TECHNICAL SUPPORT DOCUMENT FOR
REVISION OF CERTAIN PROVISIONS:
PROPOSED RULE FOR
MANDATORY REPORTING OF GREENHOUSE
GASES
Office of Air and Radiation
U.S. Environmental Protection Agency
July 8, 2010
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TABLE OF CONTENTS
Subpart A 3
Background on Accuracy and Calibration Requirements 3
Calibration- Temperature and Pressure Transmitters for Orifice, Nozzle, and Venturi
Meters 10
Background Information on BAMM 12
Subpart C 14
Heterogeneity and Variability of Municipal Solid Waste in Relation to Municipal Waste
Combustor Emissions 14
Default Biomass Fraction for Municipal Solid Waste and Tires 26
Comparison of 250 Tons of MSW Per Day And 250 MMBtu/hr Heat Input Capacity... 27
Subpart C and D 31
Part 75 Units that Combust Biomass (Results of Database Query) 31
Subpart X and Y 34
Evaluation of Process Heaters Less than 30 MMBtu/hr Rated Heat Capacity 34
Subpart OO 55
Impact of Minor Constituents on the GW of the Mixture as a Function of Concentration
55
Subpart PP 56
CO2 Density Value 56
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Subpart A
Background on Accuracy and Calibration Requirements1
Background: The current rule provides, with limited exceptions, that "flow meters and other
devices (e.g., belt scales) that measure data used to calculate GHG emissions shall be calibrated
prior to April 1, 2010 using the procedures specified in this paragraph and each relevant subpart
of this part. All measurement devices must be calibrated according to the manufacturer's
recommended procedures, an appropriate industry consensus standard, or a method specified in a
relevant subpart of this part. All measurement devices shall be calibrated to an accuracy of 5
percent." Measurement devices that may be used to comply with the rule include:
• Fuel Mass Flow Meters;
• Fuel Volumetric Flow Meters;
• Weighing Systems;
• Tank Level Sensor;
• Acid Concentration Monitor; and
• Methane Analyzer.
EPA has received a number of comments on what the 5% accuracy requirement really means,
which measurement devices it should be applied to, and whether 5% is an appropriate value.
Based on these questions, we are reviewing the calibration and accuracy requirements in the rule.
This document provides some background materials gathered and evaluated in developing the
proposal.
Accuracy Requirements in Other Reporting Programs
1. Acid Rain Program and NOx Budget Program
• Requirements for Continuous Emissions Monitoring are described in 40 CFR Part
75. The performance specifications for fuel flow meters under Part 75, Appendix
D state:
— Conduct a flow meter accuracy test using American Society of
Mechanical Engineers (ASME) methods or using comparison to a
reference flow meter designed to American Gas Association (AGA)
standards.
— Error must be no more than 2.0 percent of full scale (initial calibration
and periodic QA).
— QA test required annually.
• Information from the Acid Rain Program accuracy tests between 2005 and 2009
show:
— Fuel flow meter accuracy ranged between 0.10 and 0.40 percent; and
— Transmitter transducer accuracy ranged between 0.20 and 0.50 percent.
1 Developed with support from Eastern Research Group.
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Tables A-l and A-2 in Appendix A summarize the Acid Rain Program accuracy
test results.
2. California Mandatory GHG Reporting Program
• Section 95103(a)(9) of Subarticle 1 General Requirements for the Mandatory
Reporting of Greenhouse Gas Emissions of the California GHG Reporting Rule
has an accuracy requirement for fuel use measurements that states:
"Fuel Use Measurement Accuracy. The operator shall employ procedures for fuel
use data measurements (mass or volume flow) used to calculate GHG emissions
that quantify fuel use with an accuracy within ±5 percent. All fuel use
measurement devices shall be maintained and calibrated in a manner and at a
frequency required to maintain this level of accuracy. The operator shall make
available to the verification team documentation to support this level of accuracy.
The operator who measures solid fuels shall validate fuel consumption estimates
with belt or conveyor scale calibrations conducted at least quarterly, and retain
record of such calibrations." (http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-
rep. htm)
• California originally proposed an accuracy requirement of ±2.5 percent. The Final
Statement of Reasons for Rulemaking responded to public comments regarding
the accuracy requirement. Commenters stated that the ±2.5 percent uncertainty
requirement is too stringent and is not achievable with most of the existing flow
measurement devices used in the petroleum industry.
• California also recognized there could be measurement difficulties for some
facilities and fuel types, including solid fuels. The response to comments
document concluded that, "Because it is impractical to write into the regulation
detailed specifications for evaluating the absolute accuracy of measurements for
each solid fuel, we chose to require in section 95103(a)(9) that facility operators
employ procedures to ensure a fuel activity accuracy of ±5 percent. Operators
must maintain and calibrate equipment to meet this level of accuracy, and
maintain appropriate records.
• California modified the original accuracy requirement of ±2.5 to ±5.0 percent for
the final rule.
• The California regulation and Final Statement of Reasons for Rulemaking did not
contain additional detail on the rational for the 5 percent accuracy requirement or
the change from the original 2.5 percent requirement.
What is the typical range of accuracy achievable for other measurement devices used in
Part 98 (e.g., belt scales, weigh hoppers, truck weigh scales)?
• Based on information from internet product searches and vendor information,
measurement devices typically have accuracy ranges less than ± 5 percent.
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• The Instrument Engineers Handbook lists load cell performance specifications for
individual load cells which have accuracy ranges between 0.03 and 1 percent.
Table A-3 in Appendix A lists typically accuracies for various types of load cells.
• Vendor information found through internet searches also showed accuracy ranges
of less than 5 percent. The accuracy ranges obtained from the vendor information
for devices that may be used in GHG reporting are listed below. Table A-4 in
Appendix A contains the detailed information by vendor.
— Mass flow meter - 0.2 percent to 1 percent;
— Volumetric flow meter - 0.125 to 1 percent;
— Load cell accuracy - 0.02 to 5 percent;
— Liquid level sensors - 0.075 to 2 percent;
— Concentration monitors - 0.1 to 2 percent; and
— Landfill gas monitors - 0.1 to 3 percent.
Uniform Accuracy Requirements Across Part 98 Versus Subpart-specific?
• The range of accuracy of new measurement technologies on the market today
does not suggest that different accuracy requirements are needed by type of
technology, if the required standard is near 5%. If differentiation is needed, it
may be driven by the cost of maintenance and replacement of older equipment
that cannot meet the 5% requirement. Therefore, if differentiation is necessary, it
may be needed by industry rather than technology, as explained below.
• The standards for accurately weighing raw materials and products are likely to
vary between industries, and between facilities within an industry, and even
among separate processes within a single facility.
• Different processes are likely to be more or less tolerant of different accuracies, so
a single standard for accuracy is probably not in practice among all industries.
• Different standards for accuracy also apply depending on whether the material is
being weighed and used within a plant for process control, or weighed as part of a
sale or purchase in commerce. Process control may not require the same level of
accuracy as in commerce.
• Additional information from specific industries could be needed to identify the
customary level of accuracy associated with those industries and variables that are
of most critical interest in the GHG emission calculations.
• In commerce, weighing devices are likely to conform to NIST Handbook 44, if a
device is used. Pennsylvania, for example, specifies that weighing devices used
in commerce must comply with NIST Handbook 44 (see, for example, Pa. Code
Title 70, Weights, Measures And Standards; Chapter 10. Device Type Approval;
http://www.pacode.com/secure/data/070/chapterlQ/chapl0toc.htmn.
Enforcement, inspection, and certification ("sealing") is done at the county level.
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Appendix A - Supporting Tables
TABLE A-l. SUMMARY OF FUEL FLOWMETER ACCURACY TEST BETWEEN 2005 & 2009
ACCURACY TEST METHOD CODE DESCRIPTION
TEST
METHOD
CODE
TOTAL
TEST
AVG LOW
LEVEL
ACCURACY
(PERCENT)
AVG MID
LEVEL
ACCURACY
(PERCENT)
AVG HIGH
LEVEL
ACCURACY
(PERCENT)
AGA Report No. 7, Measurement of Natural Gas by Turbine
Meter
AGA7
19
0.10
0.10
0.10
American Petroleum Institute Method in Appendix D
API
32
0.20
0.20
0.20
ASME Method in Appendix D
ASME
40
0.40
0.20
0.30
In-Line Comparison against Master Meter at Facility
ILMMF
251
0.10
0.20
0.30
International Organization for Standardization Method in
Appendix D
ISO
33
0.30
0.30
0.40
Laboratory Comparison against Reference Meter
LCRM
530
0.20
0.20
0.20
NIST-Traceable Method Approved by Petition
NIST
84
0.20
0.20
0.20
TABLE A-2. SUMMARY OF TRANSMITTER TRANSDUCER TEST BETWEEN 2005 & 2009
TEST TYPE
LOW LEVEL
ACCURACY
MID LEVEL
ACCURACY
HIGH LEVEL
ACCURACY
ACCURACY SPEC CODE
DESCRIPTION
ACCURACY
SPEC CODE
TOTAL
TEST
AVG
(PERCENT)
TOTAL
TEST
AVG
(PERCENT)
TOTAL
TEST
AVG
(PERCENT)
Actual Accuracy of Each Component
ACT
1,221
0.20
1,198
0.20
1,198
0.20
Sum of Accuracies of All Components
SUM
678
0.30
703
0.50
702
0.50
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Tabic A-3. Load Cell Performance Comparison
Type
Weight Range
Accu racy
(Full Scale)
Applications
Strengths
Weaknesses
Mechanical Load Cells
Hydraulic Load
Cells
Up to 10,000,000
lb
0.25%
Tanks, bins
and hoppers.
Hazardous
areas.
Takes high
impacts,
insensitive to
temperature.
Expensive,
complex.
Pneumatic Load
Cells
Wide
High
Food industry,
hazardous
areas
Intrinsically
safe.
Contains no
fluids.
Slow response.
Requires clean,
dry air
Strain Gage Load Cells
Bending Beam
Load Cells
10-5,000 lbs.
0.03%
Tanks,
platform
scales,
Low cost,
simple
construction
Strain gages are
exposed, require
protection
Shear Beam Load
Cells
10-5,000 lbs.
0.03%
Tanks,
platform
scales, off-
center loads
High side load
rejection, better
sealing and
protection
Canister Load
Cells
to 500,000 lbs.
