concentra-
tion does not change greater than ±5
percent from the certified value. The date
of gas cylinder preparation, certified
vinyl chloride concentration and recom-
mended maximum shelf life must have
been affixed to the cylinder before ship-
ment from the manufacturer to the
buyer. If a gas chromatotrraph Is used as
the vinyl chloride monitoring system,
these gas mixtures may be directly used
to prepare a chromatograph calibration
curve as described in section 7.3 of Test
Method 106. The requirements in sec-
tion 5.2.3.1 and 5.2.3.2 of Test Method
106 for certification of cylinder stand-
ards and for establishment and verifica-
tion of calibration standards are to be
followed.
(Sees. 112 and 801 (»), CI«*n Air Act (42
U.S.C. 18670-7 and 18S7g(»)).)
(iv) The location and number of points
to be monitored and the frequency- of
monitoring provided for In the program
are acceptable when they are compared
with the number of pieces of equipment
in vinyl chloride service and the size and
physical layout of the plant.
(v) It contains an acceptable plan of
action to be taken when a leak is de-
tected.
(vi) It contains a definition of leak
which is acceptable when compared with
the background concentrations of vinyl
chloride in the areas of the plant to be
monitored by the vinyl chloride monitor-
ing system. Measurements of background
concentrations of vinyl chloride In the
areas of the plant to be monitored by the
vinyl chloride monitoring system are to
be included with the description of the
program. The definition of leak for a
given plant may vary among the differ-
ent areas within the plant and is also to
change over time as background con-
centrations in the plant are reduced.
(9) Inprocess wastewater: Vinyl chlo-
ride emissions to the atmosphere from
inprocess wastewater are to be reduced
as follows:
(1) The concentration of vinyl chlo-
ride in each Inprocess wastewater stream
containing greater than 10 ppm vinyl
chloride measured immediately as tt
leaves a piece of equipment and before
being mixed with any other Inprocess
wastewater stream is to be reduced to no
more than 10 ppm by weight before being
mixed with any other Inprocess wastewa-
ter stream which contains less than 10
ppm vinyl chloride: before being exposed
to the atmosphere, before being dis-
charged to a wastewater treatment J)roc-
ess; or before being discharged untreated
as a wastewater. This paragraph does
apply to water which is used to displace
vinyl chloride from equipment before it
is opened to the atmosphere in accord-
ance with 561.64(a)(2) or paragraph
(b) (6) of this section, but does not apply
to water which is used to wash out equip-
ment after the equipment has already
been opened to the atmosphere in ac-
cordance with i 61.64(a) (2) or para-
graph (b) (6) of this section.
(11) Any vinyl chloride removed from
the inprocess wastewater in accordance
with paragraph (b) (9) (1) of this section
is to be ducted through a control system
from which the concentration of Inyl
chloride in the exhaust gases doe? not
exceed 10 ppm, or equivalent as prov 'ded
in | 61.66.
(c) The requirements in paragrr >hs
(b)(l), (b)(2), (b)(5), (b)(6). (bK7>
and (b) (8) of this section are to be in-
corporated into a standard operating
procedure, anr made available upon re-
quest for inspection by the Administra-
tor. The standard operating procedure is
to Include provisions for measuring the
vinyl chloride in equipment fe4.75 m*
(1.250 gal) in volume lor whirli nn emis-
sion limit is prescribed In I 61.65 Ob) (6)
(i) prior to opening the equipment and
using Test Method 106, a portable hydro-
carbon detector, or an equivalent or al-
ternative method. The method of meas-
urement is to meet the requirements in
I 61.87(g) (5) (1) (A) or (g)((5)(l)(B).
§ 61.66 Equivalent equipment and pro-
cedures.
Upon written application from an own-
er or operator, the Administrator may
approve use of equipment or procedures
which have been demonstrated to his
satisfaction to be equivalent' In terms of
reducing vinyl chloride emissions to the
atmosphere to those prescribed for com-
pliance with a specific paragraph of this
subpart. For an existing source, any re-
quest for using an equivalent method as
the initial measure of control is to be
submitted to the Administrator within
30 days of the effective date. For a new
source, any request for using an equiva-
lent method is to be submitted to the
Administrator with the application for
approval of construction or modification
required by | 01.07.
§ 61.67 EmlMion test*.
(a) Unless a waiver of emission testing
is obtained under I 61.13, the owner or
operator of a source to which tills sub-
III-110
-------
part applies shall teat emission* from
the source,
(1) Within 90 days of the effective date
In the case of an existing source or a
new source which has an Initial startup
date preceding the effective date, or
(2) Within 90 days of startup In the
case of a new source, Initial startup of
which occurs after the effective date.
(b) The owner or operator shall pro-
vide the Administrator at least 30 days
prior notice of an emission test to afford
the Administrator the opportunity to
have an observer present during the test.
(c) Any emission test is to be con-
ducted while the equipment being tested
Is operating at the maximum production
rate at which the equipment will be op-
erated and under other relevant condi-
tions as may be specified by the Adminis-
trator based on representative perform-
ance of the source.
(d) [Reserved]
(2>, <5>,
(b) (6) (11), or (b)(9)(il>.
(1) For each run, one sample Is to be
collected. The sampling site Is to be at
least two stack or duct diameters down-
stream and one half diameter upstream
from any flow disturbance such as a
bend, expansion, contraction, or visible
flame. For a rectangular cross section an
equivalent diameter is to be determined
from the following equation:
. , t j. , o (length) (width)
equivalent diameter « 2 ^— ,.' ...rr--
M length + width
The sampling point In the duct Is to
be at the centrold of the cross section.
The sample Is to be extracted at a rate
proportional to the gas velocity at the
sampling point. The sample Is to be
taken over a minimum of one hour, and
Is to contain a minimum volume of BO
liters corrected to standard conditions.
(11) Each emission test is to consist of
three runs. For the purpose of determin-
ing emissions, the average of results of
all runs Is to apply. The average Is to be
computed on a time weighted basis.
(Ill) For gas streams containing more
than 10 percent oxygen the concentra-
tion of vinyl chloride as determined by
Test Method 106 Is to be corrected to 10
percent oxygen (dry basis) for determi-
nation of emissions by using the follow-
ing equation:
C» (•orr««>d)a*
10.0
20.9—percent O»
where:
Ci><..,rre«.d> = The concentration of vinyl
chloride in the exhaust gases, corrected
to 10-percent oxygen.
C6=The concentration of vinyl chloride
as measured by Test Method 106.
20.9= Percent oxygen in the ambient
air at standard conditions.
10.9 = Percent oxygen in the ambient
air at standard conditions, minus the
10.0-percent oxygen to which the
correction is being made.
Percent O»= Percent oxygen in the
exhaust gas as measured by Refer-
ence Method 3 in Appendix A of
Part 60 of this chapter.
(iv) For those emission sources where
the emission limit Is prescribed In terms
of mass rather than concentration, mass
emissions in kg/100 kg product are to be
determined by using the following equa-
tion:
(2.60) Q10-«H100]
Z
where:
Cfljr=kg vinyl chloride/100 kg prod-
uct.
Ck=The concentration of vinyl chlo-
ride as measured by Test
Method 106.
2.60= Density of vinyl chloride at one
atmosphere and 20° C hi
kg/m>.
0=Volumetric flow rate in mVhr as
determined by Reference
Method 2 of Appendix A to
Part 60 of this chapter.
10~'= Conversion factor for ppm.
Z=*Production rate (kg/hr).
(2) Test Method 107 is to be used to
determine the concentration of vinyl
chloride In each Inprocess wastewater
stream for which an emission limit Is
prescribed In | 61.85(b) (9) (1).
(3) Where a stripping operation Is
used to attain the emission limit In | 61.-
64(e), emissions are to be determined
using Test Method 107 as follows:
(1) The number of strippers and sam-
ples and the types and grades of resin to
be sampled are to be determined by the
Administrator for each Individual plant
at the time of the test based on the
plant's operation.
(11) Each sample Is to be taken Imme-
diately following the stripping operation.
(Ill) 'The corresponding quantity of
material processed by each stripper Is to
be determined on a dry solids basis and
by a method submitted to and approved
by the Administrator.
(Iv) At the prior request of the Ad-
ministrator, the owner or operator shall
provide duplicates of the samples re-
quired In paragraph (g)(3)(l) of this
section.
(4) Where control technology other
than or In addition to a stripping opera-
tion Is used to attain the emission limit
in 181.64(e), emissions are to be deter-
mined as follows:
(1) Test Method 106 is to be used to
determine atmospheric emissions from
all of the process equipment simultane-
ously. The requirements of paragraph
(g) (1> of this section are to be met.
(11) Test Method 107 Is to be used to
determine the concentration of vinyl
chloride in each Inprocess wastewater
stream subject to the emission limit pre-
scribed in | 61.64(e). The mass of vinyl
chloride in kg/100 kg product in each
In process wastewater stream Is to be de-
termined by using the following equa-
tion:
C,x--
[Ct R 10-1 [1001
Z
There:
Cn -kg vinyl chloride/100 k» product.
C<-the concentration of vinyl chloride at measured
by Test Method 107.
K -water flow nte In 1/hr, determined In accordance
with e method which hu been submitted !•
Mid approved by the Administrator.
IO-* - Conversion factor for ppm.
Z-Prodoctlon rate (kf/hr), determined In accord-
ance with a method which hu been submitted
and approved by the Administrator.
(5) The reactor opening loss for which
an emission limit is prescribed In f 61.64
(a) (2) is to be determined. The number
of reactors for which the determination
Is to be made Is to be specified by the
Administrator for each Individual plant
at the time of the determination based
on the plant's operation. For a reactor
that fc alao'ased as a stripper, the deter*
mtnatstTfi n*y be made immediately tOsW
lowing the stripping operation.
(1) Except as provided in paragraph
(g)(6)(U) of this section, the reactor
opening loss Is to be determined using
the following equation:
„ w (a.ao) (io-«) (ct)
c 7z
where:
C- kt ilnyl chloride emMonaTkf prodnet.
P-Capacity of the reactor In m«.
160-Density of rlnyl chloride at one atnuwphtre and
10-«-Converslon factor tor ppm.
C*—ppm by Tolume vinyl chloride ai determined by
Teat Method 100 or a portable hydrocarbon
detector which measure* hydrocarbon*-
•with a atniltlvltj of at least 10 ppsa.
r-Number of batchet since the reactor was last
opened to the atmosphere.
Z-Average k| of polyvlnyl chloride produced per
batch In the number of batches since the reactor
was ben opened to the atmosphere.
(A) If Method 108 is used to deter-
mine the concentration of vinyl chloride
(Cb), the sample Is to be withdrawn at
a constant rate with a probe of sufficient
length to reach the vessel bottom from
the manhole. Samples are to be taken
for 5 minutes within 6 Inches of the ves-
III-lll
-------
fel bottom, B minute* near the Teasel
center, and 5 minutes near the vessel top.
(B) If a portable hydrocarbon detec-
tor Is used to determine the concentra-
tion of vinyl chloride (Cb), a probe of
sufficient length to reach the vessel bot-
tom from the manhole is to be used to
make the measurements. One measure-
ment will be made within 6 Inches of the
Vessel bottom, one near the vessel center
and one near the vessel top. Measure-
ments are to be made at each location
until the reading is stabilized. All hydro-
carbons measured are to be assumed to
be vinyl chloride.
(C) The production rate of polyvlnyl
chloride (Z) Is to be determined by a
method submitted to and approved by the
Administrator.
(11) A calculation based on the riumber
of evacuations, the vacuum Involved, and
the volume of gas In the reactor is hereby
approved by the Administrator as an al-
ternative method for determining reac-
tor opening loss for postpolymerizatlon
reactors in the manufacture of bulk
resins.
(Sec. 114 of the Clean Air Act ac amende*
(42UJ3.C. 18670-9).)
g 61.68 Emuboa mooitorinc.
(a) A vinyle chloride monitoring sys-
tem is to be used to monitor on a con-
tinuous basis the emissions from the
sources for which emission limits are pre-
scribed in ! 61.62(a) and (b>, I 61.63(a),
and 1 61.64(a) (1) , (b) , (c) , and (d) . and
for any control system to which reactor
emissions are required to be ducted in
161.64'a) *2>or to which fugitive emis-
sions are required to be ducted in
f 61.65(b)(l)(il), and (b)(3), (b)(5),
(b) The vinyl chloride monitoring sys-
tem(s) used to meet the requirement in
paragraph (a) of this section Is to be a
device which obtains air sampels from
one or more points on a continuous
sequential basis and analyzes the sample!
with gas chromotography or, if the owner
or operator assumes that all hydrocar-
bons measured are vinyl chloride, with
infrared spectrophotometry, flame Ion
detection, or an equivalent or alterna-
tive method. The vinyl chloride monitor-
Ing system used to meet the requirement*
in I «1.65 A calibration gas cylinder stand-
ard containing the appropriate concen-
tration of vinyl chloride. The gas com-
position of the calibration gas cylinder
standard is to have been certified by the
manufacturer. The manufacturer must
have recommended a maximum shelf
life for each cylinder so that the concen-
tration does not change greater than
±5 percent from the certified value. The
date of gas cylinder preparation, certified
vinyl chloride concentration and recom-
mended maximum shelf life must have
been affixed to the cylinder before ship-
ment from the manufacturer to the
buyer. If a gas chromatograpb is used as
the vinyl chloride monitoring system,
these gas mixtures may be directly used
to prepare a chromatograph calibration
curve as described In section 7.3 of Test
Method 106. The requirements in sec-
tions 5.2.3.1 and 5.2.3.2 of Test Method
106 for certification of cylinder stand-
ards and for establishment and verifica-
tion of calibration standards are to be
followed.
(Sec. 114 of the Clean Air Act w amended
(48UJB.C. 18670-*).)
g 61.69 Initial report.
(a) An owner or operator of any
source to which this subpart applies shall
submit a statement in writing notifying
the Administrator that the equipment
and procedural specifications in {$ 61.65
(b)(6), (b)(7), and (b) (8) are being
implemented.
(b) (1) In the case of an existing
source or a new source which has an
Initial startup date preceding the effec-
tive date, the statement is to be submit-
ted within 90 days of the effective date,
unless a waiver of compliance is granted
under {61.11, along with the informa-
tion required under i 61.10. If a waiver
of compliance is granted, the statement
is to be submitted on a date scheduled
by the Administrator.
<2_> In the case of a new source which
did not have an initial startup date pre-
ceding the effective date, the statement
is to be submitted within 90 days of the
initial startup date.
(c) The statement to to contain the
following Information:
(1) A list of the equipment Installed
for compliance,
(2) A description of the physical and
functional characteristics of each piece
of equipment.
(3) A description of the methods
which have been incorporated Into the
standard operating procedures for meas-
uring or calculating the emissions for
which emission limits are prescribed in
1161.65 (b) (DO) and (b) («)(!),
(4) A statement that each piece of
equipment to Installed and that each
piece of equipment and each procedure/
is being used.
(Sec. 114 of the Clean Air Act at amende*
(42U.S.C. 18670-0).)
§ 61.70 Semiannual report.
(a) The owner or operator of arty
(a) (2) to to be determined. The number
source to which this subpart applies shall
submit to the Administrator on Septem-
ber 15 and March 15 of each year a report
in writing containing the information
required by this section. The first semi-
annual report to to be submitted follow-
ing the first full 6 month reporting period
after the initial report to submitted.
(b) (1) In the case of an existing source
or a new source which has an initial
startup date preceding the effective date,
the first report to to be submitted within
180 days of the effective date, unless a
waiver of compliance to granted under
i 61.11. If a waiver of compliance to
granted, the first report to to be sub-
mitted on a date scheduled by the Ad-
ministrator.
(2) In the case of a new source waich
did not have an initial startup date, -re-
ceding the effective date, the first report
to to be submitted within 180 days of the
initial startup date.
(c) Unless otherwise specified, the
owner or operator shall use the Test
Methods In Appendix B to this part to
conduct emission tests as required by
paragraphs (c)(2) and (c)(3) of this
section, unless an equivalent or an alter-
native method has been approved by the
Administrator. If the Administrator
finds reasonable grounds to dispute the
results obtained by an equivalent or al-
ternative method, he may require the use
of a reference method. If the results of
the reference and equivalent or alterna-
tive methods do not agree, the results
obtained by the reference method pre-
vail, and the Administrator may notify
the owner or operator that approval of
the method previously considered to be
equivalent or alternative to withdrawn.
(1) The owner or operator shall in-
clude in the report a record of any emis-
sions which averaged over any 'hour
period (commencing on the hour) are
In excess of the emission limits pre-
scribed in }i 61.62(a) or (b), { 61.63(a),
or 8t61.64(a)U), (b), (c).or (d), or for
any control system to which reactor
emissions are required to be ducted in
5 61.64 (a) (2) or to which fugitive emis-
sions are required to be ducted in 5 61.65
(b)(1)(11), (b)(2), (b) (5), (b)(6)(11).or
(b) (9) (11). The emissions are to be meas-
ured in accordance with i 61.68.
(2) In polyvlnyl chloride plants for
which a stripping operation to used to
attain the emlsison level prescribed in
8 61.64(e), the owner or operator shall
include in the report a record of the
vinyl chloride content in the polyvinyl
chloride resin. Test Method 107 to to be
used to determine vinyl chloride content
as follows:
(i) If batch stripping to used, one rep-
resentative sample of polyvlnyl chloride
resin to to be taken from each batch of
111-112
-------
•ach grade of resin immediately follow-
ing the completion of the stripping op-
eration, and Identified by resin type and
grade and the date and time the batch
is completed. The corresponding quan-
tity of material processed In each strip-
per batch Is to be recorded and identi-
fied by resin type and grade and the
date and time the batch is completed.
(11) If continuous stripping is used,
on* rtpriMntaUve sample of polyvlnyl
chloride feeln is to be taken for each
grade of resin processed or at Intervals
at • hours for each grade of resin which
is being processed, whichever is more fre-
quent. The sample is to be taken as the
resin flows out of the stripper and Iden-
tified by resin type and grade and tha
date and time the sample was taken.
The corresponding quantity of material
processed by each stripper over the time
period represented by the sample during
the eight hour period, is to be recorded
and identified by resin type and grade
and the date and time it represents.
(ill) The quantity of material proc-
essed by the stripper is to be determined
on a dry solids basis and by a method
submitted to and approved by the Ad-
ministrator.
