[Code of Federal Regulations]
[Title 40, Volume 14]
[Revised as of July 1, 2003]
From the U.S. Government Printing Office via GPO Access
[CITE: 40CFR75.58]
[Page 292-296]
TITLE 40--PROTECTION OF ENVIRONMENT
CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)
PART 75--CONTINUOUS EMISSION MONITORING--Table of Contents
Subpart F--Recordkeeping Requirements
Sec. 75.58 General recordkeeping provisions for specific situations.
The owner or operator shall meet all of the applicable recordkeeping
requirements of this section.
(a) [Reserved]
(b) Specific parametric data record provisions for calculating
substitute emissions data for units with add-on emission controls. In
accordance with Sec. 75.34, the owner or operator of an affected unit
with add-on emission controls shall either record the applicable
information in paragraph (b)(3) of this section for each hour of missing
SO2 concentration data or NOX emission rate (in
addition to other information), or shall record the information in
paragraph (b)(1) of this section for SO2 or paragraph (b)(2)
of this section for NOX through an automated data acquisition
and handling system, as appropriate to the type of add-on emission
controls:
(1) For units with add-on SO2 emission controls using the
optional parametric monitoring procedures in appendix C to this part,
for each hour of missing SO2 concentration or volumetric flow
data:
(i) The information required in Sec. 75.57(c) for SO2
concentration and volumetric flow, if either one of these monitors is
still operating;
(ii) Date and hour;
(iii) Number of operating scrubber modules;
(iv) Total feedrate of slurry to each operating scrubber module
(gal/min);
(v) Pressure differential across each operating scrubber module
(inches of water column);
(vi) For a unit with a wet flue gas desulfurization system, an in-
line measure of absorber pH for each operating scrubber module;
(vii) For a unit with a dry flue gas desulfurization system, the
inlet and outlet temperatures across each operating scrubber module;
(viii) For a unit with a wet flue gas desulfurization system, the
percent solids in slurry for each scrubber module;
(ix) For a unit with a dry flue gas desulfurization system, the
slurry feed rate (gal/min) to the atomizer nozzle;
(x) For a unit with SO2 add-on emission controls other
than wet or dry limestone, corresponding parameters approved by the
Administrator;
(xi) Method of determination of SO2 concentration and
volumetric flow using Codes 1-55 in Table 4a of Sec. 75.57; and
(xii) Inlet and outlet SO2 concentration values, recorded
by an SO2 continuous emission monitoring system, and the
removal efficiency of the add-on emission controls.
(2) For units with add-on NOX emission controls using the
optional parametric monitoring procedures in appendix C to this part,
for each hour of missing NOX emission rate data:
(i) Date and hour;
(ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
(iii) Excess O2 concentration of flue gas at stack outlet
(percent, rounded to the nearest tenth of a percent);
(iv) Carbon monoxide concentration of flue gas at stack outlet (ppm,
rounded to the nearest tenth);
(v) Temperature of flue gas at furnace exit or economizer outlet
duct ( deg.F);
(vi) Other parameters specific to NOX emission controls
(e.g., average hourly reagent feedrate);
(vii) Method of determination of NOX emission rate using
Codes 1-55 in Table 4a of Sec. 75.57; and
(viii) Inlet and outlet NOX emission rate values recorded
by a NOX continuous emission monitoring system and the
removal efficiency of the add-on emission controls.
(3) Except as otherwise provided in Sec. 75.34(d), for units with
add-on SO2 or NOX emission controls following the
provisions of Sec. 75.34(a)(1), (a)(2) or (a)(3), the owner or operator
shall record:
(i) Parametric data which demonstrate, for each hour of missing
SO2 or NOX emission data, the proper operation of
the add-on emission controls, as described in the quality assurance/
quality control program for the unit.