0.05%
Truck, tank,
track, and
hopper scales
Handles load
movements
No horizontal
load protection
Ring and Pancake
Load Cells
5- 500,000 lbs.
Tanks, bins,
scales
All stainless
steel
No load
movement
allowed
Button and
washer Load
Cells
0-50,000 lbs
1%
Small scales
Small,
inexpensive
Loads must be
centered, no load
movement
permitted
0-200 lbs. typ.
Other Load Cells
Helical
0-40,000 lbs.
0.20%
Platform,
forklift, wheel
load,
automotive
seat weight
Handles off-axis
loads, overloads,
shocks
Fiber optic
0.10%
Electrical
transmission
cables, stud or
bolt mounts
Immune to
RFI/EMI and
high temps,
intrinsically safe
Piezo-resistive
0.03%
Extremely
sensitive, high
signal output
level
High cost,
nonlinear output
Source: Instalment Engineers Handbook, Process Measurement and Analysis, Fourth Edition, 2003
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Tabic A-4. Example Vendors for Measurement Devices and Device Accuracv
Vendor
Accu racv
Mass Flow Meters
Alicat Scientific
0.8% of reading + 0.2% of full scale for most models
Sierra Instruments
1% of full scale for most models
MKS Instruments
1% of full scale for most models
TSI
2% of reading a full scale for most models
Brooks Instrument
0.2%, 0.5% or 1% depending on model
Bronk Horst High Tech
0.2% of reading and 0.2% of full scale
Fluid Components International
0.5% for gases
Volumetric Flow Meters
Sure Flow Products
0.5% -1% of full scale
Instramart
0.8% of reading + 0.2% of full scale for Flocat LA10-A Gas flow meter
Liquid Controls
0.125 - 0.5% of reading - liquid volume meters
Liquid Level Sensors
SensorOne
0.25% of full scale for most products
SSI Technologies Inc
2% of full scale
Endress+Hauser
0.075% to 0.2%
Concentration Monitors (for liquid acids and bases)
Horiba
1% for most products
Jetalon Solutions, Inc
0.1% for the CR-288
Vnalytical Technology, Inc
2% of full scale for Q45/85 Peracetic acid monitor
Landfill (>as Monitors
(feotech GA2000 Portable Gas
Analyzer
Gas Accuracy depends on concentration level:
CH4: ±0.5-3.0
C02: ±0.5-3.0
02: ±1.0
Enviro-Equipment, Inc. CES-
LANDTEC GEM-2000
CH4: Range 0-100% Resolution 0.1%
C02: Range 0-60% Resolution 0.1%
02: Range 0-25% Resolution 0.1%
Flow Accuracy ±3% 50-150 SCFM
Load Cells
Vendor
Equipment Type
Accuracy (full scale)
Honeywell
Compression Canister Load
Cells
1%
S-Beam Load Cells
0.02%
Pancake Type Load Cells
0.1%
Ring Type Load Cells
1%
ADI Artech
S-Beam Load Cells
1%
Shear Beam Load Cells
1%
Bending Beam Load Cells
1%
Compression Canister Load
Cells
1%
Eilerson
Insdustrial
Sensors
Various Load Cell Types
0.25%
Control Systems
Weigh Hoppers
0.5%
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Tabic A-4. Example Vendors for Measurement Devices and Device Accuracy
Technology
Belt Feeder
0.1-5%
Siemens
Industry USA
Weigh Hoppers
0.25-0.5%
Belt Weighers
0.5-2%
Avery Weigh
Tronics
Truck and Railroad Scales
0.25-0.4% (static)
0.5% or +/- 400 lbs; whichever is higher (in motion)
Floor Scales
0.05%
Compression Load Cells
0.05%
Kistler-Morse
Compression Load Cells
0.08%
Rice Lake
Weighing
Systems
Belt Scales
0.25%
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Calibration- Temperature and Pressure Transmitters for Orifice, Nozzle, and Venturi Meters
Based on conversations with industry since release of the 2009 Final Rule, EPA learned of a
concern regarding temperature and pressure transmitters for orifice, nozzle and venturi meters.
Specifically, the petroleum refining and petrochemical industry informed us that some existing
meters in refinery fuel gas systems do not have temperature and total pressure sensors and
transmitters installed immediately adjacent to the meter. However, some of these installations
have one pressure and temperature measurement point that can provide compensation
information for the particular fuel line or system and meters installed on the line or system. The
industry expressed concern that new pressure and temperature monitors cannot be safely added
without a facility or unit shut-down unless the system can be securely isolated and bypassed to
enable continued unit operation. Moreover, they noted that even if a system can be isolated, the
work involved to plan, engineer, and execute the installation and tie in of these devices to the
process data systems will take considerable time and may not be feasible before the end of 2010.
The industry representatives suggested that conditions at a flow meter can be reliably and
accurately represented by temperature and pressure indications remote from the flow meter, and
therefore that the use of remote temperature and pressure indication should be allowed if a
reporter can demonstrate that these can be used to provide representative compensation for the
remotely located fuel meter. The industry representatives provided the approaches described in
the following paragraphs as examples of potential methods to demonstrate that a remote
measurement provides a representative indication:
A. Representative Conditions
In order to determine if the remote temperature and pressure values are representative of
conditions at the flow meter, temperature and pressure surveys could be conducted to determine
the difference between the readings at the transmitters not proximal to the meter and the actual
conditions at the meter. A typical temperature survey involves the use of an infrared gun, reading
local gauges, or an equivalent method and recording the temperature for each flow meter, near
each flow meter. If a temperature transmitter is not proximal to the meter, the difference between
the recorded value and the monitored temperature is recorded to give a temperature loss for the
line. This temperature loss, if significant, is then used to correct the monitored temperatures for
the particular flow meter. Pressure throughout a system is not expected to vary as widely and
could be determined through a pressure survey or calculated using standard fluid dynamics
equations, with the resulting calculated result used to compensate the measured flow at the fuel
metering device. A pressure survey generally involves using a calibrated pressure gauge to
measure the pressure in the pipe at, or as close as possible to, the meter. The measured pressure
would then be compared to the pressure monitoring from an existing transmitter on the
line/system and an appropriate "correction factor" calculated to correct the live pressure
transmitter readings to the corrected pressure at the meter.
B. Corrections
In the event a correction is needed to account for temperature and pressure changes, such
corrections could be done by applying a "correction factor" to the measured values based on
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comparisons in the data handling/calculation systems, such as through the temperature and
pressure surveys described above.
C. Active Compensation
Active compensation, in the context discussed, is the automated feed of the measured total
pressure and temperature information into the metering calculation system algorithms
periodically (e.g., every minute or every 10 minutes). In many current configurations, the total
pressure and temperature data used in these algorithms are constants set to provide a reasonable
match with the system in question. The sensors and transmitters furnishing the automated
pressure and temperature data may be located adjacent to the meter or on the same line/system
remote from the meter.
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Background Information on BAMM
Based on conversations with the petrochemical and petroleum refining industry since release of
the 2009 Final Rule, EPA learned of a concern regarding the ability to install measurement
devices in 2010 if installation would require a unit (or process line or facility) shutdown or a hot
tap. In the context of these discussions, industry representatives provided additional information
regarding (i) the circumstances that would justify use of Best Available Monitoring Methods
(BAMM) beyond 2010, and (ii) the proposed process for implementing BAMM beyond 2010.
The industry representatives surveyed members of their trade associations to obtain information
related to this issue. According to the industry representatives, twenty-three companies
responded from a broad cross-section of the industry ranging from companies that have a single
refinery to the large household names that have several refineries in the United States. These
respondents operate facilities ranging from refineries that make a single product with a limited
range of process units to plants which produce a much larger number of products and have a
substantial number of process units at the facility. According to the representatives, it is common
knowledge that refineries vary substantially in their capacity and production, thus there is no
such thing as the typical refinery.
According to the information provided by the industry representatives, the appropriate time to
install new monitoring equipment is during normally scheduled shutdowns or turnarounds
because:
• It avoids the inherent safety risks of hot tapping;
• It minimizes the costs to install monitoring equipment; and
• In the interim, prior to equipment installation, there are suitable methods to determine the
greenhouse gas emissions which are adequate for reporting purposes.
Industry noted that while there are some rare situations in which the bypass or isolation of the
equipment could enable a monitoring device to be installed while the process continues to
operate, it would be impossible to estimate for purposes of these revisions the number of such
specific situations at the present time because it would require an engineering review of pipe
configuration and other engineering considerations at each monitor site and would inevitably
require months to complete. Rather, it is an issue that is better suited to be addressed in the
context of an individual application to continue a limited use BAMM after 2010.
According to the industry representatives none of the companies reported that their turnaround
cycles for Crude Distillation Units, Vacuum Distillation Units, FCCUs, Distillate Hydrotreating
Units, Cat Feed Hydrotreaters, Hydrocrackers, Hydrogen Plants, Catalytic Reformers, Coking
Units, Sulfur Recovery Units, Boilers or Steam Generation Units, or Cogeneration Units were
one year or less. Seven companies did report that their turnarounds varied for Boilers or Steam
Generation Units, with at least some on a one year cycle; six companies noted similar
turnarounds for Catalytic Reformers.
When asked how long BAMM would be needed for each type of unit, industry provided the
typical range of turnaround cycles provided by the companies with regards to the units listed
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above. They also noted that there is no generally applicable cycle for the entire industry for any
of these units; in addition, the companies typically vary the cycle between refineries to avoid
having all of the manufacturing capacity shut down at the same time. Industry also emphasized
that there are exceptions to the ranges provided below both on the high side and on the low side
and thus the ranges provided are not all inclusive but a range that covers the larger part of the
industry. All the ranges are in years.
Crude Distillation Units: 4-7
Vacuum Distillation Units: 4-6
FCCU: 4-5
Distillate Hydrotreating Units: 3-5
Cat Feed Hydrotreaters: 3-5
Hydrocrackers: 3-5
Hydrogen Plants: 2-5
Coking Units: 3-5
Sulfur Recovery Units: 3-5
Cogeneration Units: 3-5
The industry representatives also provided information regarding what types of monitoring
devices are most at issue regarding installation in 2010, noting that their survey showed that fuel
gas meters and/or their associated sensors, transmitters, and piping are the most problematic
devices for the refining sector in this time frame. They stated that if all monitoring devices had
to be installed in 2010, facilities would likely be required to engage in a number of "hot taps"
(and assume their inherent risks and hazards to worker safety and facility operations) to install
specific instruments. The industry representatives considered "hot-tapping" to be the installation
of devices which penetrate the pipe or vessel wall while in service, which involves welding a
special fitting on the pipe or vessel exterior, installing a full-bore opening valve on this fitting,
using specialty tools to drill a hole through the wall, and then installing the device through the
penetration created. According to industry, the risks with hot-tapping are:
• Uncontrolled release of flammable and/or explosive gases and the risk of ignition and
fire or flash fire; and
• Burn-through and ignition while welding the fitting on the pipe/vessel.