(iv) At the prior request of the Ad-
ministrator, the owner or operator shall
provide duplicates of the samples re-
quired in paragraphs (2) (1) and (e)
(2) (11) of this section.
(T) The report to the Administrator
by the owner or operator is to Include
the vinyl chloride content found in each
sample required by paragraphs (c) (2)
(1) and (c) (2) (11) of this section, aver-
aged separately for each type of resin,
over each calendar day and weighted
according to the quantity of each grade
of resin processed by the stripper(s)
that calendar day, according to the fol-
lowing equation:
Or,
where: -
/I = 24-hour average concentration of
type T( resin in ppm (dry
weight basis).
Q= Total production of type T,
resin over the 24-hour period,
in kg.
T<=Type of resin; »=1,2 . . . tn
where m is total number of
resin types " produced during
the 24-hour period.
M = Concentration of vinyl chloride
in one sample of grade Qt
resin, in ppm.
P= Production of grade G* resin
represented by the sample, in
kg.
G{= Grade of resin; e.g., G,. Gt, and
G,.
n = Total number of grades of resin
produced during the 24-hour
period.
(vl) The owner or operator shall re-
tain at the source and make available
for Inspection by the Administrator for
a minimum of 2 years records of all data
needed to furnish the information re-
quired by. paragraph (c) (2) (v) of this
section: The records are to contain the
following Information:
(A) The vinyl chloride content found
in all the samples required hi paragraphs
(c) (2) (1) and (c) (2) (11) of this section.
identified by the resin type and grade
and the tune and date of the sample, and
(B) The corresponding quantity of
polyvlnyl chloride resin processed by the
stripper (s). Identified by the resin type
and grade and the time and date it
represents.
(3) The owner or operator shall in-
clude in the report a record of the emis-
sions from each reactor opening for
which an emission limit Is prescribed in
I 81.84 (a) (2). Emissions are to be deter-
mined In accordance with | 61.87(g) (5).
except that emissions for each reactor
are to be determined. For a reactor that to
also used as a stripper, the determination
may be made Immediately following the
stripping operation.
(8«c. 114 of th« Clew Air Act M »m«o
-------
APPENDIX A - REFERENCE METHODS
UBTBOD 106—DWTUIIINATION or VINTI.
OMLOKIOI FSOM STATIONABT Bouaccs
Performance of thlt method should not b*
•tUmpted by persona unfamiliar with the
operation of • gu chromatograph, nor by
tbose Who are unfamiliar with source sam-
pling, a* there are many details that are
beyond the scope of this presentation. Care
> must be exercised to prevent exposure of
sampling personnel to vinyl chloride, a car-
cinogen.
1. Principle and Applicability.
1.1 An integrated bag sample of stack
- gas containing Tinyl chloride (chloroetbene)
to subjected to chromatographic analysis, us-
ing a name lonlzatlon detector.
1.3 The method Is applicable to the meas-
urement of vinyl chloride In stack gases from
•thylene dlchlorlde, vinyl chloride and poly-
vlnyl chloride manufacturing processes, ex-
cept where the vinyl chloride la contained In
participate matter.
3. Range and Sensitivity.
The lower limit of detection will vary ac-
cording to the chromatograph used. Values
reported Include 1 X 10-' mg and 4 X 10-'
mg.
I. Inter/erenca. Aoetaldehyde, which can
occur in some vinyl chloride sources, will In-
terfere with the vinyl chloride peak from
•the Chromaaorb 102 > column. See sections
4.3.3 and 0.4. If resolution of the vinyl
chloride peak Is still not satisfactory for a
particular sample, then chromatograph pa-
rameters can be further altered with prior
approval of the Administrator. If alteration
of the chromatograph parameters falls to
resolve the vinyl chloride peak, then sup-
plemental confirmation of the vinyl chloride
peak through an absolute analytical toch-
"* nlque, such as mass spectroscopy. must b»
performed.
4. Apparatus,
4.1 Beiapttng (Figure 106-1).
4.1.1 Probe—Stainless steel. Pyres glass.
or Teflon tubing according to stack temper-
ature, each equipped with a (lass) wool plug
to remove partleulate matter.
4.14 Sample line—Teflon, 6.4 mm outside
diameter, of sufficient length to connect
probe to bag. A new unused piece Is employed
(or each series of bag samples that constitutes
an emission test.
4.1.3 Male (2) and female (3) stainless
steel quick-connects, with ball checks (one
pair without) located as shown In Figure
108-1.
4.1.4 Tedlar bags. 100 liter capacity—To
contain sample. Teflon bags are not accept-
able, Alumlnlzed Mylar bags may be used,
provided that the samples are analyzed
within 34 hours of collection.
4.1.8 Rigid leakproof containers for 4.1.4,
with covering to protect contents from sun-
light.
4.1.0 Needle valve—To adjust sample flow
rate.
4.1.7 Pump—Leak-free. Minimum capac-
ity 3 liters per minute.
4.1.8 Charcoal tube—To prevent admis-
sion of vinyl chloride to atmosphere In vicin-
ity of samplers.
4.1.9 Plow meter—Por observing sample
flow rate; capable of measuring a flow range
from 0.10 to 1.00 liter per minute.
4.1 JO Connecting tubing— Teflon, -6.4
mm outside diameter, to assemble sample
train (Figure 100-1).
4,1.11 Pltot tube—Type B (or equivalent).
> Mention of trade names oa specific prod-
vets does not constitute endorsement by the
•environmental Protection Agency.
attached to the probe so that the sampling
stow rate can be regulated proportional to
the stack gas velocity.
44 Sample recovery.
4.3.1 Tubing—Teflon. 6.4 mm outside)
diameter, to connect bag to gas chromato-
graph sample loop. A new unused piece Is
employed for each series of bag samples that
constitutes an emission test, and Is to be dis-
carded upon conclusion of analysis of those
bags.
4.3 Analysis.
4.3.1 Oas chromatograph—With flame
lonlzatlon detector, potentlometric strip
chart recorder and 1.0 to 6.0 ml heated sam-
pling loop In automatic sample valve.
4.3.3 Ch.romatograph.ic column. Stainless
steel, 3 mx84 """. containing 80/100 mesh
Chromasorb 102. A secondary column of OE
BF-06, 20 percent on 60/80 mesh AW Chroma-
sorb P, stainless steel, 2 in x 3.2 mm or Pora-
pak T, 80/100 mesh, stainless steel, 1 mx84
mm Is required If acetaldehyde Is present. If
used, a secondary column is placed after the
Chromasorb 103 column. The combined
columns should then be operated at 130* C.
444 Flow meters (3)—Rotameter type.
0 to 100 ml/mln capacity, with flow control
valves.
4.8.4 Oas regulators—Por required gas
cylinders.
4.3 5 Thermometer—Accurate to-one de-
gree centigrade, to measure temperature of
heated sample loop at time of sample Injec-
tion.
4.3.8 Barometer—Accurate to S mm Hg, to
measure atmospheric pressure around gas
chromatograph during sample analysis.
4.8.7 Pump—Leak-free. Minimum capac-
ity 100 ml/mln.
4.4 Calibration.
4.4.1 Tubing—Teflon, 8.4 mm outside
diameter, separate pieces marked for each
calibration concentration.
4.44 Tedlar bags—Slxteen-lnch square
size, separate bag marked for each calibra-
tion concentration.
4.4.3 Syringe—0.8 ml, gas tight
4.4.4 Syringe—BOM, gas tight.
4.4J Flow meter—Rotameter type, • to
1000 ml/mln range accurate to £1%. to
meter nitrogen In preparation of standard
gas mixtures.
4.4.8 Stop watch—Of known accuracy, to
time gas flow In preparation of standard gas
mixtures.
8, Reagents. It Is necessary that all rea-
gents be of chromatographle grade.
B.I Analysis.
8.1.1 Helium gas or nitrogen gas—Zero
grade, for chromatographle carrier gas.
8.14 Hydrogen gas—Zero grade.
8.14 Oxygen gas, or Air, as required by
the detector—Zero grade.
84 Calibration. Use one of the following
options: either 64.1 and 644, or 64.3.
84.1 Vinyl chloride, 98.9+ percent. Pure
vinyl chloride gas certified by the manufac-
turer to contain a minimum of 99.8 percent
vinyl chloride for use In the preparation of
standard gas mixtures In Section 7.1. If the
gas manufacturer maintains a bulk cylinder
supply of 69.9+ percent vinyl chloride, the
certification analysis may have been per-
formed on this supply rather than on each
gas cylinder prepared from this bulk supply.
The date of gas cylinder preparation and the
certified analysis must have been affixed to
the cylinder before shipment from the gas
manufacturer to the buyer.
644 Nitrogen gas. Zero grade, for prepa-
ration of standard gas mixtures.
64.8 Cylinder standards (I). Oas mix-
ture standards (60, 10, and 6 ppm vinyl
chloride In nitrogen cylinders) for which the
gas composition uea been certified by the
manufacturer. The manufacturer must have
recommended a maximum shelf life for each
cylinder so that the concentration does not
change greater than ±6 percent from the
certified value. The date of gu cylinder prep* '
aratlon, certified vinyl chloride concentra-
tion and recommended maximum shelf life
must have been affixed to the cylinder before
shipment from the gas manufacturer to the
buyer. These gas mixture standards may be
directly used, to prepare a chromatograph
calibration curve as described in section 7.8.
8.2.3.1 Cylinder itandarda certification.
The concentration of vinyl chloride in nitro-
gen In each cylinder must have been certified
by the manufacturer by a direct analysis of
each cylinder using an analytical procedure
that the manufacturer had calibrated on ttae
day of cylinder analysis. The calibration of
the analytical procedure shall, as a minimum.
have utilized a three-point calibration curve.
It Is recommended that the manufacturer
maintain two calibration standards and use
these standards in the following way: (1) a
high concentration standard (between 60 and
100 ppm) for preparation of a calibration
curve by an appropriate dilution technique;
(3) a low concentration standard (between
6 and 10 ppm) for verification of the dilution
technique used.
64.34 Establishment and verification of
calibration standard*. The concentration of
each calibration standard must havf been
established by the manufacturer using
reliable procedures. Additionally, each
calibration standard must have been veri-
fied by the manufacturer by one 01 the
following procedures, and the agreement
between the initially determined concen-
tration value and the verification concen-
tration value must be within -± 6 percent:
(I) vertlflcatlon value determined by com-
parison with » calibrated vinyl chloride
permeation tube, (2) verification value
determined by comparison with a gas mix-
ture prepared In accordance with the pro-
cedure described In section 7.1 and using
99.9+ percent vlnyle chloride, or (3) verifi-
cation value obtained by having the
calibration standard analyzed by the Na-
tional Bureau of Standards. All calibration
standards must be renewed on a time
interval consistent with the shelf life of
the cylinder standards sold.
6. Procedure.
8.1 Sampling. Assemble the sample train
as in Figure 100-1. Perform a bag leak check
according to Section 7.4. Observe that all
connections between the bag and the probe
are tight. Place the end of the probe at the)
oentrold of the stack and start the pump
with the needle valve adjusted to yield a
flow of 0.6 1pm. After a period of time suffi-
cient to purge the line several times has
elapsed, connect the vacuum line to the
bag and evacuate the bag until the rotam-
etor indicates no flow. Then reposition the)
sample and vacuum lines and begin the ac-
tual sampling, keeping the rate proportional
to the stack velocity. Direct the gas exiting
the rotameter away from sampling personnel.
At the end of the sample period, shut off the
pump, disconnect the sample line from the
bag, and disconnect the vacuum line from
the bag container. Protect the bag container
from sunlight.
6.3 Sample storage. Sample bags must be
kept out of direct sunlight. When at all
possible analysis Is to be performed within
34 hours, but In no ease in excess of 72
hours of sample collection.
64 Sample recovery. With a piece "of Tef-
lon tubing Identified for that bag, connect a
bag inlet valve to the gas ehromatograph
sample valve. Switch the valve to withdraw
gas from the bag through the sample loop.
Plumb the equipment so the sample gas
passes from the sample valve to the leak-free
pump, and then to a charcoal tube, followed
by a 0-100 ml/mln rotameter with flow con-
trol valv*.
•.4 Analysis. Set the column temperature
III-114
-------
to 100* C tli* detector temperature to 1*0*
C. and tb« sample loop temperature to 70' O.
Wben optimum hydrogen and oxygen flow
rates have been determined verify and main-
tain theee flow rates during all chromato-
graph operation*. Using zero helium or
nitrogen M the carrier gat, ectabllih a flow
rat* In the range consistent with the manu-
facturer's requirements for satisfactory de-
tector operation. A flow rate of approxi-
mately 40 ml/mln should produce adequate
separations. Observe the base line periodi-
cally and determine that the noise level has
stabilized and that base line drift has ceased.
Purge the sample loop for thirty seconds at
the rate of 100 ml/mln, then activate toe
sample valve. Record the Injection time (the
position of the pea on the chart at the time
of sample Injection). the sample number, the
sample loop temperature, the column tem-
perature, carrier gas flow rate, chart speed
and the attenuator setting. Record the lab-
oratory pressure. From the chart, select the/
peak having the retention time correspond-
ing to vinyl chloride, as determined In Sec-
tion 7.1 Measure the peak area. A., by use
of a disc Integrator or a planlmeter. MM •
sure the peak height, H.. Record A. Ht., and
the retention time. Repeat the Injection at
least two times or until two consecutive vinyl
chloride peaks do not vary In area more than
6%. The average value for these two areas
will be used to compute the bag concentra-
tion.
Compare the ratio of H. to Am for the vinyl
chloride sample with the same ratio for the
standard peak which Is closest In height. As
a guideline, If these ratios differ by more
than 10%, the vinyl chloride peak may not
be pure (possibly acetaldehyde is present)
and the secondary column should be em-
ployed (see Section 4.3.2).
88 Measure the ambient temperature and
barometric pressure near the bag. (Assume
the relative humidity to be 100 percent.)
From a water saturation vapor pressure table,
determine and record the water vapor con-
tent of the bag.
7. Calibration and Standards.
7.1 Preparation of vinyl chlorite stand-
ard yea mixturei. Evacuate a slxteen-lnch
square Tedlar bag that has passed a leak
check (described In Section 7.4) and meter
in 5 liters of nitrogen. While the bag is
filling, use the 0.6 ml syringe to Inject
350>d of 99.9+ percent vinyl chloride
through the wall of the bag. Dpon with-
drawing the syringe needle, Immediately
cover the resulting hole with a piece of
adhesive tape. The bag now contains a
vinyl chloride concentration of BO ppm. In
a like manner use the other syringe to
prepare gas mixtures having 10 and 6 ppm
vinyl chloride concentrations. Place each
bag on a smooth surface and alternately
depress opposite sides of the bag 60 times
to further mix the gases. These gas mixture
standards may be used for 10 days from the
date of preparation, after which time prep-
aration of new gas mixtures Is required.
(CAUTION.—Contamination may be a prob-
lem when a bag Is reused If the new gas
mixture standard contains a lower con-
centration than the previous gas mixture
standard did.)
13 Determination of vinyl chloride re-
tention time. This section can be performed
simultaneously with Section 7.3. Establish
chromatograph conditions Identical with
those In Section 63, above. Bet attenuator
to X 1 position. Flush the sampling loop
with zero helium or nitrogen and activate
the sample valve. Record the Injection time,
the sample loop temperature, the column
temperature, the carrier gas flov*, rate, the
chart speed and the attenuator setting.
Record peaks and detector responses that
occur In the absence of vinyl chloride. Main-
tain conditions. With the equipment plumb-
Ing arranged Identically to Section 0.3, flush
Il«ur« 106-1.
b«g l
(1)
Hoatioa of trad* tiMeo on opoctfle product! dooo noc
••torooBftac kjr U« Invirawonul froccctln Agonc/.
the sample loop for 30 seconds at the rate of
100 ml/mln with one of the vinyl chloride
calibration mixtures and activate the sample
valve. Record the Injection time. Select the
peak that corresponds to vinyl chloride.
Measure the distance on the chart from the
injection time to the time at which the peak
maximum occurs. This quantity, divided by
the chart speed. Is defined as the retention
time. Record.
7.3 Preparation of chromatograph cali-
bration curve. Make a gas chromatographlo
measurement of each gas mixture standard
(described In section 6.2.2 or 7.1) using con-
ditions Identical with those listed in sections
6.3 and 6.4. Flush-the sampling loop for 80
seconds at the rate of 100 ml/mln with each
standard gas mixture and activate the sam-
ple valve. Record C,, the concentration of
vinyl chloride injected, the attenuator set-
ting, chart speed, peak area, sample loop
temperature, column temperature, carrier
gas flow rate, and retention time. Record the
laboratory pressure. Calculate Ac, the peak
area multiplied by the attenuator setting.
Repeat until two Injection areas are within
6 percent, then plot these points v. C«. Wben
the other concentrations have been plotted,
draw a smooth purve through the points.
Perform calibration dallyLor before and after
each set of bag samples, whichever Is more
frequent.
7.4 Bag leak checks. While performance
of this section Is required subsequent to bag
use, it ls also advised that it be performed
prior to bag use. After each use, make sure
a bag did not develop leaks aa follows. To leak
check, connect a water manometer and pres-
surize the bag to 6-10 cm H,O (2-4 in H,O).-
Allow to stand for 10 minutes. Any displace-
ment In the water manometer indicates a
leak. Also oheck the rigid container for leaks
in this manner.
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RULES AND REGULATIONS
Title 40—Protection of Environment
CHAPTER I—ENVIRONMENTAL
PROTECTION AGENCY
CUBCHAPTER C—AIR PROGRAMS
(FRL 618-11
PART 61—NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Standard for Vinyl Chloride
On December 24, 1975, under section
112 of the Clean Air Act, as amended (42
U.S.C. 1857), the Environmental Protec-
tion Agency (EPA) added vinyl chloride
to the list of hazardous air pollutants
(40 FR 59477) and proposed n national
emission standard for it (40 FR 59532).
The standard covers plants which manu-
facture ethylene dichloride, vinyl
chloride, and/or polyvinyl chlorMg.
EPA decided to regulate vinyl chloride
because It has been implicated as the
causal agent of angiosarcoma and other
serious disorders, both carcinogenic and
noncarcinogenic, in people with occupa-
tional exposure and In animals with ex-
perimental exposure to vinyl chloride.
