This document was developed for the Proposed Mandatory GHG Reporting Rule.
For the final document, please visit the final Mandatory Reporting of
Greenhouse Gases Rule.
Petroleum Refineries
c,EPA
Proposed Rule: Mandatory Reporting of Greenhouse Gases
United States
Environmental Protection
Agancy
Under the proposed Mandatory Reporting of Greenhouse Gases (GHGs) rule, owners or operators of
facilities that refine petroleum would 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
would collect feedstock and product data or emission data; calculate GHG emissions; and follow the
specified procedures for quality assurance, missing data, recordkeeping, and reporting.
Facilities that refine petroleum would also be required to report emissions under 40 CFR part 98,
subpart MM (Suppliers of Petroleum Products).
How Is This Source Category Defined?
Under the proposal, petroleum refineries are facilities that produce gasoline, kerosene, distillate fuel oils, residual
fuel oils, lubricants, asphalt (bitumen) or other products by the distillation of petroleum or the redistillation,
cracking, or reforming of petroleum derivatives.
What GHGs Would Be Reported?
Under the proposal, the refinery processes and gases that would be reported are listed in the table below along with
the rule subpart that specifies the calcination methodology that would be used.
For this refinery process . . .
Stationary combustion
Flares
Catalytic cracking
Traditional fluid coking
Fluid coking with flexicoking design
Delayed coking
Catalytic reforming
Onsite and offsite sulfur recovery
Onsite wastewater treatment
Coke calcining
Asphalt blowing (controlled)
Asphalt blowing (uncontrolled)
Equipment leaks
Storage tanks
Delayed coking
Other process vents
Uncontrolled blowdown systems
Loading operations
Report emissions of the listed GHGs by following
the requirements of the 40 CFR part 98, subpart
indicated...
Carbon
Dioxide (CO2)
C
Y
Y
Y
C/Y
-
Y
Y
II
Y
Y
-
-
-
-
Y
-
-
Methane
(CH4)
C
Y
Y
Y
C/Y
Y
Y
-
II
Y
-
Y
Y
Y
Y
Y
Y
Y
Nitrous Oxide
(N20)
C
Y
Y
Y
C/Y
-
Y
-
-
Y
-
-
-
-
-
Y
-
-
March 2009
EPA-430-F-09-021
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This document was developed for the Proposed Mandatory GHG Reporting Rule.
For the final document, please visit the final Mandatory Reporting of
Greenhouse Gases Rule.
Hydrogen plants (nonmerchant)
Onsite landfills
P
-
P
HH
-
-
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)
HH = 40 CFR part 98, subpart HH (Landfills)
II = 40 CFR part 98, subpart II (Industrial Wastewater Treatment)
- = 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, P, HH, and II summarize the requirements for calculating and reporting emissions.
How Would GHG Emissions Be Calculated?
Under 40 CFR part 98, subpart Y, the proposal calls for owners or operators of petroleum refineries to calculate CH4
and N2O emissions using the calculation methods described below for each refinery process.
For CO2 emissions, owners or operators would use one of two alternative methods:
• Refinery units with certain types of continuous emission monitoring systems (CEMS) in place would report
using the CEMS and follow the methodology of 40 CFR part 98, subpart C to report total CO2 emissions
from calcination and fuel combustion. At other refinery units, the use of CEMS would be optional.
• Facilities without CEMS would calculate CO2 emissions using the methods summarized below.
Flares
CO2 emissions from flares would be calculated using the gas flow rate (either measured with a continuous flow
meter or estimated using engineering calculations) and either: 1) the daily measured carbon content of the flare gas,
or 2) the daily measured heat content of the flare gas and an emission factor provided in the rule. If the