Petroleum Refineries
xvEPA
Final Rule: Mandatory Reporting of Greenhouse Gases
United States
Environrnsntal Protection
Agency
Under the Mandatory Reporting of Greenhouse Gases (GHGs) rule, owners or operators of facilities that
refine petroleum must report emissions from petroleum refining processes and all other source categories
located at the facility for which methods are defined in the rule. Owners or operators are required to
collect feedstock and product or emission data; calculate GHG emissions; and follow the specified
procedures for quality assurance, missing data, recordkeeping, and reporting.
Facilities that refine petroleum also are required to report emissions under 40 CFRpart 98, subpartMM
(Suppliers of Petroleum Products).
How Is This Source Category Defined?
Petroleum refineries are facilities that produce gasoline, gasoline blending stocks, naphtha, kerosene,
distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) by the distillation of petroleum or the
redistillation, cracking, or reforming of unfinished petroleum derivatives.
Facilities that distill only pipeline transmix (off-spec material created when different specification
products mix during pipeline transportation) are not petroleum refineries, regardless of the products
produced.
What GHGs Must Be Reported?
The refinery processes and gases that must be reported are listed in the table below along with the rule
subpart that specifies the calculation methodology that must be used. Please note the table key on page 2.
For this refinery process . . .
Stationary combustion
Stationary combustion using fuel gas
Flares
Catalytic cracking
Traditional fluid coking
Fluid coking with flexicoking design
Catalytic reforming
Onsite and offsite sulfur recovery
Coke calcining
Asphalt blowing
Equipment leaks
Storage tanks
Delayed coking
Other process vents
Uncontrolled blowdown systems
Loading operations
Hydrogen plants (nonmerchant)
Report emissions of the listed GHGs by following the requirements of
the 40 CFR part 98, subpart indicated. . .
Carbon Dioxide (CO2)
C
C: Tier 3 (Equation C-5)
or Tier 41
Y
Y
Y
C/Y
Y
Y
Y
Y
-
-
-
Y
-
-
P
Methane (CH4)
C
C
Y
Y
Y
C/Y
Y
-
Y
Y
Y
Y
Y
Y
Y
Y
P
Nitrous Oxide (N2O)
C
C
Y
Y
Y
C/Y
Y
-
Y
-
-
-
-
Y
-
-
-
1 For CO2 emissions from combustion of fuel gas, the Tier 3 (equation C-5) or Tier 4 methodology must be used, as
stated in the rule. Rule text supersedes preamble text when inconsistencies occur.
40 CFR 98, subpart Y
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1
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Key:
C = 40 CFR part 98, subpart C (General Stationary Combustion Sources)
P = 40 CFR part 98, subpart P (Hydrogen Production)
Y = 40 CFR part 98, subpart Y (Petroleum Refineries)
- = Reporting from this process is not required
For refinery processes that are subject to subparts other than 40 CFR part 98, subpart Y, the information
sheets for 40 CFR part 98, subparts C and P summarize the requirements for calculating and reporting
emissions.
How Should GHG Emissions Be Calculated?
Under 40 CFR part 98, subpart Y, owners or operators of petroleum refineries must calculate CFi4 and
N2O emissions using the calculation methods described below for each refinery process.
For CO2 emissions, owners or operators must use one of two alternative methods:
• For applicable processes, refinery units with certain types of continuous emission monitoring
systems (CEMS) in place must report using the CEMS and follow the Tier 4 methodology of 40
CFR part 98, subpart C to report combined process and combustion CO2 emissions.
• For refinery units without CEMS in place, reporters can elect to either:
(1) Install and operate a CEMS to measure combined process and combustion CO2 emissions
according to the requirements specified in 40 CFR part 98, subpart C; or
(2) Calculate CO2 emissions using the methods summarized below.