Reasonable extrapolations from these
findings cause concern that vinyl chlo-
ride may cause or contribute to the same
or similar disorders at present ambient
air levels. The purpose of the standard Is
to minimize vinyl chloride emissions
from all known process and fugitive
emission sources In ethylene dichlorlde-
vinyl chloride and polyvinyl chloride
plants to the level attainable with best
available control technology. This will
have the effect of furthering the protec-
tion of public health by minimizing the
health risks to the people living in the
vicinity of these plants and to any addi-
tional people who are exposed as a result
Of new construction.
Interested parties participated in the
rulemaking by sending comments to EPA.
The comments have been carefully con-
sidered, and where determined by the
Administrator to be appropriate, changes
have been made to the regulation as pro-
mulgated,
SUMMARY OF THE STANDARD
In ethylene dichlorlde-vinyl chloride
plants, the standard limits vinyl chloride
emissions from the ethylene dichloride
and vinyl chloride formation and puri-
fication processes to 10 ppm. For the ox-
ychlorination process, vinyl chloride
emissions are limited to 0.2 g/kg of ethyl-
ene dichloride product.
In polyvinyl chloride plants, the stand-
ard limits vinyl chloride emissions from
equipment preceding and including the
stripper In the plant process flow to 10
ppm. Emissions from equipment follow-
ing the stripper are to be controlled by
stripping dispersion resins to 2000 ppm
and other resins to 400 ppm, or by using
equivalent controls. Vinyl chloride emis-
sions from reactor opening are to be re-
duced to 0.02 g/kg polyvinyl chloride
product.
In both ethylene dichloride-vinyl
chloride and polyvinyl chloride plants.
relief valve discharges and manual vent-
ing of gases are prohibited except under'
emergency conditions. Fugitive emissions
are required to be raptured and con-
trolled.
HEAI/TH AND ENVJIIONMENTAL IMPACTS
EPA prepared a document entitled the
Quantitative Risk Assessment for Com-
munity Exposure to Vinyl Chloride which
estimates the risk from vinyl chloride
exposure to populations living in the vi-
cinity of vinyl chloride-emitting plants
before and after implementation of con-
trols to meet the standard. There are no
dose-response data for the concentra-
tions of vinyl chloride found in the am-
bient air. Therefore, assessments of risk
at ambient levels of exposure were ex-
trapolated from dose-response data from
higher levels of exposure using both a
linear model and a log-probit model.
Extrapolations made with each of these
models entailed using different sets of
assumptions. Because different assump-
tions can be made in extrapolating to
low doses, the health risks are reported
in ranges.
It was estimated that 4.6 million peo-
ple live within 5 miles of ethylene dicho-
ride-vinyl chloride and polyvinyl chlo-
ride plants and that the average ex-
posure around these plants before instal-
lation of controls to meet the standard.
Is 17 parts per billion. The exposure
levels for uncontrolled plants were cal-
culated based on estimated 1974 emis-
sion levels. Using the linear dose-re-
sponse model, EPA found that the
rate of initiation of liver anciosarcoma
among people living around uncontrolled
plants is expected to range from less than
one to ten cases of liver angiosarcoma
per year of exposure to vinyl chloride.
The log-probit model gave predictions
that are 0.1 to 0.01 times this rate. This
wide range Is an indication of the un-
certainties in extrapolation to low doses.
Due to the long latency time observed in
cancer cases resulting from vinyl chloride
exposure, increases initiated by exposure
this year will not be diagnosed until the
1990's or later. Vinyl chloride Is also es-
timated to produce an equal number of
primary cancers at other sites, for a total
of somewhere between less than one and
twenty cases of cancer per year of ex-
posure among residents around plants.
The number of these effects Is expected
to be reduced at least In proportion to the
reduction in the ambient annual average
vinyl chloride concentration, which Is
expected to be 5 percent of the uncon-
trolled levels after the standard Is Im-
plemented. .
Changes In the standard since pro-
posal do not affect the level of control
required. Thus, the environmental Im-
pact of the promulgated standard Is,
with one exception, the same as that
described in Chapter 6 of Volume I of
the Standard Support and Environmen-
tal Impact Statement. According to data
submitted by the Society of Plastics In-
dustry, Inc. (SPI), the Impact on water
consumption in the draft environmental
Impact statement was overstated. In es-
timating the impact on water consump-
tion, EPA based Its estimates on worst
case conditions. That Is, EPA assumed
that those control systems with the
greatest water usage would be employed
and that there would be no recycling
of water. There Ls no regulation which
would require water recycling. Accord-
Ing to SPI, the control system utilizing
the most water will not be used Rcner-
ally by the Industry and economic fac-
tors will cause plants to recycle much
of the water. Therefore, according to
SPI the impact of the standard on water
consumption will be negligible.
The environmental impacts of the
promulgated standard may be summar-
ized as follows: The primary environ-
mental impacts of the standard are ben-
eficial and will consist of vinyl chloride
emission reductions of approximately 94
percent at ethylene dichloridc-vinyl
chloride plants and 95 percent at poly-
vinyl chloride plants. Percentage num-
bers for both source categories are based
on an estimated 90 percent reduction in
fugitive emissions and 1974 emission
levels.
The potential secondary environmen-
tal Impacts of the standard are either
insignificant or will be minimized w th-
out additional action, except for one ad-
verse impact. Hydrogen chloride Is al-
ready emitted by process equipment at
ethylene dichloride-vinyl chloride plants
and by other petrochemical plants in the
complexes where ethylene dichloride-
vinyl chloride plants are typically lo-
cated. An incinerator used to attain the
standard at an ethylene dichloride-vinyl
chloride plant could Increase hydrogen
chloride emissions by several fold. Typi-
cally, however, due to the corrosion prob-
lems which would otherwise occur both
on plant property and in the community,
plants use scrubbers to control already
existing hydrogen chloride emissions.
Hydrogen chloride emissions resulting
from control of vinyl chloride emissions
are expected to be controlled for the
same reason. If even a moderately effi-
cient scrubber (98 percent control) were
used to control the hydrogen chloride
emissions resulting from incineration of
vinyl chloride emissions, the increase In
hydrogen chloride emissions from a typ-
ical ethylene dichloride-vinyl chloride
plant due to the standard would be re-
duced to 35 percent. However, EPA plans
to further evaluate the need to control
hydrogen chloride emissions, since dif-
fusion model results indicate that under
"worst-case" meteorological conditions,
the hydrogen chloride emissions from
the process equipment and the Incinera-
tor combined would cause maximum am-
bient concentrations of hydrogen chlo-
ride in the vicinity of ethylene dichlo-
ride-vinyl chloride plants to be In the
same range or somewhat higher than
existing foreign standards and National
Academy of Sciences (NAS) guidelines
for public exposure.
ECONOMIC IMPACT
In accordance with Executive Order
11821 and OMB circular A-107. EPA
carefully evaluated the economic and'
Inflationary impact of the proposed
standard and alternative control levels
and certified this in the preamble to the
proposed standard. These impacts an
FEDERAL EEOISTEt, VOL 41. NO. JOS—THURSDAY, OCTOMft 11, 1*76
III-116
-------
discussed In Chapter 7 of Volume I of
the Standard Support and Environmen-
tal Impact Statement. Comments on the
proposed standard have resulted In only
one major change In the economic Im-
pact analysis. EPA estimated that there
would be four plant closures as a result
of the promulgated standard. Of the four
plants Identified as possible closure can-
didates, one has given notice that It no
longer produces polyvlnyl chloride and
the other three have Indicated that they
do not Intend to close as a result of the
standard.
The economic Impacts of the promul-
gated standard may be summarized as
follows: The total capital cost for exist-
ing plants to meet the standard is esti-
mated to be $198 million, of which $15
million is for ethylene dichlorlde-vinyl
chloride plants and $183 million Is for
polyvinyl chloride plants. EPA estimates
that these plants will have to spend $70
million per year to maintain the required
emission levels. In addition, the total
capital cost for existing plants to meet
the EPA's 1983 water effluent guideline
limitations Is expected to be $83 million
and the total annualized operation cost
Is $17 million. The costs to the Industry
of meeting the OSHA standard cannot be
quantified at this time, but they are ex-
pected to overlap to some degree with the
costs to meet EPA's fugitive emission
regulations. The costs of meeting the
fugitive emission regulations are included
In the total costs cited above for meeting
the promulgated regulation. Broken out
separately, the capital cost of meeting
the fugitive emission regulations Is $37
' million and the annualized cost Is $25
million.
The standard is not expected to deter
construction of new ethylene dichloride-
vlnyl chloride plants or most typos of
new polyvinyl chloride plants. For one
type of polyvlnyl chloride plant (disper-
sion process) that represents 13 percent
of the Industry production, the standard
would significantly deter the construc-
tion of smaller plants.
It Is estimated that the price of poly-
vlnyl chloride resins will rise by approxi-
mately 7.3 percent in order to maintain
precontrol profitability and also to re-
cover the total annualized control costs
necessitated by the standard at ethylene
dlchloride-vinyl chloride plants and poly-
vlnyl chloride plants. This increase Is
estimated to translate Into a maximum
consumer price Increase In goods fabri-
cated from polyvlnyl chloride resins of
approximately 3.5 percent. Recovery of
effluent annualized costs plus mainte-
nance of precontrol profitability Is esti-
mated to add approximately 2 percent to
l^olyvlnyl chloride resin prices and result
in an additional maximum consumer
price Increase of 1 percent.
PUBLIC PARTICIPATION
During the public comment period, 50
comment letters on the proposed stand-
ard were received. There were 24 from
Industry; 3 from environmental groups;
15 from Federal, State, and local agen-
cies; and 8 from Individual citizens. As
required by section H2(b) (1) (B) of the
RULES AND REGULATIONS
Act, a public hearing was held on the
proposed standard on February 3, 1976,
in Washington, D.C. Presentations were
made by the Environmental Defense
Fund, the Society of the Plastics Indus-
try, Inc., Dow Chemical Company, Dia-
mond Shamrock Corporation, and Air
Products and Chemicals, Inc. Copies of
the comment letters received, the public
hearing record, and a summary of the
comments with EPA's responses are
available for public inspection and copy-
ing at the EPA Public Information Ref-
erence Unit, Room 2922 (EPA Library),
401 M Street, SW., Washington. D.C. In
addition, copies of the comment sum-
mary and Agency responses may be ob-
tained upon written request from the
Public Information Center (PM-215),
Environmental Protection Agency, 401
M Street, SW., Washington. D.C. 20460
(specify Standard Support and Environ-
mental Impact Statement. Emission
Standard for Vinyl Chloride, Volume 11).
SIGNIFICANT COMMENTS AND CHANGES TO
THE PROPOSED REGULATION
(1) Decision to list vinyl chloride as a
hazardous air pollutant. In general, the
commenters did not contest EPA's deci-
sion to list vinyl chloride as a hazardous
air pollutant. However, three comment-
ers (two companies and one Federal
agency) argued that EPA placed undue
emphasis on factors suggesting that vinyl
chloride presented a health risk and
ignored factors suggesting that no sig-
nificant risk was involved. Under section
112, however, EPA could remove vinyl
chloride from the list of hazardous air
pollutants only if Information were pre-
sented to EPA that shows that vinyl
chloride Is clearly not a hazardous air
pollutant. As discussed more fully In the
comment summary, the commenters did
not provide conclusive evidence that vinyl
chloride is not a hazardous air pollutant
which causes or contributes to death or
serious illness, nor did they conclusively
prove that the health risk factors em-
phasized by EPA were insignificant.
Several other commenters agreed with
EPA's decision to list vinyl chloride as a
hazardous air pollutant, but argued that
EPA had overstated the health problem,
the emission levels, and the projected
ambient air concentrations around un-
controlled plants. With regard to the al-
leged overstated health problem, the
commenters stated, for example, that the
U.S. worker EPA discussed as having
been exposed to vinyl chloride levels low-
er than those usually encountered in
polyvinyl chloride production has been
dropped from the National Institute of
Occupational Safety and Health's listing
of workers with angiosarcoma. EPA
agrees that there are questions concern-
Ing the level of exposure and in some
cases the pathology of these cases not
Involved directly in polyvinyl chloride
and vinyl chloride production. These un-
certainties are stated In the appropriate
footnotes of the Scientiflc and Technical
Assessment Report on Vinyl Chloride and
Polyvinyl Chloride (STAR) where the
angiosarcoma cases are listed. However,
In spite of these uncertainties, in view of
the possible exposure patterns, these
cases cannot be Ignored In the evaluation
of the potential public health problems.
With regard to the alleged overstated
emission levels, the uncontrolled emis-
sion levels reported by EPA were based
on 1974 data. This qualification was
stated wherever emission data were pre-
sented. EPA recognizes that emissions
have been reduced since that time, and
slated this in the preamble to the pro-
posed standard. EPA decided not to
gather more recent data on emission
levels, because these emission levels are
expected to change, and gathering the
data would take considerable time both
on the part of EPA and on the part of
industry. Since the purpose of the stand-
ard is to minimize emissions, these more
current data would not affect the stand-
ard itself. The 1974 emission levels were
also used in diffusion modeling to project
maximum ambient air concentrations
around uncontrolled plants. These maxi-
mum air concentrations would probably
be lower if 1976 emission levels were used.
This would reduce the relative Impact
of the standard below that described In
the Standard Support and Environmen-
tal Impact Statement, but would not
affect the basis of the standard itself.
(2) Approach JOT Regulating Vinyl
Chloride Under Section 112. Two ap-
proaches other than using best avail-
able control technology were suggested
by the commenters for regulating vinyl
chloride under section 112. The first was
to ban polyvinyl chloride products for
which substitutes are currently available
and to gradually phase out other poly-
vinyl chloride products as substitutes
are developed.
In the preamble to the proposed stand-
ard EPA specified Its reasons for not set-
ting a zero emission limit for vinyl
chloride, as follows: (1) There are bene-
ficial uses of vinyl chloride products for
which desirable substitutes are not read-
ily available; (2) there are potentially
adverse health and environmental im-
pacts from substitutes which have not
been thoroughly studied; (3) there are a
number of employees, particularly in the
fabrication Industries, who would be-
come at least temporarily unemployed;
and (4) control technology Is available
which is capable of substantially reduc-
ing emissions of vinyl chloride Into the
atmosphere.
EPA agrees that substitutes do exist or
could be manufactured for most poly-
vinyl chloride uses. However, In general,
these substitutes do not have some of the
more desirable characteristics of poly-
vlnyl chloride, such as nonflammability.
If vinyl chloride and polyvinyl chloride
were banned, other substitutes with
these more desirable characteristics
would likely be developed. There Is a risk
that these substitutes would also have
adverse health or environmental effects.
Since control measures are available
which can reduce vinyl chloride emis-
Elons by 90 percent or more, It does not
seem prudent to reduce emissions by the
remaining percentage and take the risk
of Introducing new untested chemicals
Into the environment.
FEDE«Al REGISTER, VOL. 41, NO. JOS—THURSDAY, OCTOBER 11. It76
rn-ii7
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Another approach suggested by the
commenters was to base the standard for
each individual emission point on cost
versus benefit. Several of the fugitive
emission sources were named specifically
as ones for which the costs of control
were substantially higher than the bene-
fits. Although EPA did determine a cost-
bencflt ratio for the controls required
for A number of emission points, EPA
does not believe such a ratio is an appro-
priate basis on which to set a standard.
Section 111 of the Clean Air Act provides
» for the development of standards based
on best control technology (considering
costs). Even under section 111, however,
standards are not based on a fine bal-
, ancing of costs versus benefits. Instead,
costs are considered In terms of the af-
fordabillty of the control technology re-
quired to achieve a given emission level
and the economic impact of possible
Btandards on the Industry In ques-
tion. Unlike section 111, section 112 does
not explicitly provide for consideration.
of costs, so it would clearly be inappro-
priate to consider costs to a greater ex-
tent under section 112 than would be
done under section 111. As discussed in
the preamble to the proposed standard
for vinyl chloride, EPA believes costs
may be considered under section 112, but
only to a very limited extent; i.e., to
assure that the costs of control technol-
ogy are not grossly disproportionate to
the amount of emission reduction
Achieved. In comparison with other
emission points, the costs of controlling
the fugitive emission sources mentioned
by the commenters are relatively small
compared with the amount of emission
reduction achieved.
Several commenters recommended
adding to the regulation a provision for
excess emissions during startup, shut-
down, and malfunction. EPA considered
this comment, and decided that this
addition is not necessary for the vinyl
chloride standard. Startup and shutdown
of the process has essentially no effect
on emissions to the atmosphere for poly-
vinyl chloride production, and technology
exists to avoid excess emissions during
startup and shutdown at ethylene di-
chloridevinyl chloride plants. We do not
believe plants should be allowed to emit
excess emissions during malfunctions,
and therefore are requiring them to shut
down immediately.
(3) Selection of source categories. In
the preamble to the proposed standard
EPA recognized that some small research
and development facilities may exist
where the emissions of vinyl chloride are
Insignificant and covering these facilities
under the standard would be unnecessary
and inappropriate. However, EPA did not
have sufficient information available to
clearly define which facilities should be
excluded from the standard, and
encouraged Interested parties to submit
such information during the comment
period. Based on the Information sub-
mitted, EPA decided to exempt poly-
Vinyl chloride reactors and associated
equipment from applicability of all parts
of the standard if the reactors are used
in research and development and have a
RULES AND REGULATIONS
capacity of no more than 0.19 m* (50
gal). Reactors in this size range can gen-
erally be found In a laboratory, whereas
the larger reactors are typically pilot
scale facilities. Emissions from laboratory
scale equipment are relatively small, and
application of the controls required by
the standard would be expensive and Im-
practical. EPA also decided to exempt re-
search 'and development facilities con-
taining reactors greater than 0.19 m' (50
gal) and no more than 4.07 m' (1100 gal)
In capacity from all parts of the standard
except the 10 ppm limit for reactors,
strippers, monomer recovery systems, and
mixing, weighing and holding containers.
EPA decided not to require these facili-
ties to meet other parts of the standard
because of the technical problems In-
volved in doing so. For example, the
standard for reactor opening is based In
part on reducing the frequency of open-
ing the reactor. Research and develop-
ment reactors have to be opened after
every batch for thorough cleaning. Also,
stripping technology is developed indi-
vidually for each resin In research and
development equipment. Therefore, at-
tainment of the stripping limitations in
the research and development equipment
would not always be possible. The 4.07
m' (1100 gal) figure was selected as an
upper cut-off point because there are no
commercial reactors smaller than this.