The industry representative also noted that hot-tapping is regulated under OSHA regulations at
29 C.F.R. 1910.147(a)(2)(iii)(B), and that OSHA-mandated criteria regulating this activity
discourage hot tapping in order to limit the risk of employee injury.
Regarding the frequency by which processes or units are shut down, industry representatives
indicated that, ideally, process unit shutdowns and turnarounds are the same, and if unscheduled
shut downs do occur, they tend to be short and the units are restarted as quickly as safe
operations allow. According to industry representatives, it is generally not feasible to install new
equipment during unscheduled unit outages.
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Subpart C
Heterogeneity and Variability of Municipal Solid Waste in Relation to Municipal Waste
Combustor Emissions2
Background and Summary
MSW is a fuel for MWCs, which are a category of stationary combustion sources covered under
Subpart C of EPA's Mandatory Greenhouse Gas Reporting rule (2009). Subpart C requires
stationary combustion sources to report their carbon dioxide emissions and establishes four tiers
of methods for stationary combustion sources to calculate or physically measure their carbon
dioxide emissions. These include:
• Tier 2: Mass Balance Calculations. This method estimates the annual mass of CO2
emissions for MWCs by multiplying the mass of steam generated by MSW combustion,
by the efficiency of steam generation and by a default CO2 emission factor for MSW.
• Tier 4: Continuous Emissions Monitoring. This method requires hourly measurements of
CO2 concentration and stack gas volumetric flow rate to calculate the mass of CO2
emissions.
Carbon dioxide (CO2) emissions from MWCs are a function of the composition of MSW that
they burn for fuel. As a result, the choice of monitoring techniques will depend upon the extent
to which the composition of MSW used as a fuel for combustion in MWCs varies.
Under Subpart C, MWCs with a maximum rated heat capacity greater than 250 tons per day are
required to apply the Tier 4 method and use continuous emissions monitoring systems to directly
measure their carbon dioxide emissions on a continuous basis if the unit meets the six
requirements in 98.33(b)(4)(ii). Units equal to or less than 250 tons per day are required to use
Tier 4 if they meet the three conditions outlined in 98.33 (b)(4)(iii). Stakeholders have expressed
concern, contesting the requirement for the Tier 4 monitoring method. The stakeholder
advocates the use of the Tier 2 mass balance estimate method instead, asserting that application
of the Tier 4 method is 'costly' and that there is 'no logical basis' for this requirement in the
stated purpose of the Mandatory Greenhouse Gas Reporting Rule.
The purpose of this document is to provide background on the factors influencing MSW
composition variability, how these factors contribute to variability in CO2 emissions through the
carbon content and ratio of fossil carbon to biogenic carbon3 in MSW, and the range of possible
variation of composition.
2 Developed with support from Christopher Evans, Robert Lanza, Randy Freed, and Veronica Kennedy, ICF
International
3 Carbon-based components of MSW are distinguished into fossil and biogenic fractions because these fractions are
accounted for differently under IPCC guidelines for developing national greenhouse gas inventories (IPCC 2006)
and are required to be reported separately under Subpart C of the MRR. The biogenic fraction of MSW includes
biomass-derived materials containing carbon that, under natural conditions, would cycle back to the atmosphere as
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Both the overall carbon content and the ratio of fossil carbon to biogenic carbon of MSW varies
according to the composition of biogenic and non-biogenic carbon-based materials in the MSW.
The principal components and average national composition of MSW in 2008 are shown in
Table 1, as estimated by EPA (2009) in Municipal Solid Waste Generation, Recycling, and
Disposal in the United States Detailed Tables and Figures for 2008.
Table 1: Principal components of MSW and amount of each component generated in the United States in
2008 (EPA 2009)
Material
Generation
1 Share of total
short tons
Paper
77,420
31%
Glass
12,150
5%
Metals
20,850
8%
Plastics
30,050
12%
Rubber and leather
7,410
3%
Textiles
12,370
5% ;
Wood
16,390
7%
Food scraps
31,790
13%
Yard trimmings
32,900
13%
Miscellaneous inorganic wastes
3,780
2%
Other
4,500
2%
Total
249,610
100%
Non-biogenic carbon-based materials primarily consist of plastics, synthetic textiles, and rubber;
biogenic materials include paper, natural textiles (e.g., cotton, linen), wood, food waste, and yard
trimmings (EIA 2007). Glass and metals are inorganic materials.
There are four types of compositional variability in the MSW stream: variability in the definition
of MSW, geographic variability, seasonal variability, and long-term compositional trends. Each
of these factors is discussed below. Each factor can result in considerable site-specific variation
in the C02 emissions from MWCs and the ratio of fossil to biogenic C02 in MSW burned in
MWCs. Consequently, CO2 emissions from MWCs are much harder to characterize accurately
using mass balance or other calculation methods than are C02 emissions from other stationary
combustion sources covered under Subpart C of EPA's Mandatory Greenhouse Gas Reporting
rule (2009). Other types of stationary combustion sources such as fossil fuel-fired combustors
generally have a relatively homogeneous fuel source with relatively well-characterized fossil C
content.
Description of four types of variability in the MSW stream
Variability in the definition of MSW
C02 due to degradation processes. As a result, C02 emissions from biogenic materials from sustainably-grown
biomass are not included in inventories of human-caused greenhouse gas emissions. The fossil fraction of MSW
includes materials that are derived from fossil fuels that have been sequestered under the earth. When fossil-based
materials are extracted from the earth and converted into C02 or other greenhouse gases, they are considered
anthropogenic emissions and are included in inventories. For more information, please refer to IPCC (2006) and
EPA (2006, p. 13).
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Municipal solid waste or MSW can be defined as solid phase household, commercial/retail,
and/or institutional waste. Household waste includes material discarded by single and multiple
residential dwellings, hotels, motels, and other similar permanent or temporary housing
establishments or facilities. Commercial/retail waste includes material discarded by stores,
offices, restaurants, warehouses, non-manufacturing activities at industrial facilities, and other
similar establishments or facilities. Institutional waste includes material discarded by schools,
nonmedical waste discarded by hospitals, material discarded by non-manufacturing activities at
prisons and government facilities, and material discarded by other similar establishments or
facilities. Household, commercial/retail, and institutional waste does not include used oil, wood
pellets, construction, renovation, and demolition wastes (which includes, but is not limited to,
railroad ties and telephone poles), clean wood, industrial process or manufacturing wastes,
medical waste, or motor vehicles (including motor vehicle parts or vehicle fluff). Household,
commercial/retail, and institutional wastes include yard waste, refuse-derived fuel, and motor
vehicle maintenance materials, limited to vehicle batteries and tires, except where a single waste
stream consisting of tires is combusted in a unit.
Biocycle magazine's State of Garbage in America series has reported frequently4 on the
challenges of characterizing the generation and composition of MSW. Inconsistencies in state-
level data led Biocycle to revise its methodology for estimating the generation and composition
of MSW (Biocycle 2004), but problems persist in compiling an accurate estimate of MSW
generation and composition in the United States through a state-by-state bottom-up estimate
(Biocycle 2006, p. 28):
• Wastes that are typically not considered part of the MSW stream, such as construction
and demolition materials, automobile scrap, industrial wastes, biosolids, and agricultural
wastes, may be classified as MSW in state estimates.
• Each state has its own method for collecting state-wide MSW management information;
there is a high degree of certainty in the overall tonnages of MSW that are landfilled and
that are combusted due to reporting requirements, but recycling and yard trimming
composting facilities are often not required to report throughput; and
• Exported MSW is not tracked by all states, and some states are not able to distinguish
non-MSW waste exports from MSW exports.
Challenges in accurately and consistently defining the wastes that constitute MSW can lead to
mischaracterization of MSW as a fuel for combustion in MWCs. Non-MSW wastes may have
substantially different carbon contents and fractions of fossil and biogenic components; for
example, wood can form a large share of construction and demolition debris. Consequently, CO2
emissions from wastes considered MSW that are combusted in MWCs, but which fall outside of
EPA's definition of MSW, can lead to different CO2 emissions than might be predicted using
default emission factors.
4 Usually Biocycle runs their "State of Garbage in America" article annually, but there have been occasional gaps.
16
-------
Geographic variability
The composition of MSW varies geographically across the United States. Geographic variability
is driven by factors such as the following (EPA 2008, p. 21):
• "Variance in the per capita generation of some products, such as newspapers and
telephone directories, depending upon the average size of the publications. Typically,
rural areas will generate less of these products on a per person basis than urban areas.
• "Level of commercial activity in a community. This will influence the generation rate of
some products, such as office paper, corrugated boxes, wood pallets, and food scraps
from restaurants.
• "Variations in economic activity, which affect waste generation in both the residential
and the commercial sectors.
• "Local and state regulations and practices. Deposit laws, bans on landfilling of specific
products, and variable rate pricing for waste collection are examples of practices that can
influence a local waste stream."
MSW combustion occurs predominantly in the northeast and southern regions of United States,
shown in Table 2. According to Figure 1, Connecticut combusts 65% of its MSW, and Florida,
Hawaii, Maine, and Massachusetts manage over 20% of their MSW in waste-to-energy projects5.
Twenty states do not have any MWCs within their borders.
Table 2: Municipal waste-to-energy projects by U.S. region (EPA 2008, p. 151)
Design
Number
Capacity
Region
Operational
(tpd)
NORTHEAST
40
46,537
SOUTH
23
J A
31,131
in oi">
IVIIL/»> fjO 1
WEST
to
8
i u»v I j.