Flares
CO2 emissions from flares must be calculated using the gas flow rate (either measured with a continuous
flow meter or estimated using engineering calculations) and either:
1) The daily or weekly measured carbon content of the flare gas; or
2) The daily or weekly measured heat content of the flare gas and a default emission factor provided
in the rule.
If the carbon content and heat content of the gas are not measured at least weekly, engineering estimates
of heat content during normal flare use may be used, but CO2 emissions from each startup, shutdown, and
malfunction event exceeding a certain threshold must be calculated separately, also using engineering
estimates. CFLj and N2O emissions from flares must be calculated using the emission factors specified in
40 CFR part 98, subpart C.
Catalytic Cracking Units, Fluid Coking Units
For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per
stream day (bbls/sd), continuously, or no less frequently than hourly, monitor the oxygen (O2), CO2, and
(if necessary) carbon monoxide (CO) concentrations in the exhaust stacks from the catalytic cracking unit
regenerator or fluid coking unit burner prior to the combustion of other fossil fuels. Calculate CO2
emissions using the volumetric flow rate of the exhaust gas (measured or calculated) and the measured
CO and CO2 concentrations in the exhaust stacks.
For catalytic cracking units and fluid coking units with rated capacities of 10,000 bbls/sd or less, either:
1) Monitor continuously or no less than daily the O2, CO2, and (if necessary) CO concentrations in
the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to
40 CFR 98, subpart Y 2 EPA-430-F-09-021R
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the combustion of other fossil fuels, and calculate CO2 emissions using the same method used for
units with rated capacities greater than 10,000 bbls/sd; or
2) Calculate CO2 emissions from each catalytic cracking unit and fluid coking unit using a coke
burn-off factor and the carbon content of the coke (either measured or default value).
If there is a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or
fluid coking unit exhaust gas, determine the CO2 emissions resulting from the combustion of these fuels
or other materials following the requirements in subpart C and report those emissions by following the
requirements of subpart C.
Calculate CH4 and N2O emissions using unit-specific measurement data, unit-specific emission factors
based on a source test of the unit, or the equations specified in the rule. Fluid coking units that use the
flexicoking design may account for their GHG emissions either by using the methods specified for
traditional fluid coking units, or by using the methods for stationary combustion specified in 40 CFR part
98, subpart C.
Catalytic Reforming Units
For catalytic reforming units either:
1) Monitor continuously, or no less frequently than daily, the O2, CO2, and (if necessary) CO
concentrations in the exhaust stack from the catalytic reforming unit catalyst regenerator prior to
the combustion of other fossil fuels, and calculate CO2 emissions according to the same
requirements of 40 CFR part 98.253(c)(2)(i) through (iii) for catalytic cracking units and fluid
coking units with rated capacities of 10,000 bbls/sd or less; or
2) Calculate CO2 emissions from the catalytic reforming unit catalyst regenerator using the quantity
of coke burned off, the carbon content of the coke (measured or default value), and the number of
regeneration cycles.
Calculate CFI4 and N2O emissions using the same methods specified in 40 CFR part 98.253(c)(4) and (5)
for catalytic cracking units and traditional fluid coking units.
Onsite and Offsite Sulfur Recovery
CO2 emissions must be calculated using the volumetric flow rate of the sour gas (measured continuously
or estimated from engineering calculations) and the carbon content of the sour gas stream (using a
measured or a default value).
Coke Calcining Units
CO2 emissions must be calculated from the difference between the carbon input as green coke and the
carbon output as marketable petroleum coke, and as coke dust collected in the dust collection system.
Calculate CFI4 and N2O emissions using the same methods specified in 40 CFR part 98.253(c)(4) and (5)
for catalytic cracking units and traditional fluid coking units.
Asphalt Blowing Operations
For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing,
CO2 and CFI4 emissions must be calculated using facility-specific emission factors based on test data or,
where test data are not available, default emission factors provided in the rule. For asphalt blowing
operations controlled by a thermal oxidizer or flare, CFI4 and CO2 emissions must be calculated by
assuming that 98 percent of the CFI4 and other hydrocarbons generated by the asphalt blowing operation
are converted to CO2.