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The parametric data shall be maintained on site and shall be submitted,
upon request, to the Administrator, EPA Regional office, State, or local
agency;
(ii) A flag indicating, for each hour of missing SO2 or
NOX emission data, either that the add-on emission controls
are operating properly, as evidenced by all parameters being within the
ranges specified in the quality assurance/quality control program, or
that the add-on emission controls are not operating properly;
(iii) For units substituting a representative SO2
concentration during missing data periods under Sec. 75.34(a)(3), any
available inlet and outlet SO2 concentration values recorded
by an SO2 continuous emission monitoring system; and
(iv) For units substituting a representative NOX emission
rate during missing data periods under Sec. 75.34(a)(3), any available
inlet and outlet NOX emission rate values recorded by a
continuous emission monitoring system.
(c) Specific SO2 emission record provisions for gas-fired
or oil-fired units using optional protocol in appendix D to this part.
In lieu of recording the information in Sec. 75.57(c), the owner or
operator shall record the applicable information in this paragraph for
each affected gas-fired or oil-fired unit for which the owner or
operator is using the optional protocol in appendix D to this part for
estimating SO2 mass emissions:
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average volumetric flow rate of oil, while the unit
combusts oil, with the units in which oil flow is recorded (gal/hr, scf/
hr, m3/hr, or bbl/hr, rounded to the nearest tenth) (flag
value if derived from missing data procedures);
(iii) Sulfur content of oil sample used to determine SO2
mass emission rate (rounded to nearest hundredth for diesel fuel or to
the nearest tenth of a percent for other fuel oil) (flag value if
derived from missing data procedures);
(iv) [Reserved];
(v) Mass flow rate of oil combusted each hour and method of
determination (lb/hr, rounded to the nearest tenth) (flag value if
derived from missing data procedures);
(vi) SO2 mass emission rate from oil (lb/hr, rounded to
the nearest tenth);
(vii) For units using volumetric oil flowmeters, density of oil with
the units in which oil density is recorded and method of determination
(flag value if derived from missing data procedures);
(viii) Gross calorific value of oil used to determine heat input and
method of determination (Btu/lb) (flag value if derived from missing
data procedures);
(ix) Hourly heat input rate from oil, according to procedures in
appendix D to this part (mmBtu/hr, to the nearest tenth);
(x) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest fraction of an hour (in equal increments that can
range from one hundredth to one quarter of an hour, at the option of the
owner or operator)) (flag to indicate multiple/single fuel types
combusted);
(xi) Monitoring system identification code;
(xii) Operating load range corresponding to gross unit load (01-20);
and
(xiii) Type of oil combusted.
(2) For gas-fired units or oil-fired units using the optional
protocol in appendix D to this part for daily manual oil sampling, when
the unit is combusting oil, the highest sulfur content recorded from the
most recent 30 daily oil samples (rounded to the nearest tenth of a
percent).
(3) For gas-fired units or oil-fired units using the optional
protocol in appendix D to this part, when either an assumed oil sulfur
content or density value is used, or when as-delivered oil sampling is
performed:
(i) Record the measured sulfur content, gross calorific value, and,
if applicable, density from each fuel sample; and
(ii) Record and report the assumed sulfur content, gross calorific
value, and, if applicable, density used to calculate SO2 mass
emission rate or heat input rate.
(4) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour.
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(ii) Hourly heat input rate from gaseous fuel, according to
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest
tenth).
(iii) Sulfur content or SO2 emission rate, in one of the
following formats, in accordance with the appropriate procedure from
appendix D to this part:
(A) Sulfur content of gas sample and method of determination
(rounded to the nearest 0.1 grains/100 scf) (flag value if derived from
missing data procedures); or
(B) Default SO2 emission rate of 0.0006 lb/mmBtu for
pipeline natural gas, or calculated SO2 emission rate for
natural gas from section 2.3.2.1.1 of appendix D to this part.
(iv) Hourly flow rate of gaseous fuel, while the unit combusts gas
(100 scfh) and source of data code for gas flow rate.
(v) Gross calorific value of gaseous fuel used to determine heat
input rate (Btu/100 scf) (flag value if derived from missing data
procedures).