(4) Emission limits. The only major
change in the emission limits between
proposal and promulgation Is the addi-
tion of a provision for emergency manual
venting of vinyl chloride from reactors
to the atmosphere. The proposed stand-
ard prohibited all manual venting to the
atmosphere. In the preamble to the pro-
posed standard, EPA invited interested
persons to comment on whether permit-
ting manual venting to the atmosphere
could result In overall lower emissions.
There are several methods available for
preventing relief discharges from reac-
tors, one of which is manual venting of
part of the reactor contents for purposes
of cooling and reduction in pressure
within the reactor. The higher the tem-
perature and pressure within the reac-
tor, the greater the amount of vinyl
chloride which has to be removed to
bring the reactor under control. Manual
venting can be done at a lower pressure
than the pressure required to open the
relief valve. For this reason manual vent-
Ing can result in lower emissions than
would occur by allowing the reactor to
discharge through the relief valve. Fur-
thermore, a manual vent valve is under
the control of an operator and can be
closed. A relief valve may become clogged
with resin and not close. The result
would be loss of all the reactor contents.
The contents of a reactor can be man-
ually vented to a gasholder or other hold-
ing vessel. However, in some cases, such
as during severe weather conditions, sev-
eral reactors may be out of control at
one time. There would be Insufficient
holding capacity under these conditions
to manually vent the contents of all the
reactors to a gasholder. Therefore, when
all other measures to prevent relief valve
discharges have been exhausted, manual
venting will be permitted as a last resort
before the relief valve opens. The same
notification procedures are required for
manual venting to the atmosphere as are
required for relief discharges.
There are several changes In the nu-
merical emission limits in the promul-
gated standard. Except for the standard
for reactor opening loss, these changes
simply involve conversion to the Interna-
tional System of Units (Sl>. There wa<
an error Involved in the original calcula-
tion used to derive the standard for reac-
tor opening. Correcting this error dou-
bles the allowable emissions. It Is em-
phasized that the change in this stand-
ard is a correction, and not a change in
the intent for the degree of control re-
quired.
The proposed standard required the
installation of a rupture disc beneath
each relief valve to prevent leakage from
the relief valve. A provision has been
added to the promulgated standard so
that a rupture disc is not required if
the relief valve is tied into a process line
or recovery system. In this case, any
leakage from the relief valve would be
contained.
The regulation for obtaining vinyl
chloride samples has been changed to an
operating procedure. The proposed
standard stated that there were to be
no emissions from taking the samples.
Several commenters pointed out that the
use of the word "no" would make this
regulation impractical to enforce. There-
fore, the promulgated standard specifies
the operating procedure which EPA orig-
inally intended to be used to control
this source. This revision is only a change
in wording and does not represent a
change in the level of the standard.
The regulation for taking samples has
also been revised to apply only to sam-
ples containing at least 10 percent by
weight vinyl chloride. This is consistent
with the other parts of the standard
which apply to equipment "In vinyl
chloride service." "In vinyl chloride serv-
ice" distinguishes between situations
where vinyl chloride is clearly Involved
and situations where vinyl chloride is a
minor component or contaminant, and
as defined in promulgated g 61.61(1)
means that a piece of equipment con-
tains or contacts either a liquid that is
at least 10 percent by weight vinyl chlo-
ride or a gas that is at least 10 percent
by volume vinyl chloride.
The proposed standard required a vinyl
chloride monitoring system for continu-
ously measuring vinyl chloride levels both
within the plant (for leak detection) and
within stacks. The proposed standard did
not outline required specifications for the
monitoring system.-except that It was to
analyze the samples with gas chromatog-
raphy, or if all hydrocarbons were as-
sumed to be vinyl chloride, with Infrared
spectrophotometry. flame ion detection.
or equivalent. It required that each plant
submit a description of its monitoring
system to EPA. so that EPA could deter-
mine whether it was acceptable or not.
Comments were received indicating a
need for EPA to specify some criteria for
judging the. acceptability of monitoring
systems. The accuracy of the monltor-
FEQERAL MOUTH, VOL 41, NO. JOS—THUtSDAY, OCTOMI *1, If76
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IULES AND REGULATIONS
ing system would be related to the fre-
quency of calibration. Therefore, EPA
has Included in the promulgated stand-
ard requirements for the frequency of
calibration and procedures to be carried
out in the calibration of Uie monitoring
instruments.
The portable hydrocarbon detector re-
quired by the proposed standard was re-
quired to have a sensitivity of 5 ppm!
Comments were received indicating that
Instruments in this sensitivity range are
delicate and require continuing mainte-
nance. The portable hydrocarbon detec-
tor is required for leak detection and for
measuring vinyl chloride concentrations
inside the equipment before opening it.
A 5 ppm sensitivity is not needed in
either case, and the required sensitivity
has been changed to 10 ppm in the pro-
mulgated standard.
The proposed standard contained a
single regulation for compressors. The
promulgated standard has separate regu-
lations for rotating and reciprocating
compressors. This is consistent with hav-
ing separate regulations for rotating and
reciprocating pumps in both the pro-
posed and promulgated standards.
Section 61.66 of the proposed standard
provided for the use of equivalent meth-
ods of control which have been approved
by EPA. The promiUgated standard re-
quires that the plant owner or operator
submit a request for determination of
equivalency within 30 days of the pro-
mulgation date if the alternative control
method is Intended as the Initial means
of control. The purpose of this is to pro-
vide time for EPA to evaluate the method
before the plant has to be in compliance
(for existing sources, 90 days after the
promulgation date). EPA also suggests
that this request for determination of
equivalency be accompanied by a re-
quest for waiver of compliance pursuant
to section 112(c) (1) (B) (11) of the Act.
The request for a waiver for compliance
should provide for the case where EPA
determines that a method is not equiv-
alent and the plant needs to purchase
other equipment. In no case will the
waiver of compliance be extended beyond
two years from the date of promulga-
tion.
There are several wording clarifica-
tions which have been made in the pro-
mulgated standard. The definition for
"in vinyl chloride service" (560.61(1))
has been clarified by stating that it
means equipment that contacts vinyl
chloride as well as equipment that con-
tains vinyl chloride. This would include
such equipment as agitators.
Words have been added in (9 61.62,
61.63. and 61.64 to clarify that the 10
•Dprn emission limits do not have to be
met when equipment has already been
opened In compliance with the regula-
tion for opening of equipment. Equip-
ment that has met the opening of
equipment regulation can contain more
than 10 ppm vinyl chloride and would be
in violation of the standard if this
statement were not Included.
The requirements for stripping poly-
Vinyl chloride resins to specified levels
nave been revised In M 61.64 (e). 61.67
*g)(3)(li>, and 61.70(c) (2) (1) so that
measurement of the vinyl chloride levels
In the resins is to be made immediately
after stripping is completed rather than
as the resin is being transferred out of
the stripper. This allows a plant to carry
out operations in a stripper after strip-
ping has been completed but before it is
transferred out of the stripper. This is
consistent with the original Intent of the
standard.
The regulation for loading and unload-
ing lines In §61.65(b)(l) has been re-
vised to clarify that it applies only to
lines that are disconnected after each
loading or unloading operation. Perma-
nently installed pipelines that are opened
Infrequently for inspection or mainte-
nance, for example, are covered by the
opening of equipment regulation rather
than the loading and unloading line
regulation.
The regulation for inprocess waste-
water in the proposed standard could
have been misinterpreted to require In-
dividual treatment of wastewater
streams. Section 61.65(b) (9) (i) of the
promulgated standard clarifies that
wastewater streams that are required to
be treated (i.e., those containing greater
than 10 ppm vinyl chloride) can be com-
bined to be treated. However, waste-
water streams that contain greater than
10 ppm vinyl chloride cannot be com-
bined with wastewater streams that con-
tain less than 10 ppm vinyl chloride be-
fore treatment; i.e., dilution cannot be
used to meet the standard.
The commenters recommended several
changes in the emission limits which
have not been incorporated into the
promulgated standard. These are dis-
cussed in the following paragraphs.
It was recommended that the require-
ment for double mechanical seals on
pumps, compressors, and agitators be re-
moved because the single seals currently
used on this equipment have small emis-
sions and are more reliable than double
mechanical seals. EPA is aware that each
fugitive -emission source, such as one
pump, taken by Itself causes relatively
small emissions. Fugitive emissions con-
sidered as a whole are a significant
source of emissions, however, and the in-
tent of the standard is to reduce these.
Double mechanical seal pumps are com-
monly used in the industry for emission
reduction. Sealless pumps or equivalent
systems are available as options to double
mechanical seals.
The commenters recommended in-
creasing the averaging time for the 10
ppm limits and the emission limits for
reactor opening and stripping to 30 days.
Some of the commenters apparently
thought that the 10 ppm limits had to be
met on an Instantaneous basis. However,
since the performance test for determin-
ing compliance consists of three runs for
a minimum of an hour each, the aver-
aging time for the 10 ppm limit is at least
three hours. Increasing the averaging
time to 30 days for any of the emission
limits would permit higher peak emis-
sion levels. EPA has determined that this
is neither desirable nor necessary.
Some commenters requested that the
•tripping levels for dispersion resins be
made the same as for other resins and
others requested that they be made less
stringent. EPA decided not to make the
standard for stripping dispersion resins
the same as for other resins because there
Is sufficient evidence to indicate that
these resins are more difficult to strip
than other resins. With regard to mak-
ing the stripping levels for dispersion
resins less stringent, only one of the eight
manufacturers of dispersion resins spe-
cifically commented that the dispersion
resin standard should be made less
stringent. Only two of several grades of
dispersion resins made by this company
cannot meet the 2,000 ppm limit. The
proposed standard takes Into considera-
tion that some resins are more difficu't
to strip than others by providing for
averaging among different resins.
(5) Testing, reporting, and record-
keeping. There arc several relatively
minor changes in the testing, reporting,
and recordkeeping requirements. A pro-
vision has been added to § 61.67 which
requires that stack gas samples taken
with Test Method 106 are to be analyzed
within 24 hours. This is consistent with
the requirements in the proposed Test
Method 106. The promulgated standard
also specifies that in averaging the re-
sults of the three runs required by Test
Method 106, a time-weighted average is
to be used.
One commenter requested that the
oxygen content and moisture content be
specified fof the 10 ppm concentration
standards. The proposed standard speci-
fied that the vinyl chloride concentration
Is to be corrected to 10 percent oxygen
(wet basis) if combustion is used as the
control measure. In the promulgated
standard, this requirement has been ex-
panded to all control measures.
A provision has been added to the
promulgated standard which states that
If a reactor is also used as a stripper, the
reactor opening emissions may be deter-
mined immediately following the strip-
ping operation. If a reactor is also used
as a stripper, the resin is in the reactor
when it Is opened. This means that vinyl
chloride in the resin which has already
been stripped to acceptable levels can
escape from the resin and become part
of the reactor opening loss. It is EPA's
intent that once a resin has been stripped
to the required levels, that additional
controls are not required. Under the new
provision, vinyl chloride escaping from
the resin after it has been stripped to
acceptable levels is not counted as part
of the reactor opening loss.
A section requiring continuous moni-
toring of stack emissions has been added
to the promulgated standard. The con-
tinuous monitoring of stack emissions
was required in the proposed standard.
The addition of a specific paragraph for
emission monitoring serves only to
clarify the requirement.
The standard has been revised so that
the Initial report requires a "description"
rather than a "detailed description" of
the equipment used to control fugitive
emissions. Several commenters pointed
out that a detailed description .would
contain proprietary information. EPA
agrees that a detailed description in the
IIGISTER, VOL 41. NO. 205—THURSDAY,-OCTOM* 21, 1*76
III-119
-------
Initial report to unnecessary. It addi-
tional information to needed, EPA can
obtain tt under section 114 of the Act and
the plant can request confidential treat-
ment In accordance with 40 CFR Part 3
for Information tt believes to be
proprietary.
The proposed standard required that
•> semiannual report be submitted every
110 days. The promulgated standard
specifies dates for the submittal of the
reports. It also specifies that the first
aemlannual report does not have to be
submitted until at least six months after
the Initial report to submitted.
The standard has been revised to elim-
inate the requirement to record the cause
of any leak detected by the vinyl chlo-
ride detector, the action taken to repair
the leak, and the amount of time re-
quired to repair the leak. EPA to con-
cerned only that leaks are detected and
repaired. That this has been done can be
established by looking at the strip chart
record of measurements made by the
vinyl chloride detector. These records are
stm required for the portable hydrocar-
bon detector however.
Several commentators recommended
that the companies be allowed an extra
two weeks to submit to EPA data from
the Initial performance test They also
recommended that they submit the data
by regular man rather than registered
man. EPA has not adopted either of these
recommendations. A source to supposed
to be In compliance with the standard
within 00 days of the promulgation of
the standard. The standard requires that
the emission testa be done within the
90 day period, and permits an extra 30
days for determination of results. The
purpose of using registered maQ to to
document the fact that emission data
have been sent and received. This way
if the results are lost in the mall, there
will be no question that they were sent.
(0) Teat method. Test Method 100 has
been changed to recognize that on a gas
chromatograph equipped with a Chrom-
osorb 102 column, acetaldehyde may
Interfere with the vinyl chloride peak.
When a sample to expected to contain
acetaldehyde, a secondary column as de-
scribed in section 4.3.2 must be employed.
Mass spectroscopy or another absolute
analytical technique to required to con-
firm the vinyl chloride peak obtained
with the gas chromatograph, only If peak
resolution with the secondary column to
not successful.
In section 4.1.4, alumlnlzed Mylar bags
can be substituted for Tedlar bags. EPA
now has data to allow this substitution.
provided that the samples are analyzed
within 24 hours of collection.
In section 5.1.3 of Test Method 104
the requirement to use "oxygen gas" ha*
been replaced with "oxygen gas or air, at
required by the detector." Several corn-
mentors stated that most gas chromato-
graphs are designed to use hydrogen and
air for their flame detectors. When used
in this way, they are capable of detect-
ing 0.5 ppm vinyl chloride in air. This to
sensitive enough for monitoring the 10
ppm emission limits stipulated m the
standard.
IULES AND REGULATIONS
In section 6.4 of Test Method 1M the
requirement for an automatic Integrator
has been replaced with a requirement for
a disc integrator or planimetar for meas-
uring peak area. This change to m re-
sponse to a comment which states that
automatic Integrators are unnecessarily
elaborate and expensive.
A new section 6.5 has been added to
Test Method 106 which requires deter-
mination of the water vapor content of
the sampling bag by measuring the am-
bient temperature and pressure near the
bag. The vinyl chloride concentration of
the bag can then be reported on a dry
basis. A provision for checking the rigid
container for leaks has been added to
section 7.4 of Test Method 106.
The only change in Test Method 107 to
the provision in Section 5.3.2 for use of
Carbopak C as well as Carbopak A.
AUTHORITY: Section 113 of the Clean Air
Act u added by iec. 4(a) of Pub. L. 91-404,
M Stat. 1888 (43 U.8.C. 18670-7; Section 114
of the Clean Air Act, as added by sec. 4(a)
of Pub. I» 91-404, 84 Stat. 1687, and amended
by Pub. L. 93-319. eec. 6(a) (4), 88 Stat. 369
(43 U.S.C. 18670-9); Section 801 (a) of the
Clean Air Act, M amended by «ec. 15(c) (3)
of Pub. U 91-004, 84 Stat. 1713 (43 VB.O.
1867g(a)).
Dated: October 12, 1976.
JOHN QUARLCS,
Acting Administrator.
NDEIAl ttGISTH, VOL 41, NO. 103-
-THl/ISDAT, OCTOMI It, We
III-120
-------
PROPOSED RULES
ENVIRONMENTAL PROTECTION
AGENCY
[40CFRPart61]
(PRL 738-6]
VINYL CHLORIDE
National Emission Standards for Hazardous
Air Pollutants
AGENCY: Environmental Protection
Agency.
ACTION: Proposed rule.
SUMMARY: The proposed amendments
are being made to the vinyl chloride
standard which has promulgated Octo-
ber 21, 1976, and would apply to new
and existing ethylene dlchloride, vinyl
chloride, and polyvinyl chloride plants.
The standard and the proposed amend-
ments Implement the Clean Air Act and
are based on the Administrator's deter-
mination that vinyl chloride Is a hazard-
ous air pollutant. The Intended effect of
the proposed amendments Is to require
Improved effectiveness of control tech-
nology at existing plants. Impose more
stringent emission limits on new sources,
and prohibit an emission Increase within
the vicinity of an existing source due to
the construction of a new source.
DATES: Comments must be received on
or before August 1,1977.
ADDRESSES: Comments should be sub-
mitted (preferably in triplicate) to the
Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina, Attention: Mr. Don R. Good-
win.
All public comments received may be
inspected and copied at the Public In-
formation Reference Unit (EPA Li-
brary), Room 2922, 401 M Street, SW.,
Washington. D.C.
FOR FURTHKK 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:
BACKGROUND
On October 21,1976, EPA promulgated
• standard for vinyl chloride under the
authority of section 112
-------
MtOPOSED RULES
meet the 10 ppm emission limit be re-
moved and replaced with another more
efficient control system or that a second
control system be added behind the first
control system. The purpose of the pro-
posed amendment Is to force owners and
operators to maximize the effectiveness
of existing control systems.
MOU SmiNGEKT 8TANDAKM FOR NEW
Bounces
The proposed amendments would also
require more stringent controls for new
sources; I.e., sources for which construc-
tion Is commenced after the date of pro-
posal of these amendments. According
to S 61.02 of the General Provisions,
"commenced" means that an owner or
operator has undertaken a continuous
program of construction or modification
or that an owner or operator has entered
tnto a contractual obligation to under-
take and complete, within a reasonable
time, a continuous program of construc-
tion or modification.
New sources of types which would be
subject to the 10 ppm emission limit
under the current standard would be
required under the amendments to meet
a 5 ppm emission limit at the time of
startup. With new sources there would be
no provision allowing requests for EPA
approval of an Interim emission limit.
New sources would be required to meet
the more stringent emission limit at the
time of startup, because they have an
opportunity to design their equipment to
meet the 5 ppm emission limit at the time
construction is commenced. Existing
sources, on the other hand, require time
to maximize the effectiveness of their
control systems.
