A.
Applicability
1. The provisions of this
Chapter shall apply to any affected facility in the Baton Rouge area (i.e., the
entire parishes of Ascension, East Baton Rouge, Iberville, Livingston, and West
Baton Rouge) and the region of influence (i.e., affected facilities in the
attainment parishes of East Feliciana, Pointe Coupee, St. Helena, and West
Feliciana).
2. The provisions of
this Chapter shall apply during the ozone season, as defined
in Subsection B of this Section, of each year.
3. All affected facilities shall be in
compliance as expeditiously as possible, but by no later than the dates
specified in Subsection J of this Section.
B. Definitions. Unless specifically defined
in this Subsection or in LAC 33:III.111 or 502, the words, terms, and
abbreviations in this Chapter shall have the meanings commonly used in the
field of air pollution control.For purposes of this Chapter only, the following
definitions shall supersede any definitions in LAC 33:III.111 or 502.
Administrative Authority-the secretary of
the Department of Environmental Quality or his designee or the appropriate
assistant secretary or his designee.
Administrator-the administrator, or an
authorized representative, of the U. S. Environmental Protection Agency
(EPA).
Affected Facility- any facility within the
Baton Rouge nonattainment area with one or more affected point sources that
collectively emit or have the potential to emit 25 tons or more per year of
NOx, unless exempted in Subsection C of this Section, or
any facility within the region of influence with one or more affected point
sources that collectively emit or have the potential to emit 50 tons or more
per year of NOx, unless exempted in Subsection C of this
Section. Exempt sources in a facility shall not be included in the
determination of whether it is an affected facility.
Affected Point Source-any point source
located at an affected facility and subject to an emission factor listed in
Paragraph D.1 of this Section or used as part of an alternative plan in
accordance with Subsection E of this Section, unless exempted in Subsection C
of this Section.
Ammonia Reformer-a type of process
heater/furnace located in an ammonia production plant that is designed to heat
a mixture of natural gas and steam to produce hydrogen and carbon
oxides.
Averaging Capacity-the average actual heat
input rate in million British thermal units per hour (MMBtu/hour) at which an
affected point source operated during the ozone season of the two calendar
years of 2000 and 2001 (e.g., the total heat input for the period divided by
the actual hours of operation for the same period). Another period may be used
to calculate the averaging capacity if approved by the department. For units
with permit revisions that legally curtailed capacity or that were permanently
shut down after 1997, the averaging capacity is the average actual heat input
during the last two ozone seasons of operation before the curtailment or
shutdown.
Baton Rouge Nonattainment Area-the entire
parishes of Ascension, East Baton Rouge, Iberville, Livingston, and West Baton
Rouge.
Biomass-defined as bagasse, rice-husks,
wood, or other combustible, vegetation-derived material that is suitable for
use as fuel.
Boiler-any combustion equipment fired with
any solid, liquid, and/or gaseous fuel that is primarily used to produce steam,
or heat water, or any other heat transfer medium for power generation or for
heat to an industrial, institutional, or commercial operation. Equipment that
is operated primarily for waste treatment and that incidentally produces steam
shall not be regulated under this Chapter as a boiler.
Cap-a system for demonstrating compliance
whereby an affected facility, a subset of affected sources at an affected
facility, or a group of affected facilities under common control are operated
to stay below a mass emission rate expressed as mass per unit of time. The
allowable mass emission rate is calculated by adding the allowable emissions
for each affected point source. The allowable emission is the product of the
source's average hourly heat input in MMBtu/hour (not to exceed any applicable
permit limitations) based on the highest consecutive 30-day period during the
ozone seasons of 2000 and 2001 and the applicable factor in Paragraph D.1 of
this Section.
Chemical Processing Gas Turbine-a gas
turbine that vents its exhaust gases into the operating stream of a chemical
process.
Coal-all solid fuels classified as
anthracite, bituminous, subbituminous, or lignite by the American Society for
Testing and Materials, Designation D388-77. For the purposes of this Chapter,
coal shall also include petroleum coke, solid carbon residues from the
processing of petroleum products and coal-derived synthetic fuels, including
but not limited to, solvent refined coal, coal-oil mixtures, and coal-water
mixtures.
Combined Cycle-a combustion equipment
configuration that generates electrical or mechanical power with a stationary
gas or liquid-fired turbine and/or a stationary internal combustion engine and
that recovers heat from the discharge within equipment to heat water or
generate steam.
Continuous Emissions Monitoring System
(CEMS)-the total equipment that may be required to meet the data
acquisition and availability requirements, used to sample, condition, if
applicable, analyze, and provide a record of emissions.
Daily Average-an average of the hourly data
for one calendar day starting at 12-midnight and continuing until the following
12-midnight.
Department-the Louisiana Department of
Environmental Quality.
Elapsed Run-Time Meter-an instrument
designed to measure and record the time that an affected point source has run
during a designated period.
Electric Power Generating System-all
boilers, stationary internal combustion engines, stationary gas turbines, and
other combustion equipment within an affected facility that are used to
generate electric power and that are owned or operated by a municipality, an
electric cooperative, an independent power producer, a public utility, or a
Louisiana Public Service Commission regulated utility company, or any of its
successors.
Emergency Standby Gas Turbine or Engine-a
gas turbine or engine operated as an electrical or a mechanical power source
for an affected facility when the primary source has been disrupted or
discontinued during an emergency due to circumstances beyond the control of the
owner or operator of the affected facility and that is operated only during
such an emergency or when normal testing procedures, as recommended by the
manufacturer, are being performed. The definition includes a stationary gas
turbine or a stationary internal combustion engine that is used at a nuclear
power plant as an emergency generator that is subject to Nuclear Regulatory
Commission (NRC) regulations and a stationary internal combustion engine that
is used for the emergency pumping of water for either fire protection or flood
relief. This term does not include an electric generating unit in peaking
service.
F Factor-the ratio of the gas volume of the
products of combustion to the heat content of the fuel, typically expressed in
dry standard cubic feet (dscf) per MMBtu.
Facility-a contiguous area under common
control that contains various types of equipment that emit or have the
potential to emit NOx.
Facility-Wide Averaging
Plan-an alternative emission plan whereby an affected facility (or
affected facilities with a common owner or operator) with multiple affected
point sources of NOx emissions achieves the required
reduction by a different mix of controls from that mandated by Subsection D of
this Section. Some affected point sources may be over-controlled (more
restrictive than the regulation) or shut down in order to offset other affected
point sources that are under-controlled (less restrictive than the regulation)
or not controlled, provided the required overall NOx
reduction is met.
Facility-Wide Emission
Factor-the total average allowable NOx emission
factor in pound NOx/MMBtu for affected point sources
when firing at their averaging capacities.
Flare-a type of equipment specifically
designed for combusting gaseous vents at an above-ground location.
Fluid Catalytic Cracking Unit Regenerator-a
unit in a refinery where catalyst is recovered (regenerated) by burning off
coke and other deposits with hot air. The term includes the associated
equipment for controlling air pollutant emissions and for heat recovery.
Gas-any gaseous substance that can be used
as a fuel to create heat and/or mechanical energy including natural gas,
synthetically produced gas from coal or oil, gaseous substances from the
decomposition of organic matter, and gas streams that are
by-products of a manufacturing process.
Heat Input-the heat released due to fuel
combustion in an affected point source, using the higher heating value of the
fuel, excluding the sensible heat of the incoming combustion air.
Higher Heating Value-a measurement of the
heat evolved during the complete combustion of a substance, including the
latent heat of condensation of any water that is produced.
Horsepower Rating-the engine manufacturer's
maximum continuous load rating at the lesser of the engine or driven
equipment's maximum published continuous speed.
Incinerator-same as defined in LAC
33:III.111.