6,141
U.S. Total*
87
94721
5 MWCs account for roughly 90% of MSW processed in waste-to-energy projects (EPA 2008, p.
151). The remaining 10% is largely made up of tires, which are sent separately to cement kilns,
utility boilers, pulp and paper mills, industrial boilers, and dedicated tire-derived fuel facilities
for combustion. (EPA 2008, p. 151)
17
-------
100%
BB Landfilled
E3 Recycled
¦ Waste-to-energy
Figure 1: Share of waste management methods employed by U.S. states, as a percentage of total tonnage of
MSW generation (Adapted from Arsova et al., 2008)
As shown in Figure 2, bans on scrap tires, used oil, and lead-acid batteries are common, but bans
on other types of goods such as yard trimmings, white goods, and electronics are more variable.
State-level regulations banning disposal of materials in MSW landfills can influence the
composition of waste that is sent to MWCs. Often the regulations govern waste haulers. The
boundaries of "wastesheds" can shift day by day as a function of relative tipping fees for
landfilling versus combustion. Thus, as the haulers (and/or the municipalities they serve) try to
divert materials from landfills, they also divert them from combustors.
18
-------
Yard
Httofe
Used
LknMc&
Wntw
Slate
Tnmvnos
Tires
&i
Mtm&s
Goods
Efectrontcs Others
Alaska.
X
X
Arisni
X
X
Arkansas
3C
X
X
xi
California
X
X
X
X X3
Connecticut
X
Delaware
X
Florida
X
X
X
X
Georgia
X?
X
X
X
Idaho
X
X
Illinois
X
X
X
K
X
x«
Indiana
X7
X
X
low
1
X
X
I
X
Kansas
X
Kentucky
X
X
Louisiana
X
X
X
X
Maine
X
X
X
X X?
Maryland
X*
X
X
X
Massachusetts
X
X
I
X
X X10
Michigan
X
X
X
I
X11
Minnesota
X
%
X
X.
X.
X
Mississippi
X
X
Missouri
X
X
X
X
X
Nebraska
X12
x:
X
X
X
New Hampshire
X
X
X.
X
New Jersey
x«
x«
New Mexico
X
X
New York
X
X
X
North Carolina
X
X
3C
X
X
X15
North Dakota
X
X
.It
Ohio
X*
X
Oregon
X
X
X
X
Pennsylvania
X16
X
X
Rhode Island17
X
X
X
X
X
X1*
S. Carolina
X
K
X
X
X
S. Dakota
X
X
X
1
X
Tennessee
X
X.
X
Tern
X
X
X
x«
Utah
X
X
X
Vermont
X
,1
X
X
X20
Virginia
X
X
West Virginia21
X22
X
K
X
Wisconsin
X
X
X
X
X
xa x«
Wyoming
X
'ntgamm taming mmH »# eonpettr .a# HMnHwt • sn«» etgan Amy 120m *moimemt Mtor %i»
«v»p.'*rm mkH s» -if cBarry mhw lmmf sp« Jft «iafF iwt nw MnMvt m tmmie nrnmm imam amgntm
Mi t> soBtte 0 mmum pammf m&bM or mmg #t» ymi ttmarngsM rnmmnt twtma cm iutm «
MMMfflMKtfMMr ?i*w*«®e, m>a#vtg$btotmittrtn**'to*> 3 mm moeymgs&ttm
mMrMCf fcin3n'«j*i|S fMtevgMLMMM wrtMfHw cortmwfc Kway fl^fl*ygro«Ktsr»sip«r<»»
«i»cf8fffafl ass# is aiistfr»»«, nuts# f«5
-------
quantity of materials recovered for recycling as a percentage of total waste generated, not
including any losses or contamination of recyclables), of municipal recycling systems is variable
on a municipal/county level as well as by state, as shown by Figure 3. The rates depend upon a
number of technical and non-technical factors, including the type of recycling system (e.g.,
single-stream versus dual-stream curbside collection), the age of the program (i.e., how long it
has been established), the level of public outreach, municipal policies such as variable-rate waste
collection (also known as Pay As You Throw, or PAYT), frequency of collection, and
demographics (e.g., recovery rates are correlated with median household income). Other
practices, such as the level of backyard composting in a region, can also affect the recovery rate
of materials in certain communities (EPA 2008, p. 21). Recovery of paper, yard trimmings, and
other materials will influence the carbon content and ratio of fossil-to-biogenic components of
MSW sent to MWCs for combustion, and, consequently, the resulting C02 emissions.
Figure 4 provides data on of the range of geographic variability in the MSW stream by
summarizing state-level MSW-sort data (i.e., the composition of MSW after recovery from
recycling programs). The figure illustrates that paper and organics (i.e., food waste and yard
trimmings) components in particular exhibit a high level of variability, fluctuating by nearly 20
percent (as a fraction of total MSW wet weight) across different states. Plastics have been
observed to constitute from 6 (in Kansas) to 18 percent (in Iowa) of the MSW stream. The data
reveal that there is significant geographic variability in the composition of MSW, particularly the
fractions that contribute to fossil and biogenic CO2 emissions.
Seasonal variability
The composition of MSW varies seasonally, according to variations in climate as well as
economic and demographic waste generation factors each year (EPA 2008, p. 21). Examples of
factors that contribute to seasonal variability in the composition of MSW—yard trimmings in
particular—include the following trends:
• Increased generation of grass clippings in spring, summer, and fall months (and in most
climates, no generation in the winter),
• The occurrence of autumn leaves (September/October/November) in areas with
deciduous forests and urban trees, and
• Generation of Christmas tree and wrapping paper waste in December/January.
Local and/or state policies may also have an impact on the level of seasonal variation in MSW
composition. Since many states ban yard trimmings, autumn leaves, and Christmas trees from the
MSW stream (see Figure 2), the level of seasonal variation in the generation of yard trimmings
will be less in these jurisdictions.
MWCs have limited ability to even out the seasonal variation since it is generally not feasible to
store MSW for more than a few days prior to combustion (due to odor and hygiene concerns).
Consequently, the underlying seasonal variation in MSW that fuels MWCs will translate to
seasonal variation in CO2 emissions as well.
20
-------
1
0% 10%
J3L
JUL
jnnL
30% 40% 50% 60% 70% 80% 90% 100%
Recycling rate
(a) New Mexico
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Recycling rate
(b) Massachusetts
t
JUL
0% 10%
30% 40% 50% 60% 70% 80% 90% 100%
Recycling rate
(c) New Hampshire
Figure 3: Distribution of recovery rates across counties and municipalities using different recycling programs
in (a) New Mexico, (b) Massachusetts, and (c) New Hampshire. Note: The vertical axes differ in scale.
21
-------
100%
90%
80%
70%
60%
| 50%
_ £ 40%
30%
20%
10%
0%
IIITTTF
1
SI
Hi
I
1
I
-------
The estimates developed by EIA highlight the effect that long-term compositional trends can
have on C02 emissions from MSW combustion. Changes in the heat content and ratio of fossil to
biogenic components of MSW will influence both the carbon content of MSW combusted as fuel
as well as the fossil-to-biogenic ratio of CO2 emissions.
Table 3: MSW heat eontcnt and biogenie/fossil shares from 1989 to 2005 (EIA 2007, p. 6)
Year
Heal Content
(Million Bru/Tosi}
_§:< V>'/. : ¦ ¦¦ I¥_
WW
10.08
0.67
1133
1990
10.21
0.66
0.34
1991
1:0,40
0.65
0.35
1992
10.61
0,64
0.36
1993
10.94
0.64
0J6
1994
11.15
0.63
0.37
1995
11.11
0.62
6JS
1996
10.94
0.61
0,39
1997
11.17
0-60
0.40
1998
11.06
0.60
0.40
1999
10.95
0.60
0.40
2000
11.33
0.S8
0.42
2001
1121
0.57
0,43
2002
11.19
0.56
0.44
2003
11.17
0.55
0.45
2004
11.45
0.55
0.45
2005
11.73
0,56
0,44
ket-ti linearly ituerpolalcd m the itiilifiais pomp ievtl between iiiiii«li«!d)*
airttilnitSof IwitW ywnv
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Protection Agency, Municipal Solid Warn »t the United Sain: 3S85 Fam
fiwrf fiiMni,, Table *1. J
Biogenic and BC)it.biijfii»ic porce
23
-------
1—•-
1—•-
1—¦¦
1
I—•-
i—¦¦
1—•-
1—¦¦
1
1—¦-
i—¦¦
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to
to
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Figure 5: Trends in fossil and biogenic fractions of MSW on a heat-content basis (EIA 2007)
In sum, the composition of MSW is very heterogeneous - containing thousands of individual
materials and over a dozen different categories of materials - and extremely variable on a
geographic and temporal basis. This underlying variability in the composition of the fuel of
MWCs implies that accurate monitoring requires frequent sampling, and an approach to either
characterize the fossil and biogenic components of the fuel or, more directly, of the emissions
themselves.
References
Arsova, L., Haaren, R. V., Goldstein, N., Kaufman, S. M., & Themelis, N. J. (2008). The State
Of Garbage in America. Biocycle. Retrieved from
http://www.igpress.com/archives/ free/001782.html
EPA. (2006). Solid Waste Management and Greenhouse Gases: A Life-Cycle Assessment of
Emissions and Sinks. U.S. Environmental Protection Agency (EPA). Retrieved from
http://epa.gov/climatechange/wvcd/waste/reports.html
EPA. (2008). Municipal Solid Waste in the United States: 2007 Facts and Figures. U.S.
Environmental Protection Agency (EPA). Retrieved from
http://www.epa.gov/osw/nonhaz/municipal/msw99.htm
24
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EPA. (2009). Municipal Solid Waste in the United States: 2008 Facts and Figures, Data Tables.
U.S. Environmental Protection Agency (EPA). Retrieved from
http://www.epa.gov/epawaste/nonhaz/municipal/pubs/msw2008data.pdf
EIA. (2007). Methodology for Allocating MSW to Renewable/Non-Renewable Energy. Energy
Information Administration (EIA). Retrieved from
http://www.eia.doe.gov/cneaf/solar.renewables/page/mswaste/msw report.html
Friedland, D. (2009). Petition for Reconsideration. Beveridge and Diamond. Petition for
reconsideration of Mandatory Reporting of Greenhouse Gases, Final Rule.
IPCC. (2006). 2006 IPCC Guidelines for National Greenhouse Gas Inventories. Volume 3:
Industrial Process and Product Use, Chapter 3: Chemical Industry Emissions. Retrieved
from http://www.ipcc-nggip.iges.or.ip/public/2006gl/vol3.html
Mandatory Greenhouse Gas Reporting, 74 Fed. Reg. 56374 (2009).