The proposed amendment would also
require ethylene dlchloride-vlnyl chlor-
ide plants to control emissions from new
oxychlorlnation reactors to 5 ppm. This
requirement Is based on installation of
a recycling and oxygen feed system with
an incinerator or equivalent control de-
vice. The current standard limits emis-
sions from the oxychlorlnation reactor
to 0.2 g/kg (0.0002 Ib/lb) of the 100 per-
cent ethylene dichloride product from
the oxychlorlnation reactor. This emis-
sion limit can be met by changing proc-
ess parameters, rather than Installing a
control device. During the development
of the current standard EPA considered
requiring existing sources to control
emissions with an Incinerator or equiva-
lent technology, but rejected this ap-
proach because a large quantity of fuel
would be required to reduce emissions
from a relatively small source. An exist-
ing oxychlorination reactor typically has
a large volume, low hydrocarbon effluent
gas stream, and large quantities of sup-
plemental fuels would be required for
combustion of its emissions.
A new plant can reduce the volume of
Its effluent gas stream and make it more
concentrated by recycling the gas stream
and using oxygen instead of air to feed
Into the process. (3, 4) the current
standard was not based on this technol-
ogy because it was not considered feasi-
ble to retrofit existing plants so that they
could use oxygen Instead of air. The re-
cycling and oxygen feed methodolgy te
considered feasible for new oxychlorlna-
tion reactors because It can be.Incorpo-
rated at the time of construction. Since
the use of this technology would elimin-
ate the supplemental fuel problem re-
ferred to above, it Is EPA's Judgment that
new oxychlorlnation reactors should be
controlled to the same extent that Is
proposed for other emission sources.
The proposed amendment also Includes
a more stringent emission limit for new
polyvinyl chloride resins being processed
In equipment following the stripping
operation. That is, the amendment
would apply to resins for which produc-
tion for the purpose of marketing was
commenced after the proposal of the
amendment. The amendment would re-
quire all new resins except new disper-
sion resins to be stripped to 100 ppm and
new dispersion resins to be stripped to
500 ppm. These limits for new products
"would be one-fourth of the limits con-
tained in the standard for existing prod-
ucts. Consistent with the current stand-
ard, the amendment would permit the
use of control devices rather than strip-
ping technology to meet the emission
limit. In this case equipment being used
to process all new resins except new dis-
persion resins would have to be con-
trolled to' 0.01 kg/kg product and the
equipment used for new dispersion resins
would have to be controlled to 0.05 kg/kg
product.
A "new source" to denned in 40 CPR
61.02 as a stationary source, the con-
struction or modification of which Is
commenced after proposal of a standard.
There was some question based on this
definition as to whether the amendment
to the stripping standard for new sources
should apply to new polyvinyl chloride
resins or the Installation of new equip-
ment following the stripper. If the ap-
plicability of the amendment for new
sources were based on the Installation of
new equipment following the stripper, it
would be difficult to determine what con-
stitutes a new source at an existing plant
This is based on the reasoning that the
stripping standard requires that all
equipment following the stripper in the
process be controlled as a unit. The series
of equipment following the stripper In-
cludes pumps and conveying equipment
which might be expected to be replaced
on a frequent and routine basis. Replac-
ing one of these pieces of equipment
would in effect cause the whole series of
equipment following the stripper to have
to meet the standard for new sources. In
other words, all resins processed In the
series of the equipment would have to
meet the lower standard even though
only a minor part of the«equlpment had
been replaced.
EPA decided that a more reasonable
and direct approach was to make the
proposed amendment apply to the pro-
duction of new polyvinyl chloride resins.
This is based on the reasoning that emis-
sions from the equipment following the
stripper are a function of the amount of
vinyl chloride left in the resin after the
stripping operation Is completed; I.e.,
the resin is the source of the emissions
rather "than the equipment The same
equipment can be used to process differ-
ent resin grades. Variations in the emis-
sions from the equipment are a function
of the resin being processed rather than
the characteristics of the equipment. The
control technology which is used for the
equipment following the stripper is like-
wise more directly linked to the resin
than the equipment. Stripping is used to
control the emissions due to the vinyl
chloride in the resin before the resin is
processed in the equipment.
Before the hazards of vinyl chloride
became known, stripping technology was
employed by polyvinyl chloride manu-
facturers to recover raw materials for
economic purposes. As a result of a
standard promulgated by the Occupa-
tional Safety and Health Administration
(39 PR 35890), some companies investi-
gated improvements in stripping meth-
odology for emission control purposes.
U)
Optimum stripping consists of a set of
operating conditions which must be de-
veloped experimentally on an individual
basis for the many resins. In developing
the current standard, EPA recognized
that stripping technology for dispersion
resins had not been refined to the same
extent as it had been for other resins and
that there was more difficulty in strip-
ping dispersion resins than other resins.
For this reason a less stringent emission
limit was established for dispersion res-
ins. Dispersion resins are permitted a
higher emission limit under the proposed
amendment for the same reason.
EPA believes that for some resins,
companies have already developed strip-
ping technology which would meet the
proposed amendment. (2) For other
resins, the proposed standard would re-
quire additional improvement in strip-
ping technology. If stripping technology
has not been developed to the extent
necessary to meet the proposed amend-
ment for a particular resin, the manu-
facturer would have the option of de-
veloping the technology or not producing
the resin.
The current standard, unlike the
proposed amendment, was not based on
the premise that an owner or operator
would have the option of not producing
a particular resin. It is EPA's judgment
that the owner or operator making a new
product has more freedom of choice than
the owner or operator already making a
particular product in selecting those
resins which are to be produced. EPA's
standard would be Included in the
variables under consideration when
decisions are being made as to which
resins are to be produced.
The proposed amendment would apply
to any new source, whether it constituted
replacement of an existing source in an
existing plant, the expansion of an exist-
ing plant, or part of an entirely new
plant. That is, if a new oxychlorination
reactor or a new polyvinyl chloride re-
actor were installed at an existing plant,
it would be subject to the emission limits
for new sources. This means that as
existing sources are gradually replaced
with new sources in an existing plant,
flORAL IfOISTiR, VOL. 42, NO. 10*—THURSDAY, JUNE 1, 1977
111-122
-------
PROPOSED RULES
the overall emission level from that
existing plant would be reduced.
EMISSION OFFSET
Because the present vinyl chloride
standard focuses on reducing emissions
rather than attaining a particular am-
bient air quality concentration, there Is
no provision for limiting the size of
plants or the clustering of plants In a
geographical area. The doubling of the
size of an existing plant or the construc-
tion of a new plant beside an existing
plant would considerably Increase the
ambient air concentrations of vinyl
chloride In the vicinity of the plant (s)
even If the vinyl chloride standard was
met. EPA determined at the time of
promulgation of the current standard
that the costs of prohibiting the produc-
tion of vinyl chloride and polyvlnyl
chloride were too high and the continued
operation of existing plants should be
allowed. EPA believes, however, that the
standard should include a mechanism
for prohibiting an increase In ambient
concentrations of vinyl chloride due to
new construction in areas where existing
sources are already located.
Accordingly, EPA is proposing an
amendment which would prohibit an In-
crease In emissions within 8 kilometers
(km) (approximately five miles) of an
existing source due to the construction
of a new emission source. This means
that If a new source were added to an
existing plant, the Increase in emissions
due to that new source would have to be
offset by a reduction In emissions from
other existing sources within that plant
or at other plants within 8 km of the
construction site of the new source. Simi-
larly, a new plant could not be con-
structed within 8 km of an existing
plant(s) unless the emission increase
due to the new plant were offset by an
emission reduction at the existing plant
or plants. This provision may result in
few existing plants being expanded and
few new plants being constructed in the
vicinity of existing plants. However, the
proposed amendment does not preclude
this possibility.
The offset provision would apply only
to new construction which results in an
Increase in production rate. Replacing or
adding equipment such as pumps, com-
pressors, agitators', sampling equipment
and unloading hoses is a routine practice
at existing plants. Additions of equip-
ment of this nature would, in and of it-
self, be expected to result in little, if any,
increase in emissions. In EPA's judg-
ment, a plant should not be required to
prove this fact each time one of these
pieces of equipment is added. The addi-
tion of this type of equipment in con-
junction with major process equipment,
however, is likely to result in both an in-
crease In emissions as well as an in-
crease In production rate, and is there-
fore covered by the offset provision.
If the offset provision were adopted,
the reduction In emissions could be
achieved In the production rate of an
existing source or sources. The baseline
emission rate would be determined based
on the maximum production rate which
had been attained by each existing
source. The allowable emission rate for
each source would be based on the maxi-
mum production rate at which that
source would be operated In the future.
Also, If the emissions from an existing
source were already below the emission
limit applicable to It, the proposed
amendment would give the source credit
for the difference between the emission
limit and the actual emission level. That
is the baseline emission rate would be
based on the standard rather than on an
emission test. It Is EPA's judgment that
this is a more equitable approach than
penalizing a source which has already
taken measures to reduce emissions below
the standard. Such a source would have
less room for further reducing emissions.
The emission limits applicable to both
the existing and new sources Involved
In the offset arrangement would be con-
tained In the approval of new construc-
tion granted by the Administrator under
40 CPR 61.08.
EPA believes that a policy of no net
Increase In emissions due to new con-
struction is justified because of the haz-
ardous nature of vinyl chloride. How-
ever, EPA recognizes the potential diffi-
culties In Implementing such a policy
and Interested persons are urged to sub-
mit comments and factual information
relating to this policy.
REVIEW OF STANDARD
EPA plans to undertake a full-scale
review of Subpart P of 40 CPR Part 61
beginning three years from the promul-
gation of any amendments. In the study
EPA will review information concerning
technological advances In the control of
vinyl chloride emissions to determine
what further changes might then be ap-
propriate to move toward the goal of
zero vinyl chloride emissions. EPA will
also consider recent health data to de-
termine whether the approach for regu-
lating vinyl chloride should be altered.
ENVIRONMENTAL IMPACT
The proposed amendment, In contrast
to the current standard, would encourage
the development of new technology and
improvements in existing technology and
would have the following three positive
environmental impacts: (1) further re-
duction of emissions at existing plants,
(2) no Increase in emissions within 8 km
of an existing source, and (3) lower
emissions from new sources than would
be accQmpllshed through the current
standard regardless of the'construction
site. These environmental Impacts would
provide progress toward the ultimate
goal of zero emissions without banning
vinyl chloride, and in the process would
provide additional protection of public
health by further minimizing the health
risks to the people living in the vicinity
of existing plants and to any additional
people who are exposed as a result of new
construction.
Specifically, for those existing sources
which are currently subject to a 10 ppm
emission limit, emissions would be re-
duced by half within three years after
the promulgation date of these amend-
ments. At both an existing average-sized
ethylene dlchloride-vlnyl chloride plant
and an existing average-sized polyvinyl
chloride plant, which contain other
sources than the ones required to meet
a 5 ppm emission limit, It Is estimated
this will have the effect of reducing total
emissions by less than one percent. Emis-
sions at existing plants would be further
reduced as existing oxychlorlnatlon re-
actors are replaced with new oxychlori-
natlon reactors and as new polyvinyl
chloride resins are preduced to replace
existing ones.
Under the proposed amendment, emis-
sions from new plants would be consider-
ably lower than they would be under the
current standard. For a typical new
average-sized ethylene dichloride-viny)
chloride plant (318x10' kg/yr or 700
XlO" Ib/yr produced), the hourly emis-
sions would be 5.1 kg (11.5 Ib) Instead
of 10.3 kg (23.1 Ib). For a typical new
average-sized dispersion polyvinyl chlo-
ride plant (46x10' kg/yr or 100x10"
Ib/yr production), the emissions would
be about 9 kg/hr (20 Ib/hr) Instead of
17.5 kg/hr (39 Ib/hr) and for a typical
new average-sized suspension polyvinyl
chloride (68xlOe kg/yr or 150x10' Ib/yr
production) the emissions would be 13.5
kg/hr) (30 Ib/hr) Instead of 16 kg/hr
(36 Ib/hr). These emissions are calcu-
lated based on the emission factors pub-
lished In the documentation for the ex-
isting standard. U) Ambient air concen-
trations are expected to be reduced
proportionately.
The only negative environmental im-
pact would be an increase in hydrogen
chloride emissions at ethylene dlchlo-
ride-vlnyl chloride plants If Incineration
were used to control emissions from new
oxychlorination reactors. However, due
to the corrosion problems which would
otherwise occur on plant property and
in the community, plants are expected
to use scrubbers to control the hydrogen
chloride emissions. The proposed amend-
ment is not expected to have a signifi-
cant impact on energy consumption.
ECONOMIC IMPACT
The potential economic Impacts of the
proposed standard are:
(1) Costs for research and develop-
ment of Improved methodology for oper-
ation of existing control technology so
that it can be used to meet the 5 ppm
emission limit.
(2) Costs for research and develop-
ment of Improved stripping techniques
to meet the standard for new polyvinyl
chloride resins.
(3) Cost of research and development
or licensing for converting over to the
oxygen system for a new oxychlorination
reactor.
(4) Possibly'Increased transportation
costs of raw materials in the case that
the offset policy results in the construc-
tion of a new plant farther from an
existing plant than it otherwise would
have been.
(6) Costs of building a new plant more
than 8 km from an existing plant in the
event that the offset requirement pre-
cluded the expansion of an existing
Plant.
FIDfRAl REGISTER, VOl 42, NO. 106—THURSDAY, JUNI 1, 1*77
III-123
-------
PROPOSED RUIES
(6) Delay in the production of a par-
ticular resin due to .time spent develop-
ing stripping technology for that resin.
(7) No growth in the production of a
particular resin due to the inability to
strip that resin to required levels.
The types of costs which have been
named would be difficult to quantify. The
costs would be expected to vary consider-
ably from one plant to another depend-
ing on the amount of research and de-
velopment than had already been done,
• the extent to which technology could be
transferred from other plants and proc-
esses, and the plans for new construction.
One area in which cost estimates can
• be generated is the use of an oxygen-
recycle oxychlorination process as op-
posed to an air-based system. The pro-
posed amendment does not require the
use of the oxygen-recycle system, but
many plants would be expected to em-
ploy this system to avoid the high costs
of Incinerating the high volume gas
stream from a typical air-based system.
The primary cost of using the oxygen-
recycle system is the cost of the oxygen
Itself. The cost of the oxygen for a par-
ticular plant would depend on whether
the plant was located where there is a
considerable demand for both the oxygen
and nitrogen products of air separation.
According to one recent article, if it is
assumed that such a demand exists, the
cost of the oxygen ($14.34/ton) would
be approximately equivalent to the cost
of compressing air for use in the alr-
based system. (1) Another report In
which this assumption was not made and
the economics of the air and oxygen sys-
" terns were being compared, it was con-
cluded that overall production economics
"favor the oxygen process even if vent
gas incineration would not be required
for an air-based plant since the sum of
all remaining advantages offered by
oxygen-based plant operation more than
outweighs the incremental cost for the
oxygen feed." (2)
Miscellaneous: The Administrator in-
vites comments on all aspects of the pro-
posed amendments.
(Section 113 of the Clean Air Act, sec. 4(a) of
Pub. L 91-604, 84 Stat. 1685 (42 U.S.C. 1857c-
7) and section 301 (a) of the Clean Air Act.
sec. 2 of Pub. L. No. 90-148, 84 Btat. 604 as
amended by sec. (IS) (c) (2) of PUD. L. 91-604,
84 Stat. 1713 (42 U.8.C. 18S7 g(tt)). Sees.
61.67 and 61.68 also proposed under the au-
thority of section 114 of the Clean Air Act,
as added by sec. 4(a) of Pub. L. 91-604, 84
Btat. 1687 and amended by Pub. L. 93-319,
sec. 6(a)(4). 88 Stat. 259 (42 D.S.C.
1B57C-9).)
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: May 27,1077.
DOUGLAS M. COSTLE,
Administrator.
RxrnutNcx*
(1) Standard Support and environmental
Impact Statement: Emission Standard for
Vinyl Chloride, EPA-460 12-75-009, October,
1976.
(2) "Ooodrlch Reports Impressive Progress
In Solving Vinyl Chloride Problem." Ameri-
can Paint and Coatings Journal, Vol. 60, No.
31, January 12, 1976, p. 24.
(3) E. W. Wlmer and R E. Feathers, "Ox-
ygen Gives Low Cost VCM," Hydrocarbon
Processing, March 1976, pp. 81-84.
(4) Peter Reich. "Air or Oxygen For
VCM?," Hydrocarbon Processing, March,
1976, pp. 86-86.
It is proposed that Subpart F of 40
CFR Part 61 be amended as follows:
1. In § 61.08, paragraph (b) is revised
to read as follows:
§ 61.08 Approval by the Administrator.
*****
(b) If the Administrator determines
that a stationary source for which an
application pursuant to {61.07 Was sub-
mitted will not, if properly operated,
cause emissions in violation of the
standard or violation of { 61.73, he will
approve the construction or modification
of such source.
2. Section 61.62 is revised-to read as
follows:
§ 61.62 Emission standard for ethylene
dichloride plants.
An owner or operator of an ethylene
dichloride plant shall comply with the
requirements of this section and { 61.65.
(a) Ethylene dichloride purification:
Except as provided in §61.65
-------
PROPOSED RULES
of proposal of these amendments), 10
ppm until (date three years after pro-
mulgation of these amendments) and S
ppm after (date three years after pro-
mulgation of these amendments).
(2) Each source for which construc-
tion commence after June 2, 1977, 5
ppm.
, (b)
(2), (b)(3), (b)(5), (b)(6), and/or
(9), within 90 days following (date three
years after the promulgation date of
these amendments).
(2) For a new source for which initial
startup occurs after October 21, 1976.
within 90 days of startup.
• • • • •
7. In t 61.68, paragraph (c) Is revised
to read as follows:
§ 61.68 Emission monitoring.
• • • » •
(c) A dally span check is to be con-
ducted for each vinyl chloride monitor-
ing system used. For all of the sources
listed in paragraph (a) of this section,
except for the one for which an emission
limit is prescribed in { 61.62(b) (1), the
daily span check is to be conducted with
a concentration of vinyl chloride equal to
the concentration emission limit appli-
cable to it. For a source subject to the
emission limit prescribed in { 61.62.(b)
(1), the daily span check is to be con-
ducted with a concentration of vinyl
chloride which is determined to be
equivalent to the emission limit for that
source based on the emission test re-
quired by t 61.67. The calibration Is to be
done with either:
• 4 • • •
8. A new (61.72 is added to read as
follows:
§ 61.72 RequrM for interim emi««ion
limit.