International Standards Organization (ISO)
Conditions-standard conditions of 59°F, 1.0 atmosphere, and 60 percent
relative humidity.
Kilns and Ovens-combustion equipment used
for drying, baking, cooking, and calcining. Kilns can also be used for the
treatment of solid wastes.
Lean-Burn Engine-a spark-ignited or
compression-ignited, Otto cycle, diesel cycle, or two-stroke engine that is not
capable of being operated with an exhaust stream oxygen concentration equal to
or less than 1.0 percent, by volume on a dry basis, as originally designed by
the manufacturer. The exhaust gas oxygen concentration shall be determined from
the uncontrolled exhaust stream.
Liquid Fuel-any substance in a liquid state
that can be used as a fuel to create heat and/or mechanical energy
including:
a. crude oil, petroleum oil,
fuel oil, residual oil, distillate, or other liquid fuel derived from crude oil
or petroleum;
b. liquid by-products
of a manufacturing process or a petroleum refinery; and
c. any other liquid fuel.
Low Ozone Season Capacity Factor Boiler or Process
Heater/Furnace- a boiler or process heater/furnace in the Baton Rouge
nonattainment area with a maximum rated capacity greater than or equal to 40
MMBtu/hour and an ozone season average heat input less than or equal to 12.5
MMBtu/hour, using a 30-day rolling average; or in the region of influence with
a maximum rated capacity greater than or equal to 80 MMBtu/hour and an ozone
season average heat input less than or equal to 25 MMBtu/hour, using a 30-day
rolling average.
Malfunction-any sudden and unavoidable
failure, as defined in LAC 33:III.111.
Maximum Rated Capacity-the maximum annual
design capacity, as determined by the equipment manufacturer or as proven by
actual maximum annual performance in the field, unless the affected point
source is limited by permit condition to a lesser annual capacity, in which
case the limiting condition shall be used as the maximum rated
capacity. Where the capacity of a point source is limited by an
operating cap applicable to a group of point sources (e.g., several units
capped to a combined total firing rate), the total firing rate cap shall be
divided by the number of point sources in the cap to arrive at an equivalent
maximum rated capacity. This equivalent maximum rated capacity
shall be used only to determine the applicability of the emission factors and
monitoring provisions of this Chapter.
Megawatt (MW) Rating-the continuous power
rating or mechanical equivalent by a stationary gas turbine manufacturer at ISO
conditions, without consideration to the increase in turbine shaft output
and/or decrease in turbine fuel consumption by the addition of energy recovered
from exhaust heat.
Nitric Acid Production Unit-a facility that
produces nitric acid by any process.
Nitrogen Oxides
(NOx)-the sum of the nitric oxide and nitrogen
dioxide in a stream measured in accordance with Subsection G of this
Section.
Number 6 Fuel Oil-fuel oil of the grade
that is classified number 6, according to ASTM standard specification for
classification of fuel oil by ASTM D396-84.
Ozone Season- except as provided in LAC
33:III.2202, the period May 1 to September 30, inclusive, of each year.
Peaking Service-a stationary gas turbine
that is operated intermittently to produce energy. To be in peaking service,
the annual electric output (MW-hour) for the affected point source shall be
less than the product of 2500 hours and the MW rating of the turbine.
Permanent Shutdown-a shutdown of an
affected point source where the owner or operator has filed a notice of
permanent shutdown with the department or where the department, through a
permit revision or final permit, has removed the affected point source from the
applicable permit. (To maintain temporary shutdown status, a source must be
maintained in good working order and not dismantled or cannibalized, must still
be listed in the applicable permit, must still be listed on the department's
emission inventory, and must continue to pay appropriate fees.)
Predictive Emissions Monitoring System
(PEMS)-a system that uses process and other parameters as inputs to a
computer program or other data reduction system to produce values in terms of
the applicable emission limitation or standard.
Process Heater/Furnace-any combustion
equipment fired with solid, liquid, and/or gaseous fuel that is used to
transfer heat to a process fluid, superheated steam, or water for the purpose
of heating the process fluid or causing a chemical reaction. The term
process heater/furnace does not apply to any unfired waste
heat recovery boiler that is used to recover sensible heat from the exhaust of
any combustion equipment, or to boilers as defined in this Subsection.
Pulp Liquor Recovery Furnace-either a
straight Kraft recovery furnace or a cross recovery furnace as defined in 40
CFR 60 Subpart BB.
Region of Influence-an area to the north of
the Baton Rouge nonattainment area that encompasses affected facilities in the
attainment parishes of East Feliciana, Pointe Coupee, St. Helena, and West
Feliciana.
Rich-Burn Engine-all stationary
reciprocating engines that do not fit the definition of lean-burn.
Sensible Heat-the heat energy stored in a
substance as a result of an increase in its temperature.
Stationary Gas Turbine-any turbine system
that is gas and/or liquid fuel fired and that is either attached to a
foundation at an affected facility or is portable equipment operated at a
specific affected facility for more than 60 days in any ozone season.
Stationary Internal Combustion Engine-a
reciprocating engine that is either gas and/or liquid fuel fired and that is
either attached to a foundation or is portable equipment operated at a specific
affected facility for more than six months at a time. This term does not
include locomotive engines or self-propelled construction engines.
Supplemental Firing Unit-a unit with
burners that is installed in the exhaust duct of a stationary gas turbine or
internal combustion engine for the purpose of supplying supplemental heat to a
downstream heat recovery unit.
Thirty-Day (30-Day) Rolling Average- an
average, calculated daily, of all hourly data for the last 30 days for an
affected point source. At the beginning of each ozone season, use one of the
following methods to calculate the initial 30-day averages:
a. calculate and record the average of all
hourly readings taken during the first day of the ozone season for day one,
then the average of all hourly readings taken during the first and second days
for day two, and so on until the first full 30-day average falling entirely
within the ozone season is reached;
b. calculate and record a 30-day
rolling average for day one of the ozone season using the hourly
readings from that day and the previous 29 calendar days, for the second day of
the ozone season using the readings from the first two ozone season days and
the preceding 28 calendar days, and so on until the first full 30-day average
falling entirely within the current ozone season is reached; or
c. calculate and record a
30-day
rolling average for day one of the ozone season using the hourly
readings from that day and the last 29 days of the previous ozone season, for
the second day of the ozone season using the readings from the first two
current ozone season days and the last 28 days of the previous ozone season,
and so on until the first full 30-day average falling entirely within the
current ozone season is reached.
Totalizing Fuel Meter-a meter or metering
system that provides a cumulative measure of fuel consumption.
Trading Allowances-the tons of
NOx emissions that result from over-controlling,
permanently reducing the operating rate of, or permanently shutting down, an
affected point source located within the Baton Rouge nonattainment area or the
region of influence. The allowances are determined in accordance with LAC
33:III.607.C and from the emission factors required by Subsection D of this
Section for the affected point source and the enforceable emission factor
assigned by the owner or operator in accordance with Subsection E of this
Section. Baseline emissions shall be the lower of actual emissions or adjusted
allowable emissions, as defined in LAC 33:III.605. Trading allowances will be
granted only for reductions that are real, quantifiable, permanent, and
federally enforceable. NOx reductions that are used in a
facility-wide averaging plan cannot also be used in a trading
plan.
Wood-wood, wood residue, bark, or any
derivative fuel or residue thereof in any form, including but not limited to,
sawdust, sander dust, wood chips, scraps, slabs, millings, shavings, and
processed pellets made from wood or other forest residues.