Staley, B. F., & Barlaz, M. A. (2009). Composition of Municipal Solid Waste in the United
States and Implications for Carbon Sequestration and Methane Yield. Journal of
Environmental Engineering, 735(10), 901-909. doi: 10.1061/(ASCE)EE.1943-
7870.0000032
25
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Default Biomass Fraction for Municipal Solid Waste and Tires
EPA has amended 40 CFR 98.33(e)(3) to add an alternative calculation methodology for
biogenic C02 emissions from the combustion of tires and/or MSW that may be used when the
total contribution of these fuels to the unit's heat input is 10 percent or less. The methodology
may also be used for small, batch incinerators that burn no more than 1,000 tons of MSW per
year. Units that qualify for and elect to use the methodology use Tier 1 to calculate the total
annual C02 emissions from the combustion of the MSW or tires, and multiply the result by an
appropriate default factor that represents the biomass fraction of the fuel, to obtain an estimate of
the annual biogenic C02 emissions. This memo provides the underlying data used to generate
the default factors of 0.20 for tires and 0.60 for MSW that is found in the rule.
MSW
See Table 3 in the previous section: "Heterogeneity and Variability of Municipal Solid Waste in
Relation to Municipal Waste Combustor Emissions The default factor of 0.60 is the average
biogenic fraction of MSW during the time series from 1989 through 2005.
2. Tires
The default value for tires was based on data available from the Rubber Manufacturers
Association (RMA). According to RMA the typical composition of tires is different depending
on if it is a passenger tire or a truck tire. The characteristics are presented below. The default
factor of 0.20 is the average biogenic fraction of passenger and truck tires.
Passenger Tire Truck Tire
Natural rubber
14 %
Matural rubber
27%
Synthetic rubber
27%
Synthetic rubber
14%
Carbon black
28%
Darbon black
28%
Steel
14-15%
Steel
14-15%
Fabric, fillers,
16-17%
rabric, fillers,
16-17%
accelerators, antiozonants,
accelerators,
etc.
antiozonants, etc.
Average weight:
New 25 lbs,
Scrap 22.5 lbs.
-------
Comparison of250 Tons of MSWPer Day And 250 MMBtu/hr Heat Input Capacity
Background and Summary6
MSW is a fuel for MWCs, which are a category of stationary combustion sources covered under
Subpart C of EPA's Mandatory Greenhouse Gas Reporting Rule. Subpart C requires stationary
combustion sources to report their carbon dioxide emissions and establishes four tiers of methods
for stationary combustion sources to calculate or physically measure their carbon dioxide
emissions.
According to sections 40 CFR § 98.33(b)(4)(ii)(A), stationary combustion units with a
"maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts
municipal solid waste [...] a maximum rated input capacity greater than 250 [short] tons per day
of MSW" that meet the other five conditions in paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(F)
must use the Tier 4 Calculation Methodology to calculate their carbon dioxide emissions. Some
owners and operators of MWCs contended that the threshold of 250 short tons per day of MSW
is more stringent than the 250 mmBtu/hr heat input threshold for other stationary combustion
units, and therefore places a disproportionate burden on MWCs.
This memorandum evaluates approximate equivalencies between the 250 short tons of MSW per
day threshold for units combusting MSW and the 250 mmBtu/hour heat input capacity threshold
for other stationary combustion units. The calculation and relevant data are provided below.
Calculation and Data Sources
The formula for converting the maximum rated heat input capacity of a MWC unit in short tons
per day into an equivalent maximum rated heat input capacity can be expressed as follows:
MSW input rate [short tons/day] * MSW heating value [mmBtu/short ton] '¦ N [hours/day]=
Heat input rate [mmBtu/hour]
Where,
MSW input rate = the maximum rated input capacity of the unit, in short tons per day
MSW heating value = the heat rate of MSW, in mmBtu per short ton
N = the time period over which MWC operation is evaluated in a day to determine
maximum rated input capacity, in hours per day
Heat input rate = the maximum rated heat input capacity of the unit, in mmBtu per hour
To evaluate the equivalent heat input capacity at rates of 250 short tons/day and 250 short
tons/day, two parameters are required: (i) the heating value of MSW combusted in MWCs, and
(ii) the number of hours per day over which MWC operation is evaluated to determine maximum
rated input capacity.
Heating value of MSW Combusted in MWCs
6 Developed with support from Christopher Evans and Randy Freed, ICF International.
27
-------
Estimates of the heating value of MSW are given in Table 4. Due to the considerable
heterogeneity of MSW, heating value estimates range from 4,500 to 5,865 Btu/pound, or 9.0 to
11.7 mmBtu/short ton. This range reflects the variability in MSW composition resulting from
geographic variability, seasonal patterns in MSW disposal, and long-term trends in MSW
generation.
Table 4: Heating value for estimates for MSW
Heating value of MSW
Notes
Source
Btu/pound
mmBtu/short ton
4,500
9.00
MSW that is not refuse-derived fuel
EPA (1996), p. 2.1-
29
5,500
11.00
MSW refuse-derived fuel
EPA (1996), p. 2.1-
29
5,040
10.08
Heating value of MSW in 1989;
based on estimates of material-
specific heating values and U.S.
MSW composition taken from EPA
(2006) Facts and Figures: 2005.
EIA (2007), Table 1,
p. 6
5,865
11.73
Heating value of MSW in 2005;
based on estimates of material-
specific heating values and U.S.
MSW composition taken from EPA
(2006) Facts and Figures: 2005.
EIA (2007), Table 1,
p. 6
Number of Hours Per Day Over Which MWC Operation is Evaluated to Determine
Maximum Rated Input Capacity
Second, according to 40 CFR § 60.58b(j), the maximum rated input capacity of MWCs is
evaluated over a 24-hour period (i.e., N = 24), regardless of whether the MWC operates
continuously or as a batch-feed operation. The procedures for calculating MWC unit capacity are
defined as follows:
• For MWC units that are capable of combusting MSW continuously for a 24-hour period,
"the unit capacity shall be calculated based on 24 hours of operation at the maximum
charging rate", where the maximum charging rate is either:
o The maximum design heat input capacity of the unit multiplied by a heating value
for the MSW fuel combusted, for combustors designed based on heat capacity, or
o The maximum design charging rate, for combustors not designed based on heat
capacity.
• For batch-feed MWC units, unit capacity is calculated "as the maximum design amount
of municipal solid waste that can be charged per batch multiplied by the maximum
number of batches that could be processed in a 24-hour period."
40 CFR § 60.58b(j) also specifies that the MSW heating values to convert the design heat input
capacity of a MWC into the unit's input capacity shall be "12,800 kilojoules per kilogram for
combustors firing refuse-derived fuel and [...] 10,500 kilojoules per kilogram for combustors
28
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firing municipal solid waste that is not refuse-derived fuel". These values correspond to MSW
heat rates of 9.0 and 11.0 mmBtu/short ton respectively, consistent with the EPA (1996) values
from AP-42, identified in Table 4.
Results
Table 5 provides the equivalent maximum rated heat input capacities for two different MWC unit
rated input capacities using the equation and parameters provided above. Due to the variability in
MSW heating values, we selected three MSW heat input values: a low value of 9 mmBtu/short
ton; a medium value of 10 mmBtu/short ton, and a high value of 12 mmBtu/short ton. This range
is representative of the values provided by Table 4 above, and in 40 CFR § 60.58b(j).
Table 5: Equivalent maximum rated heat input capacity at various MSW heat input rates for two different
MWC rated input ca
pacities
Max. rated input
capacity (short
tons/day)
Equivalent maximum rated heat input capacity (mmBtu/hour)
Low MSW heat input
(9 mmBtu/short ton)
Medium MSW heat input
(10 mmBtu/short ton)
High MSW heat input
(12 mmBtu/short ton)
250
94
122
600
225
250
300
Notes: Calculated over a 24-hour operating period (i.e., N = 24 hours/day)
Gray = below 250 mmBtu/hr threshold for other stationary combustion units
Black = equal to 250 mmBtu/hr threshold for other stationary combustion units
Bold = above 250 mmBtu/hr threshold for other stationary combustion units
The 250 short tons/day input capacity threshold is more stringent than the 250 mmBtu/short ton
heat input capacity threshold, regardless of the MSW heating value. Using the medium MSW
heat input value of 10 mmBtu/short ton, a threshold of 600 short tons of MSW per day is
equivalent to the 250 mmBtu/hour threshold that applies to other stationary sources. MWCs that
combust MSW with heating values higher than 10 mmBtu/short ton will have a higher equivalent
maximum rated heat input capacity; MWCs that combust MSW with heating values lower than
10 mmBtu/short ton will have a lower equivalent maximum rated heat input capacity.
Conclusion
Acknowledging the variability in MSW composition and heat content, a threshold of 600 short
tons of MSW per day is consistent with the 250 mmBtu/hour threshold that applies to other
stationary combustion units for Tier 4 reporting in 40 CFR § 98.33(b)(4)(ii).
References
EIA. (2007). Methodology for Allocating MSW to Renewable/Non-Renewable Energy. Energy
Information Administration (EIA). Retrieved from
http://www.eia.doe.gov/cneaf/solar.renewables/page/mswaste/msw report.html accessed
June 21, 2010.
29
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EPA (1996) AP 42, Fifth Edition, Volume I Chapter 2: Solid Waste Disposal, Section 2.1:
Refuse Combustion, p. 2.1-29. Retrieved from
http://www.epa.gov/ttn/chief/ap42/ch02/index.html accessed June 21, 2010.
30
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Subpart C and D
Part 75 Units that Combust Biomass (Results of Database Query)
On August 24, 2010, a query of the CAMD database was performed, to identify units in
Part 75 monitoring and reporting programs (i.e., Acid Rain, CAIR, RGGI, NOx SIP Call) that
combust biomass and/or partially biogenic fuels such as municipal solid waste (MSW) and tire-
derived fuel (TDF), either as the primary fuel or as a secondary fuel. For each unit, the query
also provided the unit's reporting frequency (i.e., year-round or ozone season-only), its Part 75
heat input methodology, and (if applicable) its C02 mass emissions methodology.
The objective of the query was to find out how many Part 75 units that burn biomass or
partly biogenic fuels would qualify to use a recently-proposed Greenhouse gas (GHG) emissions
reporting option under 40 CFR Part 987. That option would allow Part 75 units to report only the
total annual C02 mass emissions in their Part 98 GHG emissions reports, instead of separately
reporting biogenic C02 and non-biogenic C02 emissions.