(a) If in the opinion of the owner or
operator of an existing source, that
source will be unable to comply with the
5 ppm emission limit in {§ 61.62(a) (1);
61.63(a)(l); 61.64 (a)(l)(i), M>,
(c)(l), (d>(l); and/or 61.65(cMl> on
or before (date three years after pro-
mulgation of these amendments), the
owner or operator of that source may re-
quest that the Admlnstrator approve an
interim emission limit for that source.
The request is to be in writing and is to
be submitted to the Administrator within
six months prior to (date two years after
promulgation of these amendments).
The request is to Include:
(1) The reasons the source is in-
capable of being in compliance with the
5 ppm emission limit and data to support
those reasons, and
ffDIRAl UGISTER. VOl. 42, NO. 106—THURSDAY, JUNE 2, 1*77
III-125
-------
(2) A suggested interim emission limit
and description of the methodology for
attaining that limit.
(b) Any owner or operator of a source
who has submitted to the Administrator
a written request for an interim emis-
sion limit In accordance with ( 61.72(a),
Shall within 60 days of the date of the
written request meet with the Admin-
istrator concerning the information con-
tained in the request. The meeting is to
' be open to Interested persons, who are
to be allowed to submit oral or written
testimony relevant to compliance of the
source.
' (c) The Administrator will within 120
days of receipt of the written request
required by paragraph (a) of this sec-
tion, notify the owner or operator in
writing of approval or denial of approval
of an Interim emission limit.
(d) If an Interim emission limit is ap-
proved the notification Is to Include the
level of the interim emission limit, which
may be the level requested or a more
stringent one.
(e) A determination to deny approval
of an Interim emission limit is to set
forth the specific grounds on which such
denial Is based.
(f) Approval for any Interim emission
Dmit granted for any source under
( 61.72(c) shall expire three years from
the date of Issuance. The owner or op-
erator may request an extension of ap-
proval for an Interim emission limit or a
lower interim emission limit. The re-
quest is to be In writing, is to be sub-
mitted within six months prior to a year
before the expiration date and Is to In-
clude the Information listed In I 61.72
(b), (c), (d), and (e) are to apply.
9. A new S 61.73 is added to read as
follows:
§ 61.73 Offset of emlMioni due to new
construction.
(a) No owner or operator is to con-
struct a new source which alone or in
combination with other sources 'being
constructed at the same time results in
an increased production rate unless he
demonstrates to the Administrator's sat-
isfaction that such construction will not
cause an Increase in vinyl chloride emis-
sions within 8 km of any other source
which is subject to this subpart.
(b) Reduction in production rate is
an allowable mechanism for attaining an
offset in emissions.
(c) The baseline emission rate is to be
determined based on the level of emis-
sions allowable by the standard.
(d) Reducing emissions from an In-
terim emission limit to the standard for a
source is not an acceptable means of
achieving an emission offset.
(e) In the application for approval of
construction required by I 61.07, owners
or operators of sources subject to this
subpart shall Include, in addition to the
information required by i 61.07, the fol-
lowing information:
(1) The name, address, and location
of any plant subject to this subpart
which is located within 8 km of the pro-
posed location of the source to be con-
structed.
PROPOSED RULES
(f) The emission limits applicable to
both the new source (s) and the source(s)
at which emissions are being reduced to
balance the Increase In emissions due to
the new construction are to be estab-
lished by the Administrator in the ap-
proval for construction required by
I 61.08.
(Sees. 112 and 801 (t) of the Clean Air Act.
MC. 4 (a) Of Pub. L. No. 91-004, B4 8t»t. 1083;
MC. 2 of Pub. L. No. 90-148, 81 Btat. 604 (42
U.S.C. 185&C-7, 1867g(a)>. Sees. 01.67 and
BLOB also Issued under sec. 114 of the Clean
Air Act, 0ec 4(a) of Pub. L. No. 91-604, 84
8Ut. 1687 (42 U.8.C. 18B7C-9).)
|PR Doo.77-16672 Piled 6-l-77;8:45 am)
KDItAL IIOISTIR, VOl.-42, NO. 106-
—THURSDAY, JUNE 2, 1977
III-126
-------
SUMMARY TABLES OF MONITORING INFORMATION
Table #
2
3
4
6
7
8
9
10
11
12
13
14
15
16
Subject
NSPS Cource Categories Required
to Continuously Monitor
Operational Monitoring Requirements
Emission Limitations
Proposal and Promulgation Dates for
NSPS Source Categories
NSPS Continuous Monitoring
Requirements
Quarterly Reporting Requirements
Definitions of Excess Emissions
Spanning and Zeroing
Span Specifications
Notifications Requirements
Specification Requirements
Performance Specifications
Regulation
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS
NSPS and SIP
When to Run Monitor Performance Test NSPS
Requirements for SIP Revisions SIP
Existing Sources Required to SIP
Continuously Monitor Emissions
NESHAP Monitoring Requirements NESHAP
for Vinyl Chloride Sources
III-127
-------
SUBPART
D
G
H
J
N
Q
R
TUVWX
Table #1
SOURCE CATEGORIES REQUIRED TO
CONTINUOUSLY MONITOR
SOURCE CATEGORY
Steam Generators
Solid Fossil Fuel
Liquid Fossil Fuel
Gaseous Fossil Fuel
Nitric Acid Plants
Suifuric Acid Plants
Petroleum Refineries
POLLUTANT
Opacity
S02
NOX
Opacity
SO2, NOX
NOX
S02
S02
Opacity
CO
S02
H2S
TRS
Iron and Steel Plants
Primary Copper Smelters Opacity
S02
Primary Zinc Smelters Opacity
S02
Primary Lead Smelters Opacity
S02
Phosphate Fertilizer
Plants
Coal Preparations Plants
PROCESS
02 or C02
02 or C02
02 or C02
Pressure loss
through venturi
scrubber
water supply
pressure
Total pressure
drop across process
scrubbing systems
exit gas temp.
pressure loss
through venturi
water supply
pressure to control
equipment.
T T T _ 1 <» O
-------
Table ffl, continued
SUBPART
Z
SOURCE CATEGORY
POLLUTANT
AA
Ferroalloy production Opacity
facilities
Steel Plants: Opacity
Electric Arc Furnaces
BB
Kraft Pulp Mills
Opacity
TRS
HH
Lime Manufacturing
Plants
Rotary Lime Kilns
Opacity0
Lime Hydrator
PROCESS
flowrate through
hood .
furnace power
input
Volumetric flow
rate through each
each separately '
ducted hood.
pressure in the
free space inside
the electric arc
furnace.
Temperature
Pressure loss of
the gas stream
through the
control equipment
scrubbing liquid
supply pressure
pressure loss of
steam through the
scrubber
scrubbing liquid
dupply ptrddutr
scrubbing liquid
flow rate
measurement of the
electric current
(amperes) used by
the scrubber
Does not apply when there is a wet scrubbing
emission control device.
III-129
-------
Table #2
OPERATIONAL MONITORING REQUIREMENTS (NSPS)
(Non-continuous)
Subpart
Requirement
E. Incinerators
F. Portland Cement
Plants
G. Nitric Acid Plants
H. Sulfuric Acid Plants
J. Petroleum Refineries
K. Storage Vessels for
Petroleum Liquids
III-130
Daily charging rates and hours
of operation.
Daily production rates and kiln
feed rates.
Daily production rate and hours
of operation.
The conversion factor shall be
determined, as a minimum, three
times daily by measuring the
concentration of sulfur dioxide
entering the converter.
Record daily the average coke
burn-off rate and hours of
operation for any fluid catalytic
cracking unit catalyst regenerate
subject to the particulate or
carbon monoxide standard.
Maintain a file of each type of
petroleum liquid stored and the
dates of storage. Show when
storage vessel is empty.
Determine and record the average
monthly storage temperature and
true vapor pressure of the pe-
troleum liquid stored if :
(1) the petroleum liquid, as
stored, has a vapor pressure
greater than 26 mm Hg but less th
78 mm and is stored in a storage
vessel other than one equipped
with a floating roof, a vapor
recovery system or their equiva-
lents; or
(2) the petroleum liquid has a ti
vapor pressure, as stored, greate
than 470 mm Hg and is stored in a
storage vessel other than one
equipped with a vapor recovery
system or its equivalent.
-------
Subpart
Requirement
0,
T.
U.
V.
w.
X.
Sewage Treatment
Plants
Primary Copper
Smelter
Primary Aluminum
Reduction Plants
Phosphate Fertilizer
Industry: Wet-Process
Phosphoric Acid Plants
Phosphate Fertilizer
Industry: Superphosphoric
Acid Plants
Phosphate
Industry:
Phosphate
Fertilizer
Diammonium
Plants
Phosphate Fertilizer
Industry: Triple
Superphosphate Plants
Phosphate
Industry
Fertilizer
III-131
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
incinerator.
Keep a monthly record of the
total smelter charge and the
weight percent (dry basis) of
arsenic, antimony, lead, and
zinc contained in this charge.
Determine daily, the weight of
aluminum and anode produced.
Maintain a record of daily
production rates of aluminum
and anodes, raw material c—
rates, and
voltages.
feed
cell or potline
Determine the mass flow of
phosphorus-bearing feed
material to the process.
Maintain a daily record of
equivalent
P2°5
feed.
flow
feed
Determine the mass
phosphorus-bearing
to the process.
Record daily the equivalent
of
material
P2°5
feed.
Determine the mass flow of
phosphorus-bearing feed material
to the process.
Maintain a daily record of
equivalent
P2°5
feed.
Determine the mass flow of
phosphorus-bearing feed material
to the process.
Maintain a daily record of
equivalent P^Oc feed.
Maintain an accurate account
of triple superphosphate in
storage.
Maintain a daily record of
total equivalent P^Or stored.
-------
Snlvpa r (
l;er ro;i 1 1 oy Product ion
Facilities
AA. Steel Plants:
Electric Arc Furnaces
III-132
Rcqu i rjM
Maintain daily records of (1)
the product; (2) description
of constituents of furnace
charge, including the quantity,
by weight; (3) the time and
duration of each tapping period
and the identification of
material tapped (slag or product);
(4) all furnace power input
data; and (5) all flow rate data
or all fan motor power consump-
tion and pressure drop data.
Maintain daily records of (1)
the time and duration of each
charge; (2) the time and
duration of each tap; (3)
all flow rate data, and (4)
all pressure data.
-------
Table #3
EMISSION LIMITATIONS (NSPS)
SUBPART
POLLUTANT
EMISSION LEVELS
D Fossil Fuel-Fired
Steam Generators
Liquid fossil
fuel
Solid fossil
fuel
Gaseous fossil
fuel
Mixture of
fossil fuel
*x = percentage of total
y = percentage of total
z = percentage of total
Particulate
Opacity
so2
N0x
Particulate
Opacity
S02
NO
x
Particulate
Opacity
N0x
Particulate
Opacity
S02
N0x
heat input from
heat input from
heat input from
43 ng/joule,-
(0.10 lb/10 BTU)
20%, 40% 2 min/hr
340 ng/joule
(0.80 lb/10 BTU)
130 ng/joule
(0.30 lb/10 BTU)
43 ng/jouler
(0.10 lb/10 BTU)
20%, 40% 2 min/hr
520 ng/joule
(1.2 lb/10 BTU)
300 ng/joule
(0.70 lb/10°BTU)
43 ng/joule,
(0.10 lb/10° BTU)
20%, 40% 2 min/hr
86 ng/joule,.
(0.20 lb/10° BTU)
43 ng/joule,.
(0.10 lb/10°BTU)
20%, 40% 2 min/hr
y(540) + z(520) *
y + z
x(86) + y(130) + z(300)
x + y + z
gaseous fossil fuel
liquid fossil fuel
solid fossil fuel
III-133
-------
Table #3, continued
SUBPART
E Incinerators
F Portland Cement
Plants
Kiln
Clinker cooler
Other emission
points
G Nitric Acid Plants
II Su If uric Acid
Plants
I Asphalt Concrete
Plants
J Petroleum
Refineries
fluid catalytic
cracking unit
POLLUTANT
Particulate
Particulate
Opacity
Particulate
Opacity
Opacity
Opacity
S00
H2S04 mist
Particulate
Opacity
Particulate
Opacity
CO
EMISSION LEVELS
0.18 g/dscm
(0.08 gr/dscf)
(corrected to 12% C02)
0.15 kg/metric ton
(0.30 Ib/ton)
10%
0.05 kg/metric ton
of feed
(0.10 Ib/ton)
20%
10%
1.5 kg/metric tons
of acid produced
(3.0 Ib/ton of acid
produced)
10%
2 kg/metric tons
of acid produced
(4.0 Ib/ton of
acid produced)
0.075 kg/metric tons
of acid produced
(0.15 Ib/ton)
90 mg/dscm
(0.04 gr/dscf)
20%
1.0 kg/1000 of
coke burn-off
30%
0.050%
III-134
-------
Table #3, continued
SUBPART
Glaus sulfur
recovery plant
'OLLUTANT
S02
Trs
EMISSION LEVELS
0.0251
0.030%
0.0010!
Storage Vessels
for Petroleum
Liquids
Hydrocarbons
L Secondary Lead
Smelters
Reverberatory
and blast
furnaces
Pot furnaces
M Secondary Brass
and Bronze Plants
Reverberatory
furnaces
Blast and elec-
tric furnaces
Particulate
Opacity
Opacity
Part iculate
Opacity
Opacity
N Iron and Steel Plants Particulate
(BOPF) Opacity
0 Sewage Treatment
Plants
P Primary Copper
Smelters
Dryer
Particulate
Opacity
Particulate
HI-135
If vapor pressure is
78-570 mm Hg the stor-
age vessel shall be
equipped with a float-
ing roof or a vapor
recovery system or thin
equivalents. If vapor
pressure is greater than
570 mm Hg, the storage
vessel shall be equipped
with a vapor recovery
system
50 mg/dscm
(0.022 gr/dscf)
20 £
10°u
50 mq/dscm
(0.022 gr/dscf)
20°u
50 mg/dscm
<20% may occur
steel productioi
10%
>10% but
once per
cycle
0.65 g/kg dry sludge
input (1.30 Ib/ton)
20%
50 mg/dscm
(0.022 gr/dscf)
-------
Table # 3, continued
SUBPART
Roaster, smelting
furnace, copper
converter
POLLUTANT
Opacity
SO.
Opacity
Primary Zinc Smelters
Sintering machine Particulate
Roaster
R Primary Lead Smelters
Blast or rever-
beratory furnace,
sintering ma-
chine discharge
end
Sintering ma-
chine, electric
smelting furnace
converter
S Primary Aluminum
Reduction Plants
Soderberg
plants
Prebake
plants
Anode bake
pi ants
Opacity
S07
£*
Opacity
Particulate
Opacity
SO-
Opacity
Total
fluorides
Opacity
Total
fluorides
Opacity
Total
fluorides
Opacity
EMISSION LEVELS
20%
0.065%
20%
50 mg/dscm
(0.022 gr/dscf)
20%
0.065%
20%
50 mg/dscm
(0.022 gr/dscf)
20%
0.065%
20%
1 kg/metric ton of
Al produced
(2 Ib/ton)
10%
0.95 kg/metric ton
of Al produced
(1.9 Ib/ton)
10%
0.05 kg/metric ton
of Al produced
20%
III-136
-------
Table #' 3, continued
SUBPART
POLLUTANT
EMISSION LEVELS
T Phosphate Ferti-
lizer Industry:
Wet Process
Phosphoric Acid
Plants
U Phosphate Ferti-
lizer Industry:
Super-phosphoric
Acid Plants
V Phosphate Ferti-
lizer Industry:
Diammonium Phos-
phate
W Phosphate Ferti-
lizer Industry:
Triple Super-
Phosphate
X Phosphate Ferti-
lizer Industry:
Granular Triple
Superphosphate
Y Coal Preparation
Plants
Thermal dryer
Pncumat ic
coal cleaving
equipment
Processing and
conveying equip-
ment, storage
systems, trans-
fer and loading
systems
Total
f]uorides
Total
f1uorides
Total
f1uo rides
Total
fluorides
Total
fluorides
Part i culate
Opacity
Particulate
Opac ity
Opacity
10 g/metric ton of
P70r feed
(6.020 Ib/ton)
5 g/metric ton of
P70r feed
(6.020 Ib/ton)
50 g/metric ton of
P70c- feed
(6.060 Ib/ton)
100 g/metric ton of
equivalent P?0r feed
(0.20 Ib/ton) 5
0.25 g/hr/metric ton
of equivalent P?0
stored
_.
"4
_
(5.0 x 10" Ib/hr/ton)
0.070 g/dscm
(0.031 gr/dscf)
20%
0.040 g/dscm
(0.031 gr/dscf)
10%
20%
III-137
-------
Table
3, continued
SUBPART
POLLUTANT
EMISSION LEVELS
Z Ferroalloy Produc-
tion Facilities
Electric sub-
merged arc
furnaces
Dust handling
equipment
AA Steel Plants
Electric arc
furnaces
Control device
Shop roof
Dust handling
equipment
BB Kraft Pulp Mills
Recovery Furnace
Straight recovery
furnace
Cross recovery
furnace
Particulate
Particulate
Opacity
Opacity
Opacity
Particulate
Opacity
TRS
TRS
0.45 kg/MW-hr
(0.99 Ib/MW-hr)
(high silicon
alloys)
0.23 kg/MW-hr
(0.51 Ib/MW-hr)
(chrome and man
ganese alloys)
Opacity
CO
Opacity
15%
20%
10%
12 mg/dscm
(0.0052 gr/dscf)
3%
0, except:
20% - charging
40% - tapping
10%
0.10 g/dscm
35%
5 ppm
25 ppm
III-138
-------
Table #3, continued
SUBPART
Smelt dissolving
tank
POLLUTANT
Particulate
TRS
TRS
Particulate
Particulate
Lime kiln
gaseous fuel
liquid fuel
Digester system,
brown stock washer
system, multiple-
effect evaporation
system, black li-
quor oxidation
system or conden-
sate stripper
HH Lime Manufacturing
Plants
Rotary Lime kiln Particulate
TRS
Lime Hydrator
Opacity
Particulate
EMISSION LEVELS
O.lg/kg black liquor
(dry out)
0.0084g/kg black liquor
(dry out)
8 ppm
0.15g/dscm
0.30g/dscm
5 ppm
0.15 kg/megagram of
limestone feed
0.075 kg/megagram
of lime feed
III-139
-------
Table # 4
PROPOSAL AND PROMULGATION DATES FOR NSPS SOURCE CATEGORIES
Promulgation
Subpart Source Date
Proposc-u
D
E
F
T
G
H
I
J
K
L
M
N
0
P
Q
R
S
TUVWX
Z
i
M
BB
HH
Fossil Fuel Fired Steam Generators 12/23/71
: Incinerators 12/23/71
i
j Portland Cement Plants j 12/23/71
; 1
1
Nitric Acid Plants i 12/23/71
i
1
Sulfuric Acid Plants ' 12/23/71
i i
! Asphalt Concrete Plants • 3/8/74
Petroleum Refineries ' 3/8/74
Storage Vessels for Petroleum '. 5/8/74
Liquids
Secondary Lead Smelters 3/8/74
Brass and Bronze Production Plants 3/8/74
i
Iron and Steel Plants j 3/8/74
Sewage Treatment Plants i 3/8/74
Primary Copper Smelter j 1/15/76
Primary Zinc Smelter 1/15/76
i
Primary Lead Smelter 1/15/76
i
Primary Aluminum Reduction Plants ' 1/26/76
!