C. Exemptions. The following categories of
equipment or processes located at an affected facility within the Baton Rouge
nonattainment area or the region of influence are exempted from the provisions
of this Chapter:
1. boilers and process
heater/furnaces with a maximum rated capacity of less than 40 MMBtu/hour in the
Baton Rouge nonattainment area or less than 80 MMBtu/hour in the region of
influence;
2. stationary gas
turbines with a megawatt rating based on heat input of less than 5 MW in the
Baton Rouge nonattainment area or less than 10 MW in the region of
influence;
3. stationary internal
combustion engines as follows:
a. rich-burn
engines with a rating of less than 150 horsepower (Hp) in the Baton Rouge
nonattainment area or less than 300 Hp in the region of influence;
and
b. lean-burn engines with a
rating of less than 150 Hp in the Baton Rouge nonattainment area or less than
1500 Hp in the region of influence;
4. low ozone season capacity factor boilers
and process heater/furnaces, as defined in Subsection B of this Section, in
accordance with Paragraph H.11 of this Section;
5. stationary gas turbines and stationary
internal combustion engines, that are:
a.
used in research and testing;
b.
used for performance verification and testing;
c. used solely to power other engines or
turbines during start-ups;
d.
operated exclusively for fire fighting or training and/or flood
control;
e. used in response to and
during the existence of any officially declared disaster or state of
emergency;
f. used directly and
exclusively for agricultural operations necessary for the growing of crops or
the raising of fowl or animals; or
g. used as chemical processing gas
turbines;
6. any point
source, in accordance with Paragraph H.12 of this Section, that operates less
than 3 hours per day, using a 30-day rolling average, during the ozone
season;
7.
flares,
incinerators, and kilns and ovens, as defined
in Subsection B of this Section;
8.
Reserved.
9. any point source used
solely to start up a process;
10.
any point source firing biomass fuel that supplies greater than 50 percent of
the heat input on a monthly basis;
11. any point source at a sugar
mill;
12. fluid catalytic cracking
unit regenerators;
13. pulp liquor
recovery furnaces;
14. diesel-fired
stationary internal combustion engines;
15. any affected point source that is
required to meet a more stringent state or federal NOx
emission limitation, whether by regulation or permit. In this case, the
monitoring, reporting, and recordkeeping requirements shall be in accordance
with the more stringent regulation or permit and not this Chapter. If the
applicable regulation or permit does not specify monitoring, reporting and
recordkeeping requirements, the provisions of Subsections H and I of this
Section shall apply;
16. wood-fired
boilers that are subject to 40 CFR
60, Subpart Db;
17. nitric acid production units that are
subject to 40 CFR
60, Subpart G or LAC 33:III.2307;
18. any affected point source firing fuel oil
during a period of emergency and approved by the administrative
authority;
19. boilers and
industrial furnaces treating hazardous waste and regulated under LAC
33:V.Chapter 30 or 40 CFR Part
264,
265, or
266, including halogen acid
furnaces and sulfuric acid regeneration furnaces; and
20. high efficiency boilers or other
combustion devices regulated under the Toxic Substance Control Act PCB rules
under 40 CFR Part
761.
D. Emission Factors
1. The following tables list
NO
x emission factors that shall apply to affected point
sources located at affected facilities in the Baton Rouge nonattainment area or
the region of influence.
|
Table D-1A
NOx Emission Factors
for Sources in the Baton Rouge Nonattainment Area
|
|
Category
|
Maximum Rated Capacity
|
NOx Emission
Factora
|
|
Electric Power Generating System Boilers
|
|
Coal-fired
|
>/=40 to<80 MMBtu/Hour
|
0.50 pound/MMBtu
|
|
>/=80 MMBtu/Hour
|
0.21 pound/MMBtu
|
|
Number 6 Fuel Oil-fired
|
>/=40 to <80 MMBtu/Hour
|
0.30 pound/MMBtu
|
|
>/=80 MMBtu/Hour
|
0.18 pound/MMBtu
|
|
All Others (gaseous or liquid)
|
>/=40 to <80 MMBtu/Hour
|
0.20 pound/MMBtu
|
|
>/=80 MMBtu/Hour
|
0.10 pound/MMBtu
|
|
Industrial Boilers
|
|
All Fuels
|
>/=40 to <80 MMBtu/Hour
|
0.20 pound/MMBtu
|
|
>/=80 MMBtu/Hour
|
0.10 pound/MMBtu
|
|
Process Heater/Furnaces
|
|
Ammonia Reformers
|
>/=40 to <80 MMBtu/Hour
|
0.30 pound/MMBtu
|
|
>/=80 MMBtu/Hour
|
0.23 pound/MMBtu
|
|
All Others
|
>/=40 to <80 MMBtu/Hour
|
0.18 pound/MMBtu
|
|
>/=80 MMBtu/Hour
|
0.08 pound/MMBtu
|
|
Stationary Gas Turbines
|
|
Peaking Service, Fuel Oil-fired
|
>/=5 to <10 MW
|
0.37 pound/MMBtu
|
|
>/=10 MW
|
0.30 pound/MMBtu
|
|
Peaking Service, Gas-fired
|
>/=5 to <10 MW
|
0.27 pound/MMBtu
|
|
>/=10 MW
|
0.20 pound/MMBtu
|
|
All Others
|
>/=5 to <10 MW
|
0.24 pound/MMBtub
|
|
>/=10 MW
|
0.16 pound/MMBtuc
|
|
Stationary Internal Combustion Engines
|
|
Lean-burn
|
>/=150 to < Hp
|
10 g/Hp-hour
|
|
>/=320 Hp
|
4 g/Hp-hour
|
|
Rich-burn
|
>/=150 to <300 Hp
|
2 g/Hp-hour
|
|
|
>/=300 Hp
|
2 g/Hp-hour
|
a based on the higher heating
value of the fuel
b equivalent to 65 ppmv (15
percent O2, dry basis) with an F factor of 8710 dscf/MMBtu
c equivalent to 43 ppmv (15
percent O2, dry basis) with an F factor of 8710 dscf/MMBtu
|
Table D-1B
NOx Emission Factors
for Sources in the Region of Influence
|
|
Category
|
Maximum Rated Capacity
|
NOx Emission Factor
a
|
|
Electric Power Generating System Boilers
|
|
Coal-fired
|
/=80 MMBtu/Hour
|
0.21 pound/MMBtu
|
|
Number 6 Fuel Oil-fired
|
/=80 MMBtu/Hour
|
0.18 pound/MMBtu
|
|
All Others (gaseous or liquid)
|
/=80 MMBtu/Hour
|
0.10 pound/MMBtu
|
|
Industrial Boilers
|
|
All Fuels
|
/=80 MMBtu/Hour
|
0.10 pound/MMBtu
|
|
Process Heater/Furnaces:
|
|
Ammonia Reformers
|
/=80 MMBtu/Hour
|
0.23 pound/MMBtu
|
|
All Others
|
/=80 MMBtu/Hour
|
0.08 pound/MMBtu
|
|
Stationary Gas Turbines
|
|
Peaking Service, Fuel Oil-fired
|
/=10 MW
|
0.30 pound/MMBtu
|
|
Peaking Service, Gas-fired
|
/=10 MW
|
0.20 pound/MMBtu
|
|
All Others
|
/=10 MW
|
0.16 pound/MMBtub
|
|
Stationary Internal Combustion Engines
|
|
Lean-burn
|
/=1500 Hp
|
4 g/Hp-hour
|
|
Rich-burn
|
/=300 Hp
|
2 g/Hp-hour
|
a all factors are based on the
higher heating value of the fuel
b equivalent to 43 ppmv (15
percent O2, dry basis) with an F factor of 8710 dscf/MMBtu
2. Any electric power generating system
boiler that operates with a combination of fuels shall comply with an adjusted
emission factor calculated as follows:
a. if
a combination of fuels is used normally, the emission factor from Paragraph D.1
of this Section shall be adjusted by the weighted average heat input of the
fuels based on the ozone season average usage in 2000 and 2001, or another
period if approved by the department;
b. if the boiler is normally fired with a
primary fuel and a secondary fuel is available for back-up, the unit shall
comply with the emission factor for the primary fuel while firing the primary
fuel and with the emission factor for the secondary fuel while firing the
secondary fuel. In addition, the usage of the secondary fuel shall be limited
to the ozone season average usage of the secondary fuel in 2000 and 2001, or
another period if approved by the department; and
c. in either case, if the secondary fuel is
less than 10 percent of the weighted average, the owner or operator may choose
to comply with the unadjusted limit for the primary fuel.