(vi) SO2 mass emission rate due to the combustion of
gaseous fuels (lb/hr).
(vii) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest fraction of an hour (in equal increments that
can range from one hundredth to one quarter of an hour, at the option of
the owner or operator)) (flag to indicate multiple/single fuel types
combusted).
(viii) Monitoring system identification code.
(ix) Operating load range corresponding to gross unit load (01-20).
(x) Type of gas combusted.
(5) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Sulfur content (percent, rounded to the nearest hundredth for
diesel fuel and to the nearest tenth for other fuel oil);
(iii) Gross calorific value (Btu/lb); and
(iv) Density or specific gravity, if required to convert volume to
mass.
(6) For each sample of gaseous fuel for sulfur content:
(i) Date of sampling; and
(ii) Sulfur content (grains/100 scf, rounded to the nearest tenth).
(7) For each sample of gaseous fuel for gross calorific value:
(i) Date of sampling; and
(ii) Gross calorific value (Btu/100 scf).
(8) For each oil sample or sample of gaseous fuel:
(i) Type of oil or gas; and
(ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of
appendix D to this part) and value used in calculations, and type of GCV
or density sampling (using codes in tables D-4 and D-5 of appendix D to
this part).
(d) Specific NOX emission record provisions for gas-fired
peaking units or oil-fired peaking units using optional protocol in
appendix E to this part. In lieu of recording the information in
Sec. 75.57(d), the owner or operator shall record the applicable
information in this paragraph for each affected gas-fired peaking unit
or oil-fired peaking unit for which the owner or operator is using the
optional protocol in appendix E to this part for estimating
NOX emission rate. The owner or operator shall meet the
requirements of this section, except that the requirements under
paragraphs (d)(1)(vii) and (d)(2)(vii) of this section shall become
applicable on the date on which the owner or operator is required to
monitor, record, and report NOX mass emissions under an
applicable State or federal NOX mass emission reduction
program, if the provisions of subpart H of this part are adopted as
requirements under such a program.
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average mass flow rate of oil while the unit combusts
oil with the units in which oil flow is recorded (lb/hr);
(iii) Gross calorific value of oil used to determine heat input
(Btu/lb);
(iv) Hourly average NOX emission rate from combustion of
oil (lb/mmBtu, rounded to the nearest hundredth);
(v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest fraction of an hour, in equal increments that can
range from one hundredth to one quarter of an hour, at the option of the
owner or operator);
(vii) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part;
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(viii) NOX monitoring system identification code;
(ix) Fuel flow monitoring system identification code; and
(x) Segment identification of the correlation curve.
(2) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly average fuel flow rate of gaseous fuel, while the unit
combusts gas (100 scfh);
(iii) Gross calorific value of gaseous fuel used to determine heat
input (Btu/100 scf) (flag value if derived from missing data
procedures);
(iv) Hourly average NOX emission rate from combustion of
gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
(v) Heat input rate from gaseous fuel, while the unit combusts gas
(mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest fraction of an hour, in equal increments that
can range from one hundredth to one quarter of an hour, at the option of
the owner or operator);
(vii) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part;
(viii) NOX monitoring system identification code;
(ix) Fuel flow monitoring system identification code; and
(x) Segment identification of the correlation curve.
(3) For each hour when the unit combusts multiple fuels:
(i) Date and hour;
(ii) Hourly average heat input rate from all fuels (mmBtu/hr,
rounded to the nearest tenth); and
(iii) Hourly average NOX emission rate for the unit for
all fuels (lb/mmBtu, rounded to the nearest hundredth).
(4) For each hour when the unit combusts any fuel(s):
(i) For stationary gas turbines and diesel or dual-fuel
reciprocating engines, hourly averages of operating parameters under
section 2.3 of appendix E to this part (flag if value is outside of
manufacturer's recommended range); and
(ii) For boilers, hourly average boiler O2 reading
(percent, rounded to the nearest tenth) (flag if value exceeds by more
than 2 percentage points the O2 level recorded at the same
heat input during the previous NOX emission rate test).