Phosphate Fertilizer Industry ! 8/6/75
Coal Preparation Plants • 1/15/76
i
Ferroalloy Production Facilities : 5/4/76
l
Steel Plants: Electric Arc : 9/23/75
Furnaces !
l
Kraft Pulp Mills ; 2/23/78
Lime Manufacturing , 3/7/78
8/17/71
3/17/71
8/17/7 1
8/17/71
3/17/7]
6/11/75
6/11/73
6/11/75
6/11/73
6/11/73
6/11/73
6/11/75'
10/16/74
10/16/74
10/16/74
10/23/74
10/22/74
10/ 24/74
10/2V4
10/21/74
9/24/76
3/3/77
III-140
-------
Table #5
CONTINUOUS MONITORING REQUIREMENTS
I. Installed and operation.'! 1 prior to conducting performance tests
II. Conduct monitoring system performance evaluations during per-
formance tests or 30 days thereafter (for specification
requirements, see Table #11)
III. Check zero and span drift at least daily (see Table #8)
IV. Time for cycle of operations (sampling, analyzing, and data
recording)
A. Opacity - 10 seconds
B. Gas Monitors - 15 minutes
V. Installed to provide representative sampling
VI. Reduction of data
A. Opacity - 6-minute average
B. Gaseous Pollutants - hourly average
VII. Source must notify agency, more than 30 days prior, of date
upon winch demonstration of continuous monitoring system
performance is to commence.
Performance tests shall be conducted within 60 days after
achieving the maximum production rate at which the affected
facility will be operated, but not later than 180 days after
initial startup of such facility.
III-141
-------
Table #6
QUARTERLY REPORTING REQUIREMENTS1 (NSPS)
I. Excess Emissions
A. Description of Excess Emission
1. Magnitude
2. Conversion factors used
3. Date and time of commencement and completion
B. Explanation of Excess Emission
1. Occurrances during startups, shutdowns, and malfunctions
2. Nature and cause of malfunction
3. Corrective and preventative action taken
C. To be Submitted in Units Same as Standard
II. Continuous Monitoring Systems
A. Date and Time when System was Inoperative (except for
zero and span checks)
B. Nature of System Repairs or Adjustments
III. Lack of Occurrances During A Quarter
A. Absence of Excess Emissions during Quarter
B. Absence of Adjustments, Repairs, or Inoperativeness of
Continuous Monitoring System
"Each owner or operator required to install a continuous monitoring
system shall submit a written report ... for every calendar quarter'
"All quarterly reports shall be postmarked by the 30th day following
the end of each calendar quarter..."
III-142
-------
Table "7
DEFINITION 01: EXCESS EMISSIONS
(NSPS)
SUBPART
D
POLLUTANT
opacity
SO.
NO,
NO
x
II
SO.
EXCESS EMISSION
any six-minute period during which the aver-
age opacity of emissions exceeds 20% opacity,
except that one six-minute average per hour
of up to 27?6 opacity need not be reported.
k
any three-hour period during which the average
emissions of S02 (arithmetic average of three
contiguous one-hour periods) exceed the
standard
any three-hour period during which the average
emissions of NO (arithmetic average of three
contiguous one-Hour periods) exceed the
standard
any three-hour period during which the average
nitrogen oxides emissions (arithmetic average
of three contiguous one-hour periods) exceed
the standard
all three hour periods (or the arithmetic
average of three consecutive one hour periods)
during which the integrated average sulfur
dioxide emissions exceed the applicable
standards
Opacity
CO
S02
S02
All one-hour periods which contain two or
more six-minute periods during which the
average opacity exceeds 30 percent.
All hourly periods during which the average
CO concentration exceeds the standard.
Any three hour period during which the
average concentration of S02 emissions
from any fuel gas combustion device exceeds
the standard.
Any twelve-hour period during which the
average concentration of S02 emissions from
any Glaus sulfur recovery plant exceed the
standard.
III-143
-------
Table #7, continued
SUBPART
P
R
AA
POLLUTANT
Opacity
so2
Opacity
so2
Opacity
Opacity
Opacity
BB
Recovery
furnace TRS
Opacity
Lime kiln TRS
Digester
system, brown
stock washer
system, multiple-
effect evaporator
system, black
liquor oxidation
system, or
condensate
stripper.
TRS
HH
Opacity
EXCESS EMISSION
any six-minute period during which the average
opacity exceeds the standard
any six-hour period during which the average
emissions of S02 (arithmetic mean of six con-
tiguous one-hour periods) exceed the standard
any six minute period during which the average
opacity exceeds the standard
any two hour period during which the average
emissions of SO? (arithmetic mean of two
contiguous one-nour periods) exceed the
standard
any six minute period during which the
average opacity exceeds the standard
any two hour period during which the
average emissions of S02 (arithmetic mean
of two contiguous one hour periods) exceed
the standard
all six minute periods in which the average
opacity is 15 percent or greater
all six minute periods during which the
average opactiy is 3 percent or greater
Any twelve hour period during which the TRS
emissions exceed the standard.
Any six minute period during which the average
opacity exceeds the standard.
Any twelve hour period during which the TRS
emissions exceed the standard.
Any twelve hour period during which the TRS
emissions exceed the standard.
All six minute periods during which the
average opacity is greater than the standard
III-144
-------
Table #8
SPANNING AND ZEROING
I. Explanation of Zero and Span ('hecks
A. Extractive gas monitors
1. Span gas composition
a. S02 - sulfur dioxide/nitrogen or gas mixture
b. NO - nitric oxide/oxygen-free nitrogen mixture
c. N02 - nitrogen dioxide/air mixture
2. Zero gases
a. Ambient air
or b. A gas certified by the manufacturer to contain less
than 1 ppm of the pollutant gas
3. Analysis of span and zero gases
a. Span and zero gases certified by their manufacturer
to be traceable to National Bureau of Standards
reference gases shall be used whenever these gases
are available
b. Span and zero gases should be reanalyzed every
six months after date of manufacture with Reference
Method 6 for S02 and 7 for NOX
c. Span and zero gases shall be analyzed two weeks
prior to performance specification tests
B. Non-extractive gas monitors
1. Span check - certified gas cell or test cell
2. Zero check - mechanically produced or calculated
from upscale measurements
C. Transmissometers
1. Span check is a neutral density filter that is
certified within * 3 percent opacity
2. Zero check is a simulated zero
D. Span values are specified in each subpart
1. Span check is 901 of span.
II. Adjustment of Span and Zero
A. Adjust the zero and span whenever the zero or calibration
drift exceeds the limits of applicable performance
specification in Appendix B.
1. For opacity, clean optical surfaces before adjusting
zero or span drift
2. For opacity systems using automatic zero adjustments,
the optical surfaces shall be cleaned when the cumu-
lative automatic zero compensation exceeds four percent
opacity
III. How to Span and Zero
A. Extractive gas monitors
1. Introduce the zero and span gas into the monitoring
system as near the probe as practical
B. Non-extractive gas monitors
1. Use a certified gas cell or test cell to check span
2. The zero check is performed by computing the zero value
from upscale measurements or by mechanically producing
a zero
C. Transmissometers
1. Span check with a neutral density filter
2. Zero check by simulating a zero opacity
III-145
-------
Table # 9
SPAN SPECIFICATIONS
SUBPART
D Fossil Fuel Fired
Steam Generators
liquid fossil fuel
solid fossil fuel
gaseous fuel
mixtures of fossil fuels
G Nitric Acid Plants
H Sulfuric Acid Plants
J Petroleum Refineries
Catalytic Cracker
Glaus Recovery Plant
Fuel Gas Combustion
POLLUTANT
opacity
S02
NOX
opaci ty
S02
opacity
S02
NOX
NO 2
SO.,
Opacity
CO
S02
TRS
S02
H2S
SPAN
80, 90, or 100% opacity
1000 ppm
500 ppm
80, 90, or 1001 opacity
1500 ppm
1000
500 ppm
80,90, or 100% opacity
lOOOy + 1500z 1
500 (x+y) + lOOOz
500 ppm
1000 ppm
60,70, or 80% Opacity
1000 ppm
500 ppm
20 ppm
600 ppm
100 ppm
300 ppm
P Primary Copper Smelters
Q Primary Zinc Smelters
R Primary Lead Smelters
Z Ferroalloy Production
Facilities
AA Steel Plants
Opacity
S02
Opacity
Opacity
S02
Opacity
Opacity
80 to 100% opacity
0. 20% by volume
80 to 100% opacity
0.20% by volume
80 to 100% opacity
0.20% by volume
not specified
not specified
III-146
-------
laoie ffy, continued
SUBPART
BB Kraft Pulp Mills
Recovery Furnace
P01.LUTANT
Opacity
Lime kiln, recovery furnace
digester system, brown 62
Stock washer system,
multiple effect TRS
evaporator system,
black liquor oxidation
system, or condensate
stripper system
HH Lime Manufacturing Plant Opacity
SPAN
opacity
20%
30 ppm
(except that for
any cross recovery
furnace the span shall
be 500 ppm)
40% Opacity
x= fraction of total heat input from gas
y= fraction of total heat input from liquid fossil fuel
z- fraction of total heat input from solid fossil fuel
Span value shall be rounded off to the nearest 500 ppm
III-147
-------
Table #10
NOTIFICATION REQUIREMENTS
Requirements
Date of Commencement of Construction
Anticipated Date of Initial Startup
Actual Date of Initial Startup
Any physical or operational change
to a facility which may increase
the emission rate of any air
pollutant to which a standard
applies
A. The precise nature of the change
B. Present and proposed emission
control systems
C. Productive capacity before and
after the change
D. Expected completion date of
change
Date upon which demonstration of
continuous monitoring system
performance commences
Time Deadline
Less than 30 days after
such date
Less than 60 or more than
30 days prior to date
Within 15 days after date
Postmarked 60 days or
as soon as practical
before the change is
commenced
more than 30 days prior
"Any owner or operator subject to the provisions of this part shall
furnish the Administrator written notification..."
TTT-148
-------
Table #11
SPECIFICATION REQUIREMENTS (NSPS)
Sept.
Before
CASE 1*
CASE 2*
CASE 3*
CASE 4
CASE 5
CASE 6
PI
P
P
11, 1974 October
After Before
I
PI
P
6, 1975
After Specification
Requirements
I
I
PI
None-unless re-
quested by the
administrator
None-unless re-
quested by the
administrator
Accuracy
All requirements
in Appendix B
All requirements
in Appendix B
All requirements
in Appendix B
P - Purchased
I - Installed
* Cases 1,2, and 3 shall be upgraded or replaced with new continuous
monitoring systems and shall comply with Specification Requirements
in Appendix B by September 11, 1979
III-149
-------
Table # 12
PliRFORMANCi; SPliCI IT CAT IONS
TRANSMISSOMETERS
Calibration error
Zero drift (24h)
Calibration drift (24h)
Response time
Operational test period
<^ 3 pet opacity
<_ 2 pet opacity
<_ 2 pet opacity
10 s-maximum
168 hours
N0x and S0?
Accuracy
Calibration error
Zero drift (2h)
Zero drift (24h)
Calibration drift (2h)
Calibration drift (24h)
Response time
Operational period
<_20 pet of the mean value
of the reference method test data
5.5 Pet of (50 pet, 90 pet)
calibration gas- mixture value
2 pet of span
2 pet of span
2 pet of span
2.5 pet of span
15 min maximum
168 h minimum
09 and CO,
L /
Zero drift (2h)
Zero drift (24h)
Calibration drift (2h)
Operational period
Response time
5.0.4 pet 02 or C02
£0.5 pet 02 or C02
5.0 ...4. pet 02 or C02
168 H minimum
10 min
Ill-ISO
-------
TABU; #13
WHEN TO RUN THE MONITOR PERFORMANCE TEST
INITIAL
FACILITY
START-UP
180
DAYS
MAX
MAX
PRODUCTION
F.A7E
REACHED
PERFORMANCE
TEST & SUBMIT
REPORT FOR
COMPLIANCE
60
DAYS
v
MONITOR
PERFORMANCE
TEST
t
30
DAYS
60
DAYS
MONITOR PERFOR-
MANCE TEST
REPORT
III-151
-------
Table #14
REQUIREMENTS FOR SIP REVISIONS
I. Submit SIP Revisions by October 6, 1976
II. Contain monitoring requirements for the following
sources (as a minimum)
A. Fossil Fuel-Fired Steam Generators
B. Sulfuric Acid Plants
C. Nitric Acid Plants
D. Petroleum Refineries
(see Table # 15)
III. Require that sources evaluate the performance
of their monitoring system
IV. Require the sources to maintain a file of all
pertinent continuous monitoring data
A. Emission measurements
B. Monitoring system evaluation data
C. Adjustments and maintenance performed on the
monitoring system
V. Require the source to submit periodic (such period
not to exceed 3 months) reports containing the
following information.
A. Number and magnitude of excess emissions
B. Nature and cause of excess emissions
C. Statement concerning absence of excess
emissions and/or monitor inoperativeness
VI. Require that monitoring begin within 18 months of
EPA approval of the SIP revision (or within 18
months of EPA promulgation)
III-152
-------
TABLE #15
EXISTING SOURCES REQUIRED TO CONTINUOUSLY MONITOR EMISSIONS
Source
Fossil Fuel-Fired
Steam Generators
Pollutant
SO,
NO
'Opacity
Nitric Acid Plants
NO
Sulfuric Acid Plants
Petroleum Refineries
SO,
Opacity
Comments
1. >250 x 10° Btu/hr
2. Source that has
control equipment
for S02
1. >1000 x 106 Btu/hr
2. Located in a designated
non-attainment area
for N02.
3. Exempt if source is
30% or more below the
emission standard
1. >250 x 106 Btu/hr
2. Exempt if burning gas
3. Exempt if burning oil,
or a mixture of oil
and gas are the
only fuels used and
the source is able
to comply with the
applicable particu-
late matter and
opacity standards with-
out installation of
control equipment
1. >300 ton/day
2. Located in a designated
non-attainment area
for N02.
1. >300 tons/day
1. >20,000 barrels/day
III-153
-------
Table // 16
NESHAP MONITORING REQUIREMENTS
FOR VINYL CHLORIDE SOURCES
I EDC PLANTS
A. All exhaust gases discharged from any equipment
used in EDC purification.
B. Emissions from each oxychlorination reactor
II VC PLANTS
A. All exhaust gases discharged from any equipment
used in vinyl chloride formation.
Ill PVC PLANTS
A. All exhaust gases discharged from each reactor.
B. All exhaust gases discharged from each stripper.
C. All exhaust gases discharged from each mixing,
weighing or holding container which precedes the
stripper (or reactor if plant has no stripper).
D. All exhaust gases discharged from each monomer
recovery system.
IV EDC, VC AND PVC PLANTS - ANY CONTROL SYSTEM TO WHICH
REACTOR EMISSIONS ARE REQUIRED TO BE DUCTED FROM
A. Loading or unloading lines
B. Slip gauges
C. Manually vented equipment
D. Equipment opened to the atmosphere from which
vinyl chloride is removed prior to opening
E. Inprocess wastewater
III-154
-------
VENDORS OF CONTINUOUS
MONITORING EQUIPMENT
Page Xo.
1. Vendors IV-1
2. Addresses IV-2
-------
VENDORS OF CONTINUOUS MONITORING EQUIPMENT
VENDORS
SO
NO
Opacity O
Data
Handling
CO,, TRS H.,8 Equipment
£ .1
\ndersen Samplers, Inc.
3abct?ck and Wilcox Company, Bailey Meter Co.
3eckman Instruments, Inc. x x
["he Bendix Corp., Env. and Process Inst. Div. x x
Calibrated Instruments, Inc. x
-EA Instruments, Inc. x x
Cleveland Controls, Inc.
^ontraves-Goerz Corporation x x
Datatest
S. I. Du Pont de Nemours and Company x x
3ynatron, Inc.
Electronics Corporation of America
Energetics Science, Inc. x
Environmental Data Corporation x x
Environmental Tectonics Corp. x
Ssterline Angus x x
ftoriba Instruments, Inc. x x
Houston Atlas, Inc.
Infrared Industries
InterScan Corporation x x
Dear Siegler, Inc. x x
Leeds and Northrup Company
Meloy Laboratories, Inc. x x
line Safety Appliance Company x x
?hotomation, Inc.
Deferred Instruments, Div.
Research Appliance Company
Milton Roy Company
Source Gas Analyzers, Inc. x
Taylor Instrument Company
rhermco Instrument Corporation
Thermo Electron Corporation x x
Western Precipitation Division x
Western Research and Development Ltd. x
Whittaker Corporation x x
x
x x
X XX
M ••-;• x x
x x
X
X
XX X
X
> X X
X
X
X
X XX X
X
x x x > x;
..;•*.
X
XX X
X X X
X X
X
X X
X
X X
X X
X X
X
XX X
XX XX
xx xx
-------
Andersen Samplers, Inc.
4215-C Wendell Drive
Atlanta, Georgia 30336
Babcock & Wilcox, Company
Bailey Meter Company
29801 Euclid Avenue
Wickliffe, Ohio 44092
Beckman Instruments, Inc.