3. For affected point sources in an electric
power generating system, the emission factors from Subsection D of this Section
shall apply as the mass of NO
x emitted per unit of heat
input (pound NO
x per MMBtu), on a 30-day rolling average
basis. Alternatively, a facility may choose to comply with a ton per day or a
pound per hour cap provided that monitoring is installed, calibrated,
maintained, and operated to demonstrate compliance with the cap. The cap for a
facility or for multiple facilities under common control is calculated by
adding the products of the factor from Paragraph D.1 of this Section and the
average hourly heat input in MMBtu/hour (not to exceed any applicable permit
limitations) based on the highest consecutive 30-day period during the ozone
seasons of 2000 and 2001 for each affected point source as follows.
Equation D-1
Click Here To View
Image
where:
HIi = the average hourly heat input
based on the highest consecutive 30-day period during the ozone seasons of 2000
and 2001 of each point source (MMBtu/hour)
i = each point source included in the cap
N = the total number of point sources included in the
cap
Rli = the limit for each point
source from Subsection D of this Section (pound
NOx/MMBtu)
4. For all other affected point sources, the
emission factors from Subsection D of this Section shall apply as the mass of
NOx emitted per unit of heat input (pounds
NOx per MMBtu or grams NOx per
Hp-hour), on a 30-day rolling average basis. Alternatively, a facility may
choose to comply with a cap as detailed in Paragraph D.3 of this Section,
provided that a system, approved by the department, is installed, calibrated,
maintained, and operated to demonstrate compliance.
5. If one affected point source discharges in
part or in whole to another affected point source, the portion discharging into
the second point source shall be treated as emanating from the second point
source and shall be controlled to the same limit as that specified for the
second point source, while the portion discharging directly to the atmosphere
from the first point source shall be controlled to the limit of the first point
source. This term shall not include a combined cycle unit that discharges into
a supplemental firing unit or other type of combustion equipment. For this type
of point source, the emissions shall be controlled as follows:
a. for the turbines and/or engines, at the
appropriate limits for the turbines and/or engines alone; and
b. for the supplemental firing unit or other
type of combustion equipment, at the appropriate limit for the supplemental
firing or combustion equipment with the measured emission values adjusted for
the emissions coming from the turbines and/or engines.
6. Where a common stack is used to collect
vents from affected point sources or affected point sources and exempt point
sources and monitoring and/or testing of individual units is not feasible, the
department, upon application from the owner or operator, shall specify
alternative methods to demonstrate compliance with the emission factors of this
Subsection.
7. Any affected point
source firing gaseous fuel that contains hydrogen and/or carbon monoxide may
apply a multiplier, as calculated below, to the appropriate emission factor
given in Paragraph D.1 of this Section. The total hydrogen and/or carbon
monoxide volume in the gaseous fuel stream is divided by the total gaseous fuel
flow volume to determine the volume percent of hydrogen and/or carbon monoxide
in the fuel supply. In order to apply this multiplier, the owner or operator of
the affected point source shall sample and analyze the fuel gas composition for
hydrogen and/or carbon monoxide in accordance with Paragraph G.5 of this
Section.
Equation D-2
Click Here To View
Image
8. The
owner or operator of a stationary gas turbine using a fuel that has an F factor
different than 8710 dscf/MMBtu may adjust the allowable emission factor shown
in Paragraph D.1 of this Section. The adjustment is made by dividing the actual
F factor (dscf/MMBtu) of the fuel by 8710 and multiplying the result by 0.16 to
get the adjusted allowable emission factor. The use of this option shall be
detailed in the permit application or in the optional compliance plan described
in Paragraph F.7 of this Section.
9. On a day that is designated as an Ozone
Action Day by the department, a facility shall not fire an affected point
source with Number 6 fuel oil or perform testing of emergency and training
combustion units without prior approval of the administrative authority. If a
facility has received approval from the administrative authority for a plan to
use Number 6 fuel oil, this is considered prior approval for purposes of this
Paragraph.
E.
Alternative Plans
1. Facility-Wide Averaging
Plan. A facility-wide averaging plan is established in this Chapter for single
affected facilities and multiple affected facilities that are owned or operated
by the same entity. For sources located within the Baton Rouge nonattainment
area or the region of influence, an owner or operator of one or more affected
facilities may use the facility-wide averaging plan as an alternative means of
compliance with the emission factors from Subsection D of this Section. A
request for approval to use a facility-wide averaging plan, that includes the
details of the plan, shall be submitted to the department either separately or
with the permit application or in the optional compliance plan described in
Paragraph F.7 of this Section. A facility-wide averaging plan submitted under
this provision shall be approved if the department determines that it will
provide emission reductions equivalent to or more than that required by the
emission factors in Subsection D of this Section and the plan establishes
satisfactory means for determining initial and continuous compliance, including
appropriate monitoring and recordkeeping requirements. Approval of the
alternative plans by the administrative authority does not necessarily indicate
automatic approval by the administrator.
a.
An owner or operator who elects to use a facility-wide averaging plan for
compliance shall establish an emission factor for each applicable affected
point source such that if each affected point source was operated at its
averaging capacity, the cumulative emission factor in pounds
NO
x/MMBtu from all point sources in the averaging group
would not exceed the facility-wide emission factor, as shown in Equation E-3.
The equations below shall be used to calculate the cumulative emission rate and
the facility-wide emission factor.
Click Here To View
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where:
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where:
fi = fraction of total system
averaging capacity for point source i
HIi = the averaging capacity of each
point source (MMBtu/hour)
i = each point source in the averaging group
N = the total number of point sources in the averaging
group
Rai = the limit assigned by the owner
to each point source in the averaging plan (pound
NOx/MMBtu)
Rli = the limit for each point source
from Subsection D of this Section (pound
NOx/MMBtu)
FL = facility-wide emission factor (pound
NOx/MMBtu) of all point sources included in the
averaging plan
b. An owner
or operator of an electric power generating system that chooses to use an
averaging plan shall demonstrate compliance by either of the following methods:
i. operating such that each affected point
source does not exceed its assigned individual limit in pound
NOx/MMBtu on a 30-day rolling average basis;
or
ii. complying with a cap as
described in Paragraph D.3 of this Section, provided that a monitoring system
is installed, calibrated, maintained, and operated to demonstrate compliance
with the cap.
c. Owners
or operators of all other affected point sources that choose to use an
averaging plan shall demonstrate compliance by either of the following methods:
i. operating such that each affected point
source does not exceed its assigned individual limit in pound
NOx/MMBtu on a 30-day rolling average basis;
or
ii. complying with a cap as
described in Paragraph D.3 of this Section, provided a system, approved by the
department, is installed, calibrated, maintained, and operated to demonstrate
compliance with the cap.
d. An owner or operator that chooses to use
the provisions of Clause E.1.b.i or E.1.c.i of this Section to demonstrate
compliance in an averaging plan shall include in the submitted plan a
description of the actions that will be taken if any under-controlled unit is
operated at more than 10 percent above its averaging capacity
(HIi in Subparagraph E.1.a of this Section). Such
actions may include a comparison of the total current emissions from all units
in the averaging plan to the total emissions that would result if the units in
the plan were operated in accordance with Subsection D of this Section, other
reviews, reporting, and/or mitigation actions. If the department determines
that the actions are not adequate to prevent an increase of emissions over the
total emissions that would result if the units were operated in accordance with
Subsection D of this Section, the department shall require that the averaging
plan and/or the action plan be revised or shall disallow the use of the
averaging plan.