To qualify for the optional biogenic C02 reporting, a unit that combusts biomass or
partly biogenic fuel(s) would either have to be: (1) an Acid Rain Program (ARP) unit; (2) a
RGGI Program unit; or (3) a CAIR unit (or NOx SIP Call unit) that is not in ARP or RGGI, and
that reports heat input data (but not C02 mass emissions data) to EPA year-round using Part 75
methods. Units in Categories (1) and (2) are subject to Subpart D of Part 98. Units in Category
(3) fall under §98.33(a)(5) of Subpart C. Many units are in more than one Part 75 program.
The results of the query showed that there are 53 units in Part 75 programs that combust
biomass or partly biogenic fuel. Ten of these units would not qualify for optional biogenic C02
reporting at the present time, because they are subject only to the CAIR Ozone Season Program,
and report heat input data to EPA on an ozone season-only basis, rather than year-round—
however, these 10 units could qualify in subsequent years if they were to switch to year-round
reporting. The status of three other units that combust refuse (MSW) as a secondary fuel is
questionable, because units that combust MSW are required by Part 98 to quantify biogenic C02
emissions (see §98.33(e)(3))8. By means of a phone call to one of the facilities on the list9, we
have learned that there is a fourth Part 75 unit that burns MSW as a backup fuel. Finally, one unit
identified by the query was eliminated from further consideration because it combusts coal
refuse, not municipal solid waste (the monitoring plan was incorrectly coded).
7 See the proposed revisions to §§98.3(c), 98.33, and 98.36(d) in the August 11, 2010 Federal Register notice (75
FR 48744-48814).
8 These three units are included as candidates for the optional biogenic C02 reporting only because they are subject
to Part 75. Note, however, that if the proposal to make biogenic C02 emissions reporting optional is finalized, the
rule would become internally inconsistent, because §98.33(e)(3) would require Part 75 units that combust MSW to
quantify biogenic C02, but the new rule provision would not require the facility to report biogenic C02 emissions
separately.
9 August 25, 2010 telephone call from Robert Vollaro of CAMD to Donald Kom of the City of Ames, IA
31
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This means that to the best of our knowledge, there are an estimated 43 Part 75 units that
could presently qualify for the proposed optional biogenic C02 reporting under Part 98. The
adjusted results of the query are presented in Table 1, below. The 10 units that could not
currently qualify for the optional reporting, but may be able to qualify in future years, are shown
in Table 2, below. Biomass fuels and partly biogenic fuels are highlighted in yellow in Tables 1
and 2.
Table 1: Part 75 Units that Would Presently Qualify
for Optional Biogenic C02 Reporting
Unit
Type
Primary fuel
Secondary fuel
Number of
Units
EGU
Non-EGU
Coal
TDF
17
17
-
Coal
Wood
8
6
2
Wood
Natural Gas
7
7
-
Coal
Municipal Solid Waste
4
3
1
Wood
2
2
-
TDF
1
1
-
Coal
Process Sludge
1
-
1
Wood
Other Solid Fuel
1
1
-
Wood
Coal
1
1
-
Residual Oil
Wood
1
-
1
Table 2: Part 75 Units that May Qualify for Optional Biogenic C02 Reporting in
Future Years
Unit
Type
Primary fuel
Secondary fuel
Number of
Units
EGU
Non-EGU
Coal
Wood
5
1
4
Wood
Coal
2
2
-
TDF
LPG
2
2
-
Coal
Process Sludge
1
-
1
Table 1 shows that twelve (12) of the qualifying units combust biomass or partly biogenic
fuel as the primary fuel. For 11 of these 12 units, wood is the primary fuel, and for the other
unit, TDF is the primary fuel. Nine of the 12 units combust secondary fuels (seven of them burn
natural gas, one burns coal, and one burns "other" solid fuel). Three of the units (two wood-fired
units and one TDF-fired unit) list no secondary fuels.
For the remaining 31 units in Table 1, 30 of them combust coal as the primary fuel and
one unit combusts residual oil. All 31 of the units burn biomass or partly biogenic fuel as a
32
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secondary fuel—17 of them burn TDF, 9 of them burn wood, 4 of them burn MSW, and one
paper mill unit combusts process sludge.
Thirty eight (38) of the 43 units in Table 1 are electricity generating units (EGUs) and
the other 5 are non-EGUs. Four (4) of the 5 non-EGUs are located at pulp and paper
manufacturing facilities.
For all the results from the database query, please see the data entry to docket EPA-HQ-
OAR-2008-0508 titled List of Part 75 units that combust biomass.
Results
The results of the CAMD database query show that a relatively significant number of Part
75 units (43) would qualify for optional biogenic C02 emissions reporting under the August 11,
2010 proposed revisions to Part 98. Twelve (12) of these units combust wood or TDF as the
primary fuel, and the other 31 units combust a variety of biogenic or partly biogenic fuels (i.e.,
wood, TDF, MSW, process sludge) as secondary fuels. Ten other Part 75 units that report
emissions data to EPA on an ozone season-only basis could not qualify for the optional biogenic
C02 reporting at the present time, but could qualify in future years by switching to year-round
reporting.
33
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Subpart X and Y
Evaluation of Process Heaters Less than 30 MMBtu/hr Rated Heat Capacity
I. Purpose10
The purpose of this memorandum is to document the evaluation of process heaters that
have a rated heat capacity of less than 30 million British thermal units per hour (MMBtu/hr).
II. Summary of Findings
Small process heaters (those with rated heat capacity less than 30 MMBtu/hr) are
generally not subject to Federal or consent decree emission limits and therefore are not typically
required to monitor fuel gas usage at the individual process heater or boiler. These small process
heaters are expected to contribute less than 5 percent of the stationary combustion source
emissions.
III. Background
The U. S. Environmental Protection Agency (EPA) finalized mandatory greenhouse gas
(GHG) reporting requirements on October 30, 2009 (74 FR 56260), which requires petroleum
refineries to use Tier 3 calculation and monitoring methods for stationary combustion sources
that combust fuel gas. EPA received feedback from stakeholders seeking relief from the Tier 3
monitoring requirements for small combustion sources.
IV. Approach and Discussion of Results
Available information regarding existing monitoring requirements for small stationary
combustion sources at petroleum refineries was reviewed. Attachment 1 presents a summary of
consent decree requirements. As shown in the Attachment 1, requirements for nitrogen oxide
(NOx) from process heaters generally apply to process heaters greater than 40 MMBtu/hr.
Similarly, review of NOx emission limits in 40 CFR 60 subpart Ja and in South Coast Air
Quality Management District (AQMD) Rule 1109 indicate that these rules apply to process
heaters greater than 40 MMBtu/hr. 40 CFR 60 subpart Dc specifically addresses sulfur dioxide
(S02) and particulate matter (PM) emissions from steam generating units from 10 to 100
MMBtu/hr rated heat capacity. The PM emission standards, however, apply only to units that
combust coal (alone or in combination with other fuels) in units with rated heat capacities of 30
MMBtu/hr or greater. While the S02 standards apply to smaller units, compliance with the S02
standards is expected to be assessed from hydrogen sulfide (H2S) or total sulfur monitoring in the
fuel gas mix drum rather than at the individual combustion unit. Thus, it appears likely that most
process heaters less than 30 MMBtu rated input heat capacity are not typically required to
monitor fuel gas usage at the individual process heater or boiler.
The distribution of process heaters were estimated based on facility-specific processing
unit capacities (EIA, 2006) and fuel use factors used previously to project GHG emissions by
10 Developed with support from Jeff Coburn, RTI International.
34
-------
petroleum refinery (Coburn, 2007). Based on these factors, the cumulative process heater
capacity for all U.S. refineries is estimated to be 257,831 MMBtu/hr. The cumulative sum of the
process heater capacities projected to be 30 MM Btu/hr or greater based on the EIA reported
process capacities is 253,796 MMBtu/hr or over 98 percent of the nationwide capacity. We note
that the EIA processing capacities are reported for the refinery. In some cases, there may be two
or more processing units of the same type at the refinery, so that the individual process heater
sizes projected from the EIA processing capacities will be overstated if there are multiple units at
the refinery. Assuming every unit has two process heaters (or that each facility has two units for
each type of processing unit listed in EIA), the cumulative sum of the process heater capacities
projected to be 30 MM Btu/hr or greater is 245,996 MMBtu/hr or approximately 95 percent of
the nationwide capacity. As it is anticipated that the larger facilities are more likely to have
either multiple equipment trains or multiple process heaters for a given process unit, the actual
fuel use for process heaters with rated heat capacities of 30 MMBtu/hr or more is expected to be
somewhere between these two estimates; however, in both scenarios, process heaters with rated
heat capacities less than 30 MMBtu/hr are projected to contribute less than 5 percent of the
nationwide fuel use.
V. References
Coburn J. 2007. Greenhouse Gas Industry Profile for the Petroleum Refining Industry. Prepared
for U.S. Environmental Protection Agency, Washington, DC. Contract No. GS-10F-
0283K. June 11.
EIA (Energy Information Administration). 2006. Refinery Capacity Report 2006. Prepared by
the Energy Information Administration, Washington, DC. June 15.