Process Instruments Division
2500 Harbor Blvd.
Fullerton, Cal. 92634
The Bendix Corp., Env. & Process Inst. Div.
Post Office Drawer 831
Lewisburg, W. Va. 24901
Calibrated Instruments, Inc.
731 Saw Mill River Rd.
Ardsley, N. Y. 10502
CEA Instruments, Inc.
15 Charles Street
Westwood, N. J. 07675
Cleveland Controls, Inc.
5755 Granger Road
Suite 850
Cleveland, Ohio 44109
Contraves-Goerz Corporation
610 Epsilon Drive
Pittsburgh, Pa. 15238
Datatest, Inc.
1117 Cedar Avenue
Croydon, Pa. 19020
E. I. Du Pont de Nemours and Company
1007 Market Street
Wilmington, Del. 19898
Dynatron, Inc.
Energy Conservation Systems
57 State Street
North Haven, Ct. 06473
Electronics Corporation of America
1 Memorial Drive
Cambridge, Mass. 02142
Energetics Science, Inc.
85 Executive Blvd.
Elmsford, N. Y. 10523
Environmental Tectonics Corp.
101 James Way
Southampton, Pa. 18966
Environmental Data Corporation
608 Fig Avenue
Monrovia, Calif. 91016
Esterline Angus Instrument Corp.
A Unit of Esterline Corporation
Post Office Box 24000
Indianapolis, Indiana 46224
Horiba Instrument, Inc.
1021 Durega Avenue
Irvine, Calif. 92714
Houston Atlas, Inc.
9441 Banthorne Drive
Houston, Texas 77043
Infrared Industries
Post Office Box 989
Santa Barbara, Calif.
93102
InterScan Corporation
9614 Cozycroft Avenue
Chatsworth, Calif. 91311
Lear Siegler, Inc.
Environmental Technology Division
74 Inverness Drive, East
Englewood, Col. 80110
Leeds and Northrup Company
Sumneytown Pike
North Wales, Pa. 19454
Meloy Laboratories, Inc.
Instrument and Systems Divisio
6715 Electronic Drive
North Springfield, Va. 22151
Mine Safety Appliance Company
400 Penn Center
Pittsburgh, Pa. 15235
Photomation, Inc.
270 Polaris Avenue
Mt. View, Calif. 94043
Preferred instruments Div.
Preferred Utilities Mfg. Corp.
11 South Str.
Danbury, Conn. 06810
Research Appliance Co.
P, O. Box 265 - Moose Lodge Rod
Cambridge, Md. 21613
Milton Roy Company
Hays-Republic Div.
4333 South Ohio St.
M-i /"•!•. 4 /-rnvi r>4 4-,, T—J
-------
Source Gas Analyzers, Inc.
7251 Garden Grove Blvd.
Garden Grove, Calif. 92641
Taylor Instrument Company
95 Ames Street
Rochester, N. Y. 14601
Thermco Instrument Corporation
«Post Office Box 309
Laporte, Ind. 46350
'Thermo Electron Corporation
Environmental Instruments Division
108 South Street
Hopkinton, Mass. 01748
Western Precipitation Division
Joy Manufacturing Co.
Post Office Box 2744 Terminal Annex
Los Angeles, Calif. 90051
Western Research and Development, Ltd.
1313 44th Avenue NE
Calgary, Alta, Canada T2E 6L5
Whittaker Corporation
Environmental Production Division
9100 Independence Avenue
Chatsworth, Calif. 91311
IV'3
-------
BIBLIOGRAPHY
Page No.
1. Bibliography Index ^~1
2. Bibliography V- 2
3. Availability of EPA Publications V-7
-------
BIBLIOGRAPHY INDEX
Subject Reference Numbers
Transmissometry
Principles and application I, 12, 13, 29, 33, 39
Instrumentation 8
Evaluation of methods 31
Used at Fossil Fuel-Fired Steam
Generator 2
Used at Refinery 41
Gaseous Emission Monitoring
Principles and application 7, 9, 10, 21, 23, 24, 47,
48, 49
Instrumentation 8, 26, 44
Evaluation of methods 3, 15, 20, 31, 36
Used at Copper Smelter Acid Plants 40, 42
Used at Sulfuric Acid Plants 43
Used at Fossil Fuel-Fired Steam
Generators 2
Used at Steel Plants 46
Sampling handling 31, 32
References used for the establishment
and support regulations 2, 34, 35, 38, 41, 42
Vendors 18, 27, 37
Regulations 45
General 4, 5, 6, 11, 14, 16, 19,
22, 25, 28, 20, 50
V-l
-------
BIBLIOGRAPHY
1. Avetta, Edward D., IN-STACK TRANSMISSOMETER EVALUATION
AND APPLICATION TO PARTICULATE OPACITY MEASUREMENT. EPA
contract no. 68-02-0660 Owens,Illinois NTIS PB 242402
Jan. 1975.
2. Baladi, Emile Midwest Research Institute, MANUAL SOURCE
TESTING AND CONTINUOUS MONITORING CALIBRATIONS AT THE
LAWRENCE ENERGY CENTER OF KANSAS POWER AND LIGHT COMPANY,
EPA contract no. 68-02-0228, EPA Report no. 73-SPP-3,
May 7, 1976.
3. Barnes, H. B., C. R. Fortune, and J. B. Homolya, AN
EVALUATION OF MEASUREMENT METHODOLOGY FOR THE CHARACTER-
IZATION OF GASEOUS SULFUR EMISSIONS FROM COMBUSTION
SOURCES, Presented at the Fourth National Conference on
Energy and the Environment, Cincinnati, Ohio, October 4-7,
1976.
4. Blosser, R. 0., A. G. Kutyna, R. A. Schmall, M. E.
Franklin, and K. Jain. THE STATUS OF SOURCE EMISSION
MONITORING AND MEASUREMENTS. Presented at the Technical
Association of the Pulp and Paper Industry, Annual
meeting Miami Beach, Florida, January, 1974.
5. Bonam, W. L. and W. F. Fuller, CERTIFICATION EXPERIENCE
KITH EXTRACTIVE EMISSION MONITORING SYSTEMS, SRI-
Proceeding of Workshop on Sampling, Analysis, and Moni-
toring of Stack Emissions, April, 1976, PB-252-748.
6. Brooks, E. F., GUIDELINES FOR STATIONARY SOURCE CONTIN-
UOUS GAS MONITORING SYSTEMS, EPA Contract number
68-02-1412, TRN Systems Group, November, 1975.
7. Brooks, E. P., C. A. Flegal, L. N. Harriett, M. A. Kolpin,
D. J. Luciani, and R. L. Williams CONTINUOUS MEASUREMENT
OF GAS COMPOSITION FROM STATIONARY SOURCES, TRW Systems
Group, EPA Contract no. 68-02-0636, EPA-600/2-75-012.
8. Chapman, Robert L., INSTRUMENTATION FOR STACK MONITORING.
Pollution Engineering, September, 1972.
9. Cheney, J. L., and J. B. Homolya, THE DEVELOPMENT OF A
SULFUR DIOXIDE CONTINUOUS MONITOR INCORPORATING A PIEZO-
ELECTRIC SORPTION DETECTOR, The Science of the Total
Environment 5, 69-77 1976.
10. Cheney, Norwood, and Homolya, THE DETECTION OF SULFUR
DIOXIDE UTILIZING A PIEZO-ELECTRIC CRYSTAL COATED WITH
ETHYLENEDINITRILOTETRAETHANOL, Analytical Letters,
9(4) 361-377, 1976.
V-2
-------
-2-
11. Cheremisinoff, P. N. and R. A. Young, NEW DEVELOPMENTS
IN AIR QUALITY INSTRUMENTATION. Pollution Engineering,
7(2): 24 1975.
12. Connor, W. D., A COMPARISON BETWEEN IN-STACK AND PLUME
OPACITY MEASUREMENTS AT OIL-FIRED POWER PLANTS. Presented
at t]ie Fourth National Conference on Energy and the
Environment, Cincinnati, Ohio, October 4-7, 1976.
13. Conner, William D. MEASUREMENT OF THE OPACITY AND MASS
CONCENTRATION OF PARTICULATE EMISSIONS BY TRANSMISSOMETRY,
Chemistry and Physics Laboratory, EPA-650/2-74-128
November, 1974.
14. Cross, F. L. Jr., and H. F. Scheff, CONTINUOUS SOURCE
MONITORING. Chemical Engineering/Deskbook Issue 125-127
June, 1973.
15. Driscoll, Becker, McCoy, Young, and Ehrenfeld, Walden
Research Corp., EVALUATION OF MONITOR METHODS AND
INSTRUMENTATION FOR HYDROCARBONS AND CARBON MONOXIDE
IN STATIONARY SOURCE EMISSIONS, EPA Contract no. 68-02-0320,
EPA-R2-72-106, November, 1972.
16. Elliot, T. C. MONITORING BOILER STACK GASES, Power, 92-94,
April, 1975.
17. Ellis, D. H. RELIABILITY OF STACK SAMPLING METHODS VS.
CONTINUOUS MONITORING SYSTEMS. Air Pollution Control
Association, Pittsburgh, Pennsylvania, Design, Operation
and Maintenance of High Efficiency Control Equipment, St.
Louis, Mo., 1973 p. 145-147.
18. Environmental Science and Technology, Pollution Control
Issue, Vol. 10, no. 11, October, 1976.
19. Fennelly, Paul, F., DEVELOPMENT OF AN IMPLEMENTATION PLAN
FOR A CONTINUOUS MONITORING PROGRAM, GCA Corp., March, 1977
20. Green, M. W., R. L. Chapman, S. C. Creason, R. N. Harvey,
G. A. Heyman, and W. R. Pearson, EVALUATION OF MONITORING
SYSTEMS FOR POWER PLANT AND SULFUR RECOVERY PLANT EMISSION'S,
EPA Contract no. 68-02-1743, Beckman Instruments, Inc.,
EPA 600/2-76-171, June, 1976.
21. Homolya, CONTINUOUS MONITORING SYSTEMS FOR GASEOUS
EMISSIONS, EPRI Workshop Proceedings, Special Report #41,
p. 17 October, 1975.
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22. Homolya, J. B., COUPLING CONTINUOUS GAS MONITORS TO
EMISSIONS SOURCES, Chem Tech, 426-433, July 1, 1974.
23. Homolya, CURRENT TECHNOLOGY FOR CONTINUOUS MONITORING
OF GASEOUS EMISSIONS, Journal of the Air Pollution
Control Assoc., 25(8) 809-814 August, 1975.
24. Homolya, THE DEVELOPMENTAL NEEDS FOR CONTINUOUS SOURCE
MONITORING SYSTEMS OF GASEOUS EMISSIONS, Proceedings
of the Fourth National Conference on Energy and the
Environment, Cincinnati, Ohio, October 4-7, 1976.
25. James R. E. and C. D. Wolback, QUALITY ASSURANCE OF
STATIONARY SOURCE EMISSION MONITORING DATA, Inst. of
Electrical and Elcectronics Engineers, Inc., 36, 1976.
26. Jaye, Frederic C., MONITORING INSTRUMENTATION FOR THE
MEASUREMENT OF SULFUR DIOXIDE IN STATIONARY SOURCE
EMISSIONS. TRW Systems Group, EPA Project 17205 NTIS
PB 220202.
27. Journal of the Air Pollution Control Association, Product
Guide, Vol. 27, no. 3, March, 1977.
28. Karels, Gale G., Gary R. Kendall, Thomas E. Perardi, and
A. Levaggi, USE OF REAL-TIME CONTINUOUS MONITORS IN
SOURCE TESTING. Presented at APCA annual meeting June 15-
20, 1975. Paper 75-19.5, NTIS PB 230934/AS GPO.
29. Knapp, K. I., NEW TECHNIQUES FOR CONTINUOUS MEASUREMENT
OF MASS EMISSIONS, Proceedings of the EPRI Workshop on
Sampling, Analysis and Monitoring of Stack Emissions
EPRI-41 April, 1976.
30. Lillis and Schueneman, CONTINUOUS EMISSION MONITORING:
OBJECTIVES AND REQUIREMENTS, Journal of the Air Pollution
Control Association, August, 1975.
31. McRanie, Richard D., John M. Craig, and George 0. Layman,
EVALUATION OF SAMPLE CONDITIONERS AND CONTINUOUS STACK
MONITORS FOR MEASUREMENT OF S02, NOX, AND OPACITY IN
FLUE GAS FROM A COAL-FIRED STEAM GENERATOR, Southern
Services, Inc., February, 1975.
32. McNulty, K. J. , J. F. McCoy, J. H. Becker, J. R. Ehrenfeld,
and R. L. Goldsmith, INVESTIGATION OF EXTRACTIVE SAMPLING
INTERFACE PARAMETERS, EPA Contract no. 68-02-0742, Walden
Research Division of Abcor, Inc., EPA - 650/2-74-089,
October, 1974.
33. Woffinden, and Ensor, OPTICAL METHOD FOR MEASURING THE MASS
CONCENTRATION OF PARTICULATE EMISSIONS, EPA Contract no.
68-02-1749, Meteorology Research, Inc. EPA-600/2-76-062,
March, 1976.
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34. Nader, John S. , CURRENT TECHNOLOGY FOR CONTINUOUS MONI-
TORING OF PARTICULAR; EMISSIONS, Journal of the Air
Pollution Control Association, August, 1975, 814-821.
35. Nader, John S. , Frederic Jaye, and William Conner,
PERFORMANCE SPECIFICATIONS FOR STATIONARY SOURCE
MONITORING SYSTEMS FOR GASES AND VISIBLE EMISSIONS. NERC
Chemistry and Physic Lab. NTIS PB 209190, January, 1974.
36. Osborne, Michael C.. M. Rodney Midgett, SURVEY OF CONTINUOUS
GAS MONITORS TO EMISSIONS SOURCES, Chem Tech, 426-433
July, 1974.
37. Pollution Engineering, Environmental Yearbook and Product
Reference Guide, Vol. 9, no. 1, January, 1977.
38. Quick, Durle L., FIELD EVALUATION OF S02 MONITORING
SYSTEMS APPLIED TO H2S04 PLANT EMISSIONS,, Volumes I § II,
EPA Contract no. 68-02-1292, Scott Environmental Technology,
EPA-650/2-75-053a (Vol. I) and EPA-650/2-75-0536 (Vol. II),
July, 1975.
39. Reisman, E., W. D. Gerber, and N. D. Potter, IN-STACK
TRANSMISSOMETER MEASUREMENT OF PARTICULATE OPACITY AND MASS
CONCENTRATION, EPA contract #68-02-1229 Philco-Ford Corp.,
NTIS PB 239864/AS, November, 1974.
40. Scott Environmental Technology, Inc., CONTINUOUS MONITOR-
ING OF A COPPER SMELTER ACID PLANT, Phelps Dodge Ajo,
Arizona Report no. 73-CUS-2.
41. Scott Environmental Technology, Inc. SUMMARY OF CONTINUOUS
MONITORING OPACITY DATA, REFINERY FCC CO BOILER, PHILLIPS
PETROLEUM, Avon, California, EPA contract no. 68-02-1400,
Report no. 74-CAT-2, March, 1976.
42. Scott Research Laboratories, CONTINUOUS MONITORING OF A
COPPER SMELTER DOUBLE CONTACT PROCESS ACID PLANT, EPA
Contract no. 68-02-0233, Report no. 73-CUS-2, May, 1974.
43. Shotles, R. S., and J. R. Dallar, CONTINUOUS MEASUREMENT
OF SULFUR DIOXIDE EMISSIONS, Mississippi Chemical Corpor-
ation, Pascagoula, Mississippi, EPA Report no. 73-SFA-3B.
44. Snyder, Arthur D. Edward C. Eimutis, Michael G. Konicek,
Leo P. Parts, and Paul L. Sherman, INSTRUMENTATION FOR
THE DETERMINATION OF NITROGEN OXIDES CONTENT OF STATIONARY
SOURCE EMISSIONS. NTIS PB 204-877 Vol. 1 PB 209-190 Vol. 2,
January, 1972.
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45. U. S. Environmental Protection Agency, STANDARDS OF
PERFORMANCE FOR NEW STATIONARY SOURCES, Federal Register,
40:46250-46270, October 6, 1975.
46. Roy Weston, Inc., FINAL REPORT ALAN WOOD STEEL COMPANY,
CONSHOHOCKEN PENNSYLVANIA, EPA Contract no. 68-02-0240,
Report no. 73-BOF-l, December, 1975.
47. Wolf,Philip C., CONTINUOUS STACK GAS MONITORING Part
One: ANALYZERS, Pollution Engineering, 32-36 June, 1975.
48. Wolf, Philip C., CONTINUOUS STACK GAS MONITORING Part Two
GAS HANDLING COMPONENTS AND ACCESSORIES, Pollution
Engineering, 26-29, July, 1975.
49. Wolf, Philip C., CONTINUOUS STACK GAS MONITORING Part
Three: SYSTEMS DESIGN, Pollution Engineering, 36-37,
August, 1975.
50. Zegel, W. C., and T. Lachajczyk, THE VALUE OF CONTINUOUS
MONITORING TO THE USER, The Journal of the Air Pollution
Control Association, Vol. 25, no. 8, 821-823, August,
1975.
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Availability of EPA Publications
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supplies are exhausted, one may purchase publications from
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U. S. Environmental Protection Agency
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TECHNICAL REPORT DATA
'li(»n E
15. SUPPLEMENTARY NOTES
10. ABSTRACT
The Environmental Protection Agency has promulgated revisions to
40 CFR Part 60, New Source Performance Standards, and 40 CFR
Part 61, National Emission Standards for Hazardous Air Pollutants
that require specified categories of stationary sources to
continuously monitor emissions. The EPA has also required States
to revise their
regulations.
SIP's to include continuous emission monitoring
This report is a compilation of the following continuous emission
monitoring information: EPA organizations and personnel involved
with continuous emission monitoring; continuous emission monitoring
regulations; vendors of continuous monitoring equipment; and a
bibliography of continuous monitoring literature.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Continuous Emission Monitoring
Regulations
New Source Performance Standard
b.IDENTIFIERS/OPEN ENDED TERMS
Continuous Emission
Monitoring
c. COSATI Held/Group
13B
14D
r R I a U T I O N S T A 1 F. M £ N 1
Release Unlimited
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassifi ed
21. NO. OF PAGES
22. p'nTcT
EPA Form 2220-1 (9-73)
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