e. The owner or
operator of affected point sources complying with the requirements of this
Subsection can include in the plan either all of the affected point sources at
the facility or select only certain sources to be included.
f. NOx reductions
accomplished after 1997 through curtailments in capacity of a point source with
a permit revision or by permanently shutting down the point source may be
included in the averaging plan. In order to include a unit with curtailed
capacity or that has been permanently shut down in the averaging plan, the old
averaging capacity, determined from the average of the two ozone seasons prior
to the capacity curtailment or shutdown, or such other two-year period as the
department may approve, shall be used to calculate the unit's contribution to
the term FL. The new averaging capacity, determined from the enforceable permit
revision, shall be multiplied by the owner-assigned limit to calculate the
contribution of the curtailed unit to the cumulative emission factor for the
averaging group. For a shut down source, the contribution to the cumulative
emission factor shall be zero.
g.
NOx reductions from post 1997 modifications to exempted
point sources, as defined in Subsection C of this Section, may be used in a
facility-wide averaging plan. If a unit exempted in Subsection C of this
Section is included in an averaging plan, the term Rli
in Equation E-1 shall be established, in accordance with Subsection G of this
Section, from a stack test or other determination of emissions approved by the
department that was performed before the NOx reduction
project was implemented, and the term Rai shall be
established from the owner-assigned emission factor in accordance with
Subparagraph E.1.a of this Section. For the case of a point source exempted by
Paragraph C.15 of this Section, if the permit limits were established after
1997 and were not required by a state or federal regulation, the source may be
included in an averaging plan, with the term Rli taken
from Table D-1A or D-1B in Paragraph D.1 of this Section.
h. Solely for the purpose of calculating the
facility-wide emission factor, the allowable emission factor (pound
NOx/MMBtu) for each affected stationary internal
combustion engine is the applicable NOx emission factor
from Subsection D of this Section (g/Hp-hour) divided by the product of the
engine manufacturer's rated heat rate (expressed in Btu/Hp-hour) at the
engine's Hp rating and 454 x10-6.
i. The owner or operator of affected point
sources complying with the requirements of this Subsection in accordance with
an emissions averaging plan shall carry out recordkeeping that includes, but is
not limited to, a record of the data on which the determination of each point
source's hourly, daily, or 30-day, as appropriate, compliance with the
facility-wide averaging plan is based.
2. Trading Plan. Trading is established in
this Chapter as an alternate means of compliance with the emission factors from
Subsection D of this Section. Within the Baton Rouge nonattainment area and the
region of influence, trading allowances, as defined in
Subsection B of this Section, may be traded between affected facilities owned
by different companies in a manner consistent with LAC 33:III.617.C.3. The
approval to use trading shall be requested in the permit application or in the
optional compliance plan described in Paragraph F.7 of this Section. A trading
plan submitted under this provision shall be approved if the department
determines that it will provide NOx emission reductions
equivalent to or more than that required by the emission factors of Subsection
D of this Section and the plan establishes satisfactory means for determining
ongoing compliance, including appropriate monitoring and recordkeeping
requirements. Approval of trading plans by the administrative authority does
not necessarily indicate automatic approval of the administrator.
F. Permits
1. Authorization to Install and Operate
NO
x Control Equipment
a. An owner or operator may obtain approval
to install and operate NOx control equipment that does
not result in ammonia emissions above the minimum emission rate (MER) in LAC
33:III.Chapter 51 by submitting documentation in accordance with LAC
33:III.511. This documentation shall include an estimate of any carbon monoxide
(CO), sulfur dioxide (SO2), particulate matter
(PM10), and/or volatile organic compound (VOC) emission
increases associated with the NOx control technology. If
approved, the administrative authority shall grant an authorization to
construct and operate in accordance with LAC 33:III.501.C.3. Any appropriate
permit application reflecting the emission reduction shall be submitted to the
department and deemed administratively complete no later than 180 days after
commencement of operation and in accordance with the procedures of LAC
33:III.Chapter 5.
b. In accordance
with LAC 33:III.5111.C, installation of NOx control
equipment that results in ammonia emissions above the MER in LAC 33:III.Chapter
51 shall not commence until a permit or permit modification has been approved
by the administrative authority. In accordance with LAC 33:III.5107.D.1, the
administrative authority shall provide at least 30 days for public comment
before issuing any such permit.
2. Alternatively to Subparagraph F.1.a of
this Section, an owner or operator of an affected facility that is operating
with a Louisiana air permit may submit a completed permit modification
application for the changes proposed to comply with this Chapter.
3. Any owner or operator with an affected
facility that has retained grandfathered status, as described in LAC
33:III.501.B.6, shall submit an application in accordance with LAC
33:III.501.C.1 for the changes proposed to comply with this Chapter.
4. Duty to Supplement. In accordance with LAC
33:III.517.C, if an owner or operator has a permit application on file with the
department, but the department has not released the proposed permit, the
applicant shall supplement the application as necessary to address this
Chapter.
5. Prevention of
Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR)
Considerations. A significant net emissions increase in
NO
x, CO, SO
2,
PM
10, and/or VOC in accordance with LAC 33:III.504 or
509, that is a direct result of, and incidental to, the installation of
NO
x control equipment or implementation of a
NO
x control technique required to comply with the
provisions of this Chapter shall be exempt from the requirements of LAC
33:III.509 and/or 504, as appropriate, provided the following conditions are
met:
a. the project shall not:
i. cause or contribute to a violation of the
national ambient air quality standard (NAAQS); or
ii. adversely affect visibility or other air
quality related value (AQRV) in a class I area;
b. any increase in CO,
SO
2, PM
10, and/or VOC emissions
shall be:
i. quantified in the submittal
required by Paragraphs F.1-4 of this Section; and
ii. tested in accordance with Subsection G of
this Section, as applicable;
c. notwithstanding the requirements of LAC
33:III.504, Table 1, a significant net increase of VOC emissions at an affected
facility located in the Baton Rouge nonattainment area shall be offset at a
ratio of at least 1:1. Offsets shall be surplus, permanent, quantifiable, and
federally enforceable and calculated in accordance with LAC 33:III.Chapter 6;
and
d. a 30-day public comment
period shall be provided in accordance with LAC 33:III.519.C prior to issuance
of a permit or permit modification.
6. Increases above the MER in toxic air
pollutant (TAP) emissions shall be subject to the applicable requirements of
LAC 33:III.Chapter 51.
7. When
pre-permit application approval of plans is desired by an owner or operator, a
compliance plan may be submitted in accordance with this Subsection. The
administrative authority shall approve the plan if it contains all of the
required information to determine that the affected sources will be in
compliance with this Chapter and is accurate. The compliance plan may address
individual point sources, groups of point sources, or all point sources at the
facility, as determined by the owner. The following information shall be
submitted as appropriate:
a. the facility
designation, as indicated by the identification number, submitted to the Office
of Environmental Services;
b. a
list of all units in the compliance plan, the emission point number as
designated on the emission inventory questionnaire, the averaging capacity, and
the maximum rated capacity;
c.
identification of all combustion units with a claimed exemption in accordance
with Subsection C of this Section, and the rule basis for the claimed
exemption;
d. a list of any units
that have been, or will be, curtailed or permanently shut down;
e. for each unit, the actual emission factor
that will be used to achieve compliance;
f. the control technology to be applied for
each unit subject to control, and an anticipated construction schedule for each
control device including the dates for completion of engineering, submission of
permit applications, start and finish of construction, and initial start-up;
and
g. the calculations to
demonstrate that each unit will achieve the required NOx
emission rate.