35
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Lion Oil Co. - El Dorado, AR
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install low-NOx burners or alternate
technology
0.045 lb/MMBtu for
atmospheric heater
(8-year program - see
Appendix C)
Heaters and boilers
CO
BACT analysis, install controls and comply
with EPA-established limits
Analysis - 4/30/03
Controls - 12/31/04
Heaters and boilers
S02
Comply with subpart J; limit H2S in
refinery fuel gas
CEMS by 12/31/06
BP (formerly Atlantic Richfield Co. (ARCO)) - Carson, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
Date of entry
Chevron USA Products
Co. - El Segundo, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Controlled H/B (SCR, low-NOx burners, shut
down, etc.) must represent 30% of the total
heat input capacity of H/B greater than 40
MMBtu/hr
0.040 lbs/MMBtu
6/30/11
Heaters and boilers
S02
Affected facility under subpart J; eliminate
fuel oil burning
Date of entry
Chevron USA Products
Co. - Richmond, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Controlled H/B (SCR, low-NOx burners, shut
down, etc.) must represent 30% of the total
heat input capacity of H/B greater than 40
MMBtu/hr
0.040 lbs/MMBtu
6/30/11
36
-------
Chevron USA Products
Co. - Richmond, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facility under subpart J; eliminate
fuel oil burning
Date of entry
ConocoPhillips (formerly Tosco, formerly Unocal Corp.) - Carson (LAR), CA
Heaters and boilers
S02
Affected facilities under subpart J
3/31/05
Heaters and boilers
S02
Comply with 40 C.F.R. §60.104(a)(1)
Date of lodging
ConocoPhillips (formerly Tosco, formerly Unocal Corp.) - Wilmington (LA), CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
3/31/05
Heaters and boilers
S02
Comply with 40 C.F.R. §60.104(a)(1)
Date of lodging
ConocoPhillips (formerly Tosco, formerly Unocal Corp.) - Rodeo (SF), CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
ConocoPhillips (formerly Tosco, formerly Unocal Corp.) - Santa IV
[aria (SF), CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/06
Valero (formerly Ultramar Diamond Shamrock) - Wilmington, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
37
-------
Valero (formerly Ultramar Diamond Shamrock) - Wilmington, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
Valero ( formerly Exxon Co. USA) - Benicia, CA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
Suncor Energy (formerly
Conoco Inc.) - Commerce City (Denver), CO
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity greater than 40 MMBtu/hr
7/31/09
Heater H-27
Affected facility under subpart J
12/31/06
Heaters and boilers
S02, PM,
CO
Affected facilities under subpart J
Date of lodging
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.005 lb/MMBtu (365-day
avg.); 0.010 lb/MMBtu (24-
hr avg.)
Date refinery applies for
PAL
Heaters and boilers
CO
Comply with emission limit when NOx
controls are added or if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb/MMBtu (365-day
avg.); 0.060 lb/MMBtu (24-
hr avg.)
Date of NOx control
installation or Date
refinery applies for PAL
Heaters and boilers
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu (365-
day avg.) OR 125 ppmvd
H2S in fuel gas (365-day
avg.)
Date refinery applies for
PAL
Valero Energy (formerly Ultramar Diamond Shamrock, formerly r
"otal Petroleum) - Denver
Commerce City), CO
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
38
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Citgo Petroleum - Savannah, GA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
combusting refinery
fuel gas
S02
Affected facility under subpart J
Date of entry
FCCU heater
NOx
Install controls (SCR, low-NOx burners, etc.)
or shut down
0.040 lbs/MMBtu
12/31/08
Heaters and boilers
S02
Affected facility under subpart J
Date of entry
Tesoro Hawaii Petrol, (formerly BHP) - Kapolei, HI
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
6/30/11
Heaters and boilers
that combust
refinery fuel gas
S02
Affected facility under subpart J
Date of entry
Marathon Ashland Petrol. - Robinson, IL
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(3 65-day avg.)
Date of application for
the PAL
Premcor Re
Ining Group (formerly Clark Oil and Refining Corp.) - Hartford, IL
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Combination of current and new generation
ultra low-NOx burners and low NOx burners
Design to achieve between
0.012 and 0.06 lb/MMBtu
10/1/05
Heaters and boilers
SOx and
NOx
Discontinue burning of fuel oil
30 days after Date of
entry
Heaters and boilers
Affected sources under subpart J
Date of entry
39
-------
ConocoPhillips (formerly Tosco Refining, Equilon, Wood River, & Shell Oil) - Wood River (E
.oxana), IL
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
(Distilling West)
S02
Affected facilities under subpart J
Date of lodging
Heaters and boilers
(except Distilling
West)
S02
Affected facilities under subpart J
6/30/08
BP (formerly Amoco Oil Co.) - Whiting, IN
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
S02
Eliminate fuel oil burning
6/01/03
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
12/31/01
National Cooperative Refinery Association - McPherson, KS
Unit
Pollutant
Requirement
Emission limit
Deadline
Boilers SB-016 and
SB-018
NOx
Comply with emission limit
101.9 tons/yr (12-month
avg.) (both boilers
combined)
Date of lodging
Distillate
hydrotreater feeder
& platformer heater
H2S
Comply with H2S concentration limit in fuel
gas
5 gr/100 scf (365-day avg.)
30 days after Date of
entry
Marathon Ashland Petroleum LLC (formerly Ashland, Inc.) - Catlettsburg, KY
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(3 65-day avg.)
Date of application for
the PAL
40
-------
Citgo Petroleum Corp. - Lake Charles, LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
6/30/11
Heaters and boilers
that combust
refinery fuel gas
S02
Affected facility under subpart J
Date of entry
ConocoPhillips (formerly Conoco Inc.) - Westlake (Lake Charles), LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity greater than 40 MMBtu/hr
7/31/09
Heaters and boilers
S02, PM,
CO
Affected facilities under subpart J
Date of lodging
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.005 lb/MMBtu (365-day
avg.); 0.010 lb/MMBtu (24-
hr avg.)
Date refinery applies for
PAL
Heaters and boilers
CO
Comply with emission limit when NOx
controls are added or if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb/MMBtu (365-day
avg.); 0.060 lb/MMBtu (24-
hr avg.)
Date of NOx control
installation or Date
refinery applies for PAL
Heaters and boilers
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu (365-
day avg.) OR 125 ppmvd
H2S in fuel gas (365-day
avg.)
Date refinery applies for
PAL
Marathon Ashland Petroleum LLC - Garyville, LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
12/31/08
Heaters and boilers
CO
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.060 lb/MMBtu (24-hr
avg.), 0.040 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
41
-------
Marathon Ashland Petroleum LLC - Garyville, LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(365-day avg.)
Date of application for
the PAL
Valero (formerly Orion
defining Corp, formerly TransAmerican Refining Corp) - Norco (St. Charles Parish), LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
ConocoPhillips (formerly, Tosco Refining Co., formerly BP Oil Co.
i - Belle Chasse (Alliance), LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
(except 191-H-l)
S02
Affected facilities under subpart J
Date of lodging
Heater 191-H-l
S02
Affected facilities under subpart J
12/31/06
Valero (formerly Basis Petroleum, Inc.) - Krotz Springs, LA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
Marathon Ashland Petrol. LLC - Detroit, MI
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
12/31/08
42
-------
Marathon Ashland Petrol. LLC - Detroit, MI
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
CO
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.060 lb/MMBtu (24-hr
avg.), 0.040 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(3 65-day avg.)
Date of application for
the PAL
Flint Hills Resources (formerly Koch Refining Co.) - Rosemount (Pine Bend), MN
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install ultra low-NOx burners on heaters and
boilers with HHV 40 MMBtu/hr or higher
Design to achieve 0.012 -
0.04 lb/MMBtu
12/31/06
Heaters and boilers
Affected facilities under subpart J (few
exceptions)
1/01/01
Marathon Ashland Petroleum LLC (formerly Ashland, Inc.) - St. Paul Park, MN
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
12/31/08
Heaters and boilers
CO
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.060 lb/MMBtu (24-hr
avg.), 0.040 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(3 65-day avg.)
Date of application for
the PAL
43
-------
Chevron USA Inc. - Pascagoula, MS
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Controlled H/B (SCR, low-NOx burners, shut
down, etc.) must represent 30% of the total
heat input capacity of H/B greater than 40
MMBtu/hr
0.040 lbs/MMBtu
6/30/11
Heaters and boilers
S02
Affected facility under subpart J; eliminate
fuel oil burning
Date of entry
Ergon Refining Inc. - Vicksburg, MS
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
Heaters and boilers
S02
Eliminate fuel oil burning except during
natural gas curtailment
Date of lodging
Cenex Harvest States - Laurel, MT
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Shut down or install NOx controls on at least
30% of the heater capacity greater than 40
MMBtu/hr
12/31/11
Heaters and boilers
S02
Minimize burning of fuel oil
Conoco Inc. - Billings, MT
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity greater than 40 MMBtu/hr
7/31/09
Heater H-16
Affected facility under subpart J
6/30/03
Heaters and boilers
S02, PM,
CO
Affected facilities under subpart J
Date of lodging
Heaters and boilers
S02
Comply with emission limit when fuel oil is
burned
300 tons/year (3 65-day
avg.)
Date of lodging
44
-------
Conoco Inc. - Billings, MT
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.005 lb/MMBtu (365-day
avg.); 0.010 lb/MMBtu (24-
hr avg.)
Date refinery applies for
PAL
Heaters and boilers
CO
Comply with emission limit when NOx
controls are added or if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb/MMBtu (365-day
avg.); 0.060 lb/MMBtu (24-
hr avg.)
Date of NOx control
installation or Date
refinery applies for PAL
Heaters and boilers
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu (365-
day avg.) OR 125 ppmvd
H2S in fuel gas (365-day
avg.)
Date refinery applies for
PAL
Montana Refining Co. - Great Falls, MT
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install next generation ultra low NOx burners
for any heater or boiler that begins to operate
with a heat input capacity of 40 MMBtu/hr or
greater
Any time during life of
consent decree
Heaters and boilers
S02
Affected facilities under subpart J
12/31/06
Heaters and boilers
S02
Eliminate burning of fuel oil (with a few
exceptions)
Date of lodging
Citgo Asphalt Refining Co. - Paulsboro, NJ
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
combusting refinery
fuel gas
S02
Affected facility under subpart J
Date of entry
Sunoco (formerly Coastal Eagle Point Oil Co.) - Westville, NJ
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls and accept federally-
enforceable emission limits
0.040 lb/MMBtu
3 years
45
-------
Sunoco (formerly Coastal Eagle Point Oil Co.) - Westville, NJ
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of lodging
Heaters and boilers
S02
Eliminate fuel oil burning except during
natural gas curtailment
Date of lodging
Boilers 5, 6, 7, and 8
PM-10
Comply with emission limit
0.000427 lbs/MMBtu (1-hr
avg.)