(5) For each fuel sample:
(i) Date of sampling;
(ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous
fuel); and
(iii) Density or specific gravity, if required to convert volume to
mass.
(6) Flag to indicate multiple or single fuels combusted.
(e) Specific SO2 emission record provisions during the
combustion of gaseous fuel. (1) If SO2 emissions are
determined in accordance with the provisions in Sec. 75.11(e)(2) during
hours in which only gaseous fuel is combusted in a unit with an
SO2 CEMS, the owner or operator shall record the information
in paragraph (c)(3) of this section in lieu of the information in
Secs. 75.57(c)(1), (c)(3), and (c)(4), for those hours.
(2) The provisions of this paragraph apply to a unit which, in
accordance with the provisions of Sec. 75.11(e)(3), uses an
SO2 CEMS to determine SO2 emissions during hours
in which only gaseous fuel is combusted in the unit. If the unit
sometimes burns only gaseous fuel that is very low sulfur fuel (as
defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel
and at other times combusts higher sulfur fuels, such as coal or oil, as
primary and/or backup fuel(s), then the owner or operator shall keep
records on-site, in a form suitable for inspection, of the type(s) of
fuel(s) burned during each period of missing SO2 data and the
number of hours that each type of fuel was combusted in the unit during
each missing data period. This recordkeeping requirement does not apply
to an affected unit that burns very low sulfur fuel exclusively, nor
does it apply to a unit that burns such gaseous fuel(s) only during unit
startup.
(f) Specific SO2, NOX, and CO2
record provisions for gas-fired or oil-fired units using the optional
low mass emissions excepted methodology in Sec. 75.19. In lieu of
recording the information in Secs. 75.57(b) through (e), the owner or
operator shall record the following information
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for each affected low mass emissions unit for which the owner or
operator is using the optional low mass emissions excepted methodology
in Sec. 75.19(c):
(1) All low mass emission units shall report for each hour:
(i) Date and hour;
(ii) Unit operating time (units using the long term fuel flow
methodology report operating time to be 1);
(iii) Fuel type (pipeline natural gas, natural gas, other gaseous
fuel, residual oil, or diesel fuel) (note: if more than one type of fuel
is combusted in the hour, indicate the fuel type which results in the
highest emission factors for NOX);
(iv) Average hourly NOX emission rate (lb/mmBtu, rounded
to the nearest thousandth);
(v) Hourly NOX mass emissions (lbs, rounded to the
nearest tenth);
(vi) Hourly SO2 mass emissions (lbs, rounded to the
nearest tenth);
(vii) Hourly CO2 mass emissions (tons, rounded to the
nearest tenth);
(viii) Hourly calculated unit heat input in mmBtu;
(ix) Hourly unit output in gross load or steam load;
(x) The method of determining hourly heat input: unit maximum rated
heat input, unit long term fuel flow or group long term fuel flow;
(xi) The method of determining NOX emission rate used for
the hour: default based on fuel combusted, unit specific default based
on testing or historical data, group default based on representative
testing of identical units, unit specific based on testing of a unit
with NOX controls operating, or missing data value; and
(xii) Control status of the unit.
(2) Low mass emission units using the optional long term fuel flow
methodology to determine unit heat input shall report for each quarter:
(i) Type of fuel;
(ii) Beginning date and hour of long term fuel flow measurement
period;
(iii) End date and hour of long term fuel flow period;
(iv) Quantity of fuel measured;
(v) Units of measure;
(vi) Fuel GCV value used to calculate heat input;
(vii) Units of GCV;
(viii) Method of determining fuel GCV used;
(ix) Method of determining fuel flow over period;
(x) Component-system identification code;
(xi) Quarter and year;
(xii) Total heat input (mmBtu); and
(xiii) Operating hours in period.
[64 FR 28612, May 26, 1999, as amended at 67 FR 40441, 40442, June 12,
2002]