G. Initial Demonstration of Compliance
1. Emissions testing to demonstrate initial
compliance with the NOx emission factors of Subsection D
of this Section, or with emission limits that are part of an alternative plan
under Subsection E of this Section, for affected point sources operating with a
CEMS or PEMS that has been certified in accordance with Subsection H of this
Section is not required. The certification of the CEMS or PEMS shall be
considered demonstration of initial compliance. Testing for initial compliance
is not required for an existing CEMS or PEMS that meets the requirements of
Subsection H of this Section.
2.
Emissions testing is required for all point sources that are subject to the
emission limitations of Subsection D of this Section or used in one of the
alternative plans of Subsection E of this Section. Test results must
demonstrate that actual NOx emissions are in compliance
with the appropriate limits of this Chapter. As applicable, CO,
SO2, PM10, and VOC shall also be
measured if modifications, done to comply with this Chapter, could cause an
increase in emissions of any of these compounds. Performance testing of these
point sources shall be performed in accordance with the schedule specified in
Subsection J of this Section.
3.
The tests required by Paragraph G.2 of this Section shall be performed by the
test methods referenced in Paragraph G.5 of this Section, except as approved by
the administrative authority in accordance with Paragraph G.7 of this Section.
Test results shall be reported in the units of the applicable emission factors
and for the corresponding averaging periods.
4. Emission testing conducted in the three
years prior to the initial demonstration of compliance date may be used to
demonstrate compliance with the limits of Subsection D or E of this Section, if
the owner or operator demonstrates to the department that the prior testing
meets the requirements of this Subsection. The request to waive emissions
testing according to this Paragraph shall be included in the permit
application. The department reserves the right to request performance testing
or CEMS performance evaluation upon 60 days notice.
5. Compliance with the emission
specifications of Subsection D or E of this Section for affected point sources
operating without CEMS or PEMS shall be demonstrated while operating at the
maximum rated capacity, or as near thereto as practicable. The stack tests
shall be performed according to emissions testing guidelines located on the
department website under Air Quality Assessment/Emission Testing Program. Three
minimum 1-hour tests, or three minimum 20-minute tests for turbines, shall be
performed and the following methods from 40 CFR Part
60, Appendix A shall be
used:
a. Methods 1, 2, 3, and 4 or 19, with
prior approval, for exhaust gas flow;
b. Method 3A or 20 for
O2 ;
c.
Method 5 for PM;
d. Method 6C for
SO2;
e.
Method 7E or 20 for NOx;
f. Method 10 or 10A for CO;
g. Method 18 or 25A for VOC;
h. modified Method 5, or a
department-approved equivalent, for NH3;
and/or
i. American Society of
Testing and Materials (ASTM) Method D1945-96 or ASTM Method D2650-99 for fuel
composition; ASTM Method D1826-94 or ASTM Method D3588-98 for calorific
value.
6. All
alternative or equivalent test methods, waivers, monitoring methods, testing
and monitoring procedures, customized or correction factors, and alternatives
to any design, equipment, work practices, or operational standards must be
approved by both the administrative authority and the administrator, if
applicable, before they become effective.
7. An owner or operator may request approval
from the department for minor modifications to the test methods listed in
Paragraph G.5 of this Section, including alternative sampling locations and
testing a subset of similar affected sources, prior to actual stack
testing.
8. The information
required in this Subsection shall be provided in accordance with the effective
dates in Subsection J of this Section.
H. Continuous Demonstration of Compliance.
After the initial demonstration of compliance required by Subsection G of this
Section, continuous compliance with the emission factors of Subsection D or E
of this Section, as applicable, shall be demonstrated by the methods described
in this Subsection. For any alternative method, the department's approval does
not necessarily constitute compliance with all federal requirements nor
eliminate the need for approval by the administrator.
1. The owner or operator of boilers that are
subject to this Chapter shall demonstrate continuous compliance as follows:
a. for boilers with a maximum rated capacity
less than 250 MMBtu/hour:
i. install,
calibrate, maintain, and operate a totalizing fuel meter to continuously
measure fuel usage;
ii. install,
calibrate, maintain, and operate an oxygen monitor to measure oxygen
concentration; and
iii. in order to
continuously demonstrate compliance with the NOx limits
of Subsection D or E of this Section, implement procedures to operate the
boiler within the fuel and oxygen limits established during the initial
compliance run in accordance with Subsection G of this Section; and
b. for boilers with a maximum
rated capacity equal to or greater than 250 MMBtu/hour:
i. install, calibrate, maintain, and operate
a totalizing fuel meter to continuously measure gas and/or liquid fuel usage.
For coal-fired boilers, belt scales or an equivalent device shall be
provided;
ii. install, calibrate,
maintain, and operate a diluent (either oxygen or carbon dioxide) monitor. The
monitor shall meet all of the requirements of Performance Specification 3 of 40
CFR
60, Appendix B;
iii. install,
calibrate, maintain, and operate a NO
x CEMS to
demonstrate continuous compliance with the NO
x emission
factors of Subsection D or E of this Section, as applicable. The CEMS shall
meet all of the requirements of 40 CFR Part
60.13 and Performance Specification
2 of 40 CFR
60, Appendix B, or the requirements of 40 CFR Part
75 for units
regulated under the Acid Rain Program; and
iv. install, calibrate, maintain, and operate
a CO monitor. The monitor shall meet all of the requirements of Performance
Specification 4 of 40 CFR
60, Appendix B; or
v. alternatively to Clauses H.1.b.ii-iv of
this Section, for demonstration of continuous compliance, the owner or operator
may install, calibrate, certify, maintain, and operate a PEMS to predict
NOx, diluent (O2 or
CO2), and CO emissions for each affected point source.
As an alternative to using the PEMS to monitor diluent
(O2 or CO2), a monitor for
diluent according to Clause H.1.b.ii of this Section or similar alternative
method approved by the department may be used. The PEMS shall be certified
while operating on primary boiler fuel and, separately, on any alternative
fuel. The certification shall be in accordance with EPA documents, "Example
Specifications and Test Procedures for Predictive Emission Monitoring Systems"
and "Predictive Emission Monitoring System to Determine
NOx and CO Emissions from an Industrial Furnace" that
are located on the EPA website in the emission monitoring section, both with
posting dates of July 31, 1997; or
vi. alternatively to Clauses H.1.b.ii-iv of
this Section, the owner or operator may request approval from the administrator
for an alternative monitoring plan that uses a fuel-oxygen operating window to
demonstrate continuous compliance of NOx and CO. In
order to continuously demonstrate compliance with the
NOx limits of Subsection D or E of this Section, the
owner or operator shall implement procedures to operate the boiler on or inside
the fuel and oxygen lines that define the operating window. The corners of the
window shall be established during the initial compliance test required by
Subsection G of this Section or similar testing at another time. The details
for use of an alternative monitoring plan shall be submitted in the permit
application or in the optional compliance plan described in Paragraph F.7 of
this Section. The plan shall become part of the facility permit and shall be
federally enforceable.