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Equipment Leaks
CFL, emissions from equipment leaks must be calculated using either default emission factors or process-
specific CH4 composition data and leak data collected using the leak detection methods specified in
EPA's Protocol for Equipment Leak Emission Estimates.
Storage Tanks
For storage tanks, the calculation methodology used to calculate the CFL, emissions depends on the
material stored. For storage tanks used to store unstabilized crude oil, facilities must use either:
1) The tank-specific CFL, composition data (based on direct measurement or product knowledge)
and the measured gas generation rate; or
2) An emission factor-based method using the quantity of unstabilized crude oil received at the
facility, the pressure difference between the previous storage pressure and atmospheric pressure,
the mole fraction of CFL, in the vented gas (using either a measured or a default value), and an
emission factor provided in the rule.
For storage tanks that have a vapor-phase CFL, concentration of 0.5 percent by volume or more and store
material other than unstabilized crude oil, facilities must use either:
1) The tank-specific CFL, composition data and the emission estimation methods provided in Section
7.1 of the AP-42: Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and
Area Sources; or
2) The default emission factor specified in the rule.
Note that CH4 emissions from storage tanks do not need to be calculated for storage tanks meeting the
conditions specified in 40 CFRpart 98.253 (m)(3).
Delayed Coking Units
CH4 emissions from the depressurization of delayed coking vessels must be calculated by either:
1) Following the method outlined below for other process vents and calculating the CFL, emissions
from the subsequent opening of the vessel for coke cutting operations (if water or steam is added
to the vessel after it is vented to the atmosphere, this option must be used); or
2) Calculating the CFL, emissions from the depressurization vent, the subsequent opening of the
vessel for coke cutting operations, and the pressure of the coking vessel when the
depressurization gases are first routed to the atmosphere.
Other Process Vents
GHG emissions from other process vents that contain CO2, CFL,, or N2O exceeding concentration
thresholds specified in the rule must be calculated using the volumetric flow rate, the mole fraction of the
GHG in the exhaust gas, and the number of hours per venting event.
Uncontrolled Blow down Systems
CFL, emissions from uncontrolled blowdown systems must be calculated using either the mass balance
method specified for process vents or a default emission factor and the sum of crude oil and intermediate
products received from off site and processed at the facility.
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Loading Operations
CH4 emissions from loading operations must be calculated using the method in Section 5.2 ofAP-42:
Compilation of Air Pollution Emission Factors, Volume 1: Stationary Point and Area Sources. Facilities
must calculate CFLj emissions only for loading materials that have an equilibrium vapor-phase CFLj
concentration equal to or greater than 0.5 percent by volume.
A checklist for data that must be monitored is available at:
www.epa.gov/climatechange/emissions/downloads/checklists/petroleumrefineries.pdf.
What Information Must Be Reported?
In addition to the information required by the General Provisions at 40 CFR 98.3(c), refineries must
report the data used to identify emission units and calculate the GHG emissions (e.g., unit ID, unit type,
feed input, GHG calculation method). In addition, facilities must report GHG emissions at the unit level
for each catalytic cracking unit, coking unit, catalytic reforming unit, onsite and offsite sulfur recovery
plant, coke calcining unit, and process vent.
For More Information
This document is provided solely for informational purposes. It does not provide legal advice, have
legally binding effect, or expressly or implicitly create, expand, or limit any legal rights, obligations,
responsibilities, expectations, or benefits in regard to any person. The series of information sheets is
intended to assist reporting facilities/owners in understanding key provisions of the final rule.
Visit EPA's Web site (www.epa.gov/climatechange/emissions/ghgrulemaking.html) for more
information, including the final preamble and rule, additional information sheets on specific industries,
the schedule for training sessions, and other documents and tools. For questions that cannot be answered
through the Web site, please contact us at: ghgmrr(g),epa.gov.
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