Date of entry
ConocoPhillips (formerly Tosco Refining Co., formerly Bayway) -
Jnden (Bayway), NJ
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
(except selected)
S02
Affected facilities under subpart J
Date of lodging
Selected heaters and
boilers
S02
Affected facilities under subpart J
6/30/11
Valero Energy Corp. (formerly Mobil Oil) - Paulsboro, NJ
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/08
Navajo Refining Co. - Artesia, NM
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install next generation ultra low NOx
burners for all controlled heaters and boilers
except Boilers B-7 and B-8
12/31/05 and 12/31/09
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
Heaters and boilers
S02
Eliminate burning of fuel oil (with a few
exceptions)
Date of lodging
46
-------
Tesoro (formerly BP, formerly Amoco Oil Co.) - Mandan, ND
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
S02
Eliminate fuel oil burning
3/31/01
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
9/30/03
Heaters and boilers
H2S
Volume-weighted, rolling 3-hour average
concentration of H2S in refinery fuel gas
0.10 gr/dscf
12/31/01 until 9/30/03
BP Oil Co. - Toledo, OH
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
9/30/03
Heaters and boilers
H2S
Volume-weighted, rolling 3-hour average
concentration of H2S in refinery fuel gas
0.10 gr/dscf
12/31/01 until 9/30/03
Marathon Ashland Petroleum LLC (formerly Ashland, Inc.) - Canton, OH
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
12/31/08
Heaters and boilers
CO
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.060 lb/MMBtu (24-hr
avg.), 0.040 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
47
-------
Marathon Ashland Petroleum LLC (formerly Ashland, Inc.) - Canton, OH
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(365-day avg.)
Date of application for
the PAL
Sunoco, Inc. - Toledo, OH
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity (all of the capacity greater than
40 MMBtu/hr if less than 30% of total)
8 years after Date of entry
Heaters and boilers
S02
Affected facilities under subpart J
12/31/09
Heaters and boilers
S02
Eliminate fuel oil burning (a few exceptions
provided)
Date of entry
Conoco Inc. - Ponca City, OK
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity greater than 40 MMBtu/hr
7/31/09
Heaters and boilers
S02, PM,
CO
Affected facilities under subpart J
Date of lodging
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.005 lb/MMBtu (365-day
avg.); 0.010 lb/MMBtu (24-
hr avg.)
Date refinery applies for
PAL
Heaters and boilers
CO
Comply with emission limit when NOx
controls are added or if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb/MMBtu (365-day
avg.); 0.060 lb/MMBtu (24-
hr avg.)
Date of NOx control
installation or Date
refinery applies for PAL
Heaters and boilers
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu (365-
day avg.) OR 125 ppmvd
H2S in fuel gas (365-day
avg.)
Date refinery applies for
PAL
48
-------
Sunoco, Inc. - Tulsa, OK
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity (all of the capacity greater than
40 MMBtu/hr if less than 30% of total)
8 years after Date of entry
Heaters and boilers
S02
Affected facilities under subpart J
Date of entry
Heaters and boilers
S02
Eliminate fuel oil burning (a few exceptions
provided)
Date of entry
Valero (formerly Ultramar/Diamond Shamrock, formerly Total Pe
troleum Inc.) - Ardmore, C
)K
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/10
Sunoco, Inc. - Marcus Hook, PA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity (all of the capacity greater than
40 MMBtu/hr if less than 30% of total)
6/15/10
Heaters and boilers
S02
Affected facilities under subpart J
Date of entry
Heaters and boilers
S02
Eliminate fuel oil burning (a few exceptions
provided)
Date of entry (12/31/05
for a few)
Sunoco (combined Sun & Chevron) - Philadelphia (Girard Pt & Pt Breeze), PA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install NOx controls on at least 30% of the
heater capacity (all of the capacity greater
than 40 MMBtu/hr if less than 30% of total)
6/15/10
Heaters and boilers
S02
Affected facilities under subpart J
12/31/10
Heaters and boilers
S02
Eliminate fuel oil burning (a few exceptions
provided)
Date of entry (later dates
for a few)
49
-------
ConocoPhillips (formerly Tosco Refining Co., formerly BP) - Trainer (Marcus Hook), PA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
6/30/08
BP (formerly Amoco Oil Co.) - Texas City, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
Date of entry
Citgo - Corpus Christi,r
rx
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
(East and West)
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
6/30/11
Heaters and boilers
that combust
refinery fuel gas
S02
Affected facility under subpart J
Date of entry
Flint Hills Resources (formerly Koch Petroleum Group, includes SWest Refining) - Corpus Christi, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install ultra low-NOx burners on heaters and
boilers with HHV 40 MMBtu/hr or higher
Design to achieve 0.012
- 0.04 lb/MMBtu
12/31/06
Marathon Ashland Petrol. LLC - Texas City, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
12/31/08
Heaters and boilers
CO
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.060 lb/MMBtu (24-hr
avg.), 0.040 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
50
-------
Marathon Ashland Petrol. LLC - Texas City, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02, PM
Affected facilities under subpart J
Date of entry (8/30/01)
Heaters and boilers
PM
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.010 lb/MMBtu (24-hr
avg.), 0.005 lb/MMBtu
(3 65-day avg.)
Date of application for
the PAL
Heaters and boilers
that burn fuel gas
only
S02
Comply with emission limit if a Plantwide
Applicability Limit (PAL) is adopted
0.040 lb S02/MMBtu or
125 ppmvd H2S in fuel gas
(3 65-day avg.)
Date of application for
the PAL
ConocoPhillips (formerly Phillips Petroleum Co.) - Borger, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
ConocoPhillips (formerly Phillips Petroleum Co.) - Sweeny, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
6/30/08
Valero (formerly Ultramar/Diamond Shamrock Corp.) - Three Rivers, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/10
Valero (formerly Ultramar/Diamond Shamrock Corp.) - Sunray (McKee), TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/10
51
-------
Valero Refining Co. - Corpus Christi, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
(East)
S02
Affected facilities under subpart J
12/31/10
Heaters and boilers
(West)
S02
Affected facilities under subpart J
12/31/07
Valero (formerly Basis Petroleum, Inc.) - Houston, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
Valero (formerly Basis Petroleum, Inc.) - Texas City, TX
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Discontinue burning or combustion of fuel oil
(during NG curtailment, may burn low sulfur
fuel oil)
12/31/05
Heaters and boilers
S02
Affected facilities under subpart J
12/31/07
Tesoro (formerly BP, formerly Amoco Oil Co.) - Salt Lake City, UT
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
S02
Eliminate fuel oil burning
6/01/02
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
Date of entry
52
-------
Chevron USA - Salt Lake City, UT
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Controlled H/B (SCR, low-NOx burners,
shut down, etc.) must represent 30% of the
total heat input capacity of H/B greater than
40 MMBtu/hr
0.040 lbs/MMBtu
6/30/11
Heaters and boilers
S02
Affected facility under subpart J; eliminate
fuel oil burning except during natural gas
curtailment, test runs, or training
Date of entry
Giant Refining (formerly BP, formerly Amoco Oil Co.) - Yorktown, VA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
S02
Eliminate fuel oil burning
6/01/01
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
Date of entry
BP (formerly Atlantic Richfield Co. (ARCO)) - Ferndale (Cherry Point), WA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install controls on 30% of total heat input
capacity of heaters and boilers with capacities
greater than 40 MMBtu/hr
1/18/05
Heaters and boilers
Subject to subparts A & J as those subparts
apply to fuel gas combustion devices
9/30/05
Heaters and boilers
H2S
Volume-weighted, rolling 3-hour average
concentration of H2S in refinery fuel gas
0.10 gr/dscf
12/31/01 until 9/30/05
ConocoPhillips (formerly Tosco Refining Co.) - Ferndale, WA
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
53
-------
Ergon-West Virginia inc. (formerly Quaker State Oil Refining Corp.) - Newell, WV
Unit
Pollutant
Requirement
Emission Limit
Deadline
Boiler A
NOx
Install next generation ultra low-NOx burner
EPA to determine emission
limit
Install - 12/31/05
Boiler B
NOx
Install next generation ultra low-NOx burner
EPA to determine emission
limit
Install - 12/31/08
Boiler C
NOx
Comply with emission limit
0.050 lb/MMBtu (3-hr avg.)
12/31/03
H-101
NOx
Comply with emission limit
0.065 lb/MMBtu (3-hr avg.)
12/31/03
Heaters and boilers
S02
Affected facilities under subpart J
12/31/06
Heaters and boilers
S02
Eliminate fuel oil burning except during
natural gas curtailment
Date of lodging
Murphy Oil USA Inc. - Superior, WI
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
S02
Reduce burning of fuel oil
33.3 tons/month (12-month
avg.)
5/01/02
Navajo Refining Co. - Lovington, NM
Unit
Pollutant
Requirement
Emission Limit
Deadline
Heaters and boilers
NOx
Install next generation ultra low NOx burners
for all controlled heaters and boilers except
Boilers B-7 and B-8
12/31/05 and 12/31/09
Heaters and boilers
S02
Affected facilities under subpart J
Date of lodging
Heaters and boilers
S02
Eliminate burning of fuel oil (with a few
exceptions)
Date of lodging
54
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Subpart OO
Impact of Minor Constituents on the GW of the Mixture as a Function of Concentration
Impact of Minor Constituents on the GWP of the Mixture as a Function of Concentration
GWP Relationship
Concentration of
Minor
Constituent
GWP of
Major
Constituent
GWP of
Minor
Constituent
C02e of
Major
Constituent
C02e of
Minor
Constituent
Weighted
GWP of
Combination
Percent by Which GWP of
Mixture is Higher than That
of Major Constituent
10x (hypothetical)
0.1%
100
1000
99.9
1
100.9
0.9%
0.5%
100
1000
99.5
5
104.5
4.5%
1.0%
100
1000
99
10
109
9.0%
55
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Subpart PP
CO2 Density Value
EPA proposed that standard temperature and pressure for subpart PP be 60 degrees F and 1.000
atm. For the proposal, EPA identified a table in the online database of thermodynamic properties
developed by the National Institute of Standards and Technology (NIST) (available at
http://webb00k.nist.gov/chemistry/fluid/) with density values of CO2 listed by temperature in
degrees F and by pressure in psi. EPA decided to use the density values of C02 at 60 degrees F
and at 14.713 psi, which is equivalent to 1.00116 atm pressure, as the density value of C02 in
the proposal. That value is 0.0018704 metric tons per standard cubic meter.
Between the proposal and this final rule, EPA identified a second NIST table on the online
database with density values of C02 listed by temperature in degrees F and by pressure in atm.
By using this NIST table, we can select a more precise value for the density of C02 at the exact
standard conditions specified for subpart PP. Therefore, in this final action, we are using
0.0018682 metric tons per standard cubic meter as the density of C02 because it is the density
value of C02 at 60 degrees F and 1.000 atm.
56
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