2. The owner or operator of process
heater/furnaces that are subject to this Chapter shall demonstrate continuous
compliance as follows:
a. for process
heater/furnaces with a maximum rated capacity less than 250 MMBtu/hour:
i. install, calibrate, maintain, and operate
a totalizing fuel meter to continuously measure fuel usage;
ii. install, calibrate, maintain, and operate
an oxygen monitor to measure oxygen concentration; and
iii. in order to continuously demonstrate
compliance with the NOx limits of Subsection D or E of
this Section, implement procedures to operate the process heater/furnace within
the fuel and oxygen limits established during the initial compliance run in
accordance with Subsection G of this Section; and
b. for process heater/furnaces with a maximum
rated capacity equal to or greater than 250 MMBtu/hour:
i. install, calibrate, maintain, and operate
a totalizing fuel meter to continuously measure fuel usage;
ii. install, certify, maintain, and operate
an oxygen or carbon dioxide diluent monitor in accordance with the requirements
of Clause H.1.b.ii of this Section;
iii. install, certify, maintain, and operate
a NOx CEMS in accordance with the requirements of Clause
H.1.b.iii of this Section; and
iv.
install, certify, maintain, and operate a CO monitor in accordance with the
requirements of Clause H.1.b.iv of this Section; or
v. alternatively to Clauses H.2.b.ii-iv of
this Section, the owner or operator may install, calibrate, certify, maintain,
and operate a PEMS in accordance with the requirements of Clause H.1.b.v of
this Section; or
vi. alternatively
to Clauses H.2.b.ii-iv of this Section, the owner or operator may request
approval from the department for an alternative monitoring plan that uses a
fuel-oxygen operating window, or other system, to demonstrate continuous
compliance of NOx and CO. In order to continuously
demonstrate compliance with the NOx limits of Subsection
D or E of this Section, the owner or operator shall implement procedures to
operate the process heater/furnace on or inside the fuel and oxygen lines that
define the operating window. The corners of the window shall be established
during the initial compliance test required by Subsection G of this Section or
similar testing at another time. The details for use of an alternative
monitoring plan shall be submitted in the permit application or in the optional
compliance plan described in Paragraph F.7 of this Section. The plan shall
become part of the facility permit and shall be federally
enforceable.
3. The owner or operator of stationary gas
turbines that are subject to this Chapter shall demonstrate continuous
compliance as follows:
a. for stationary gas
turbines with a megawatt rating based on heat input less than 30 MW:
i. if the stationary gas turbine uses steam
or water injection to comply with the NOx emission
factors, install, calibrate, maintain, and operate a continuous system to
monitor and record the average hourly fuel and steam or water consumption and
the water or steam to fuel ratio. To demonstrate continuous compliance with the
appropriate emission factor, the stationary gas turbine shall be operated at
the required steam-to-fuel or water-to-fuel ratio as determined during the
initial compliance test; and
ii.
for other stationary gas turbines, install, calibrate, maintain, and operate a
totalizing fuel meter to continuously measure fuel usage. Compliance with the
emission factors of Subsection D or E of this Section shall be demonstrated by
operating the turbine within the fuel limits established during the initial
compliance run in accordance with Subsection G of this Section and by annual
testing for NOx and CO with an approved portable
analyzer; or
iii. alternatively to
Clause H.3.a.i or ii of this Section, an owner or operator may choose to comply
with the requirements of Clauses H.3.b.i-iv or v of this Section to demonstrate
continuous compliance with the limits of Subsection D or E of this Section;
and
b. for stationary
gas turbines with a megawatt rating based on heat input of 30 MW or greater:
i. install, calibrate, maintain, and operate
a totalizing fuel meter to continuously measure fuel usage;
ii. install, certify, maintain, and operate
an oxygen or carbon dioxide diluent monitor in accordance with the requirements
of Clause H.1.b.ii of this Section;
iii. install, certify, maintain, and operate
a NOx CEMS in accordance with the requirements of Clause
H.1.b.iii of this Section; and
iv.
install, certify, maintain, and operate a CO monitor in accordance with the
requirements of Clause H.1.b.iv of this Section; or
v. alternatively to Clauses H.3.b.ii-iv of
this Section, the owner or operator may install, calibrate, certify, maintain,
and operate a PEMS in accordance with the requirements of Clause H.1.b.v of
this Section; or
vi. alternatively
to Clauses H.3.b.ii-iv of this Section, the owner or operator may request
approval from the department for an alternative monitoring plan that complies
with the provisions of Clause H.3.a.i of this Section, if the turbine uses
steam or water injection for compliance, or Clause H.3.a.ii of this Section for
other turbines. The alternative plan shall also require annual testing for
NOx and CO with an approved portable analyzer and
triennial stack testing for NOx and CO in accordance
with the methods specified in Paragraph G.5 of this Section. The details for
use of an alternative monitoring plan shall be submitted in the permit
application or in the optional compliance plan described in Paragraph F.7 of
this Section. The plan shall become part of the facility permit and shall be
federally enforceable.
4. The owner or operator of stationary
internal combustion engines that are subject to this Chapter shall demonstrate
continuous compliance as follows:
a. install,
calibrate, maintain, and operate a totalizing fuel meter to continuously
measure fuel usage and demonstrate continuous compliance by operating the
engine within the fuel limits established during the initial compliance run and
by annual testing for NOx and CO with an approved
portable analyzer and by triennial stack testing for NOx
and CO in accordance with the methods specified in Paragraph G.5 of this
Section; or
b. alternatively to
Subparagraph H.4.a of this Section, an owner or operator may choose to comply
with the requirements of Clauses H.3.b.i-iv or v of this Section to demonstrate
continuous compliance with the limits of Subsection D or E of this
Section.
5. A CEMS unit
may be used to monitor multiple point sources provided that each source is
sampled at least once every 15 minutes and the arrangement is approved by the
department.
6. Existing
instrumentation for any requirement in this Subsection shall be acceptable upon
approval of the department.
7. For
any affected point source that uses a chemical reagent for reduction of
NOx, a NOx CEMS, in accordance
with Clause H.1.b.iii of this Section, and a CO monitor, in accordance with
Clause H.1.b.iv of this Section, shall be provided.
8. Boilers or process heater/furnaces covered
by this Chapter that discharge through a common stack shall meet the
appropriate continuous monitoring requirements of Paragraph H.1 or 2 of this
Section, or an alternative approved by the department.
9. The owner or operator of any affected
point source firing gaseous fuel for which a fuel multiplier from Paragraph D.7
of this Section is used shall sample, analyze, and record the fuel gas
composition on a daily basis or on an alternative schedule approved by the
administrative authority. If an owner or operator desires to use an alternative
sampling schedule, he shall specify a sampling frequency in his permit
application and provide an explanation for the alternative schedule. Fuel gas
analysis shall be performed according to the methods listed in Subparagraph
G.5.g of this Section, or other methods that are approved by the department. A
gaseous fuel stream containing 99 percent H
2 and/or CO
by volume or greater may use the following procedure to be exempted from the
sampling and analysis requirements of this Subsection:
a. a fuel gas analysis shall be performed
initially using the test methods in Subparagraph G.5.g of this Section to
demonstrate that the gaseous fuel stream is 99 percent
H2 and/or CO by volume or greater; and
b. the owner or operator shall certify that
the fuel composition will continuously remain at 99 percent
H2 and/or CO by volume or greater during its use as a
fuel to the point source.
10. All affected point sources that rely on
periodic stack testing to demonstrate continuous compliance and use a catalyst
to control NOx emissions shall be tested to show
compliance with the emission factors of Subsection D or E of this Section after
each occurrence of catalyst replacement. Portable analyzers shall be acceptable
for this check. Documentation shall be maintained on-site, if practical, of the
date, the person doing the test, and the test results. Documentation shall be
made available for inspection upon request.
11. The owner or operator of any low
ozone season capacity factor boiler or process heater/furnace, as
defined in Subsection B of this Section, for which an exemption is granted
shall install, calibrate, and maintain a totalizing fuel meter, with
instrumentation approved by the department, and keep a record of the fuel input
for each affected point source during each ozone season. If the average
Btu-per-ozone season-hour limit is exceeded, the owner or operator of any
boiler or process heater/furnace covered under this exemption shall include the
noncompliance in the written report that is due in accordance with Paragraph
I.2 of this Section. If the average Btu-per-ozone season-hour limit is
exceeded, the exemption shall be permanently withdrawn. Within 90 days after
receipt of notification from the administrative authority of the loss of the
exemption, the owner or operator shall submit a permit modification detailing
how the facility will meet the applicable emission factor as soon as possible,
but no later than 24 months, after exceeding the ozone season limit. Included
with this permit modification, the owner or operator shall submit a schedule of
increments of progress for the installation of the required control
equipment.This schedule shall be subject to the review and approval of the
department.
12. The owner or
operator of any affected point source that is granted an exemption in
accordance with Paragraph C.6 of this Section shall install, calibrate, and
maintain a nonresettable, elapsed run-time meter to record the operating time
in order to demonstrate compliance during the ozone season. If the average
operating hours-per-day limit is exceeded the owner or operator shall include
the noncompliance in the written report that is due in accordance with
Paragraph I.2 of this Section. If the average operating hours-per-day limit is
exceeded, the exemption shall be permanently withdrawn. Within 90 days after
receipt of notification from the administrative authority of the loss of the
exemption, the owner or operator shall submit a permit modification detailing
how the facility will meet the applicable emission factor as soon as possible,
but no later than 24 months, after exceeding the limit. Included with this
permit modification, the owner or operator shall submit a schedule of
increments of progress for the installation and operation of the required
control equipment. This schedule shall be subject to the review and approval of
the department.
13. Elapsed
run-time and fuel meters, oxygen, diluents, and CO monitors, and other such
instrumentation required by this Section shall be calibrated according to the
manufacturer's recommendations, but not less frequently than once per year.
Records shall be maintained according to Paragraph I.3 of this
Section.
14. Any unit with a permit
requirement or applicable regulation that requires more stringent testing than
this Chapter requires shall comply with the permit requirements or applicable
regulation rather than this Chapter.
15. Continuous demonstration of compliance
with fuel, oxygen concentration, and other parameter limits shall be on a
30-day rolling average basis.
I. Notification, Recordkeeping, and Reporting
Requirements
1. The owner or operator of an
affected point source shall notify the department at least 30 days prior to any
compliance testing conducted under Subsection G of this Section and any CEMS or
PEMS performance evaluation conducted under Subsection H of this Section in
order to give the department an opportunity to conduct a pretest meeting and
observe the emission testing. All necessary sampling ports and such other safe
and proper sampling and testing facilities as required by LAC 33:III.913, or
alternatives approved by the department, shall be provided for the testing. The
test report shall be submitted to the department within 60 days after
completing the testing.
2. The
owner or operator of an affected point source granted an exemption in
accordance with any part of Subsection C of this Section or required to
demonstrate continuous compliance in accordance with Subsection H of this
Section shall submit a written report within 90 days of the end of each ozone
season to the administrative authority of any noncompliance with the applicable
limitations of Subsection D or E of this Section or with the applicable work
practice standards of Paragraph K.3 of this Section. The required information
may be included in reports provided to the administrative authority to meet
other requirements, so long as the report meets the deadlines and content
requirements of this Paragraph. The report shall include the following
information:
a. a description of the
noncompliance;
b. a statement of
the cause of the noncompliance;
c.
the anticipated time that the noncompliance is expected to continue or, if it
has been corrected, the duration of the period of noncompliance; and
d. the steps taken to prevent recurrence of
the noncompliance.
3.
The owner or operator of an affected point source shall maintain records of all
continuous monitoring, performance test results, hours of operation, and fuel
usage rates for each affected point source. Such records shall be kept for a
period of at least five years and shall be made available upon request by
authorized representatives of the department. The emission monitoring (as
applicable) and fuel usage records for each affected point source shall be
recorded and maintained:
a. hourly for
affected point sources complying with an emission factor on an hourly
basis;
b. daily for affected point
sources complying with an emission factor enforced on a daily average basis or
on a 30-day rolling average basis; and
c. monthly for affected point sources exempt
from the emission specifications based on ozone season heat input or hours of
operation per ozone season.
4. The owner or operator shall maintain the
following records:
a. records for a
facility-wide averaging plan in accordance with Subparagraph E.1.i of this
Section;
b. records approved for a
trading plan in accordance with Paragraph E.2 of this Section; and
c. records in accordance with Paragraphs H.7,
8, 9, 10, 11, and 12 of this Section.
5. Ammonia emissions resulting from the
operation of a NOx control equipment system shall be
reported annually in accordance with LAC 33:III.5107.A.
J. Effective Dates
1. Except as provided in LAC 33:III.2202, the
owner or operator of an affected facility shall modify and/or install and bring
into normal operation NOx control equipment and/or
NOx monitoring systems in accordance with this Chapter
as expeditiously as possible, but by no later than May 1, 2005.
2. The owner or operator shall complete all
initial compliance testing, specified by Subsection G of this Section, for
equipment modified with NOx reduction controls or a
NOx monitoring system to meet the provisions of this
Chapter within 60 days of achieving normal production rate or after the end of
the shake down period, but in no event later than 180 days after initial
start-up. Required testing to demonstrate the performance of existing,
unmodified equipment shall be completed in a timely manner, but by no later
than November 1, 2005.
K.
Start-up and Shutdown
1. For affected point
sources that are shut down intentionally more than once per month, the owner or
operator shall include NOx emitted during periods of start-up and shutdown for
purposes of determining compliance with the emission factors set forth in
Subsection D of this Section, or with an alternative plan approved in
accordance with Paragraph E.1 or 2 of this Section.
2. For all other affected point sources,
effective May 1, 2017, the owner or operator shall either comply with Paragraph
K.1 of this Section or the work practice standards described in Paragraph K.3
of this Section during periods of start-up and shutdown. If the owner or
operator chooses to comply with work practices standards, the emission factors
set forth in Subsection D of this Section shall not apply during periods of
start-up and shutdown.
3. Work
Practice Standards
a. The owner or operator
shall operate and maintain each affected point source, including any associated
air pollution control equipment and monitoring equipment, in a manner
consistent with safety and good air pollution control practices for minimizing
emissions.
b. Coal-fired and fuel
oil-fired electric power generating system boilers and fuel oil-fired
stationary gas turbines shall use natural gas during start-up. Start-up ends
when any of the steam from the boiler or steam turbine is used to generate
electricity for sale over the grid, or for any other purpose (including on-site
use). If another fuel must be used to support the shutdown process, natural gas
shall be utilized.
c. Engage
control devices such as selective catalytic reduction (SCR) or selective
non-catalytic reduction (SNCR) as expeditiously as possible, considering safety
and manufacturer recommendations. The department shall incorporate into the
applicable permit for each affected facility appropriate requirements
describing the source-specific conditions or parameters identifying when
operation of the control device shall commence.
d. Minimize the start-up time of stationary
internal combustion engines to a period needed for the appropriate and safe
loading of the engine, not to exceed 30 minutes.
e. Maintain records of the calendar date,
time, and duration of each start-up and shutdown.
f. Maintain records of the type(s) and
amount(s) of fuels used during each start-up and shutdown.
g. The records required by Subparagraphs
K.3.e and f of this Section shall be kept for a period of at least five years
and shall be made available upon request by authorized representatives of the
department.
4. On or
before May 1, 2017, the owner or operator shall notify the Office of
Environmental Services whether each affected point source will comply with
Paragraph K.1 or K.3 of this Section during periods of start-up and shutdown.
a. The owner or operator does not have to
select the same option for every affected point source.
b. The department shall incorporate into the
applicable permit for each affected facility the provisions of Paragraph K.1
and/or K.3 of this Section, as appropriate. The owner or operator may elect to
revise the method of compliance with Subsection K of this Section for one or
more affected point sources by means of a permit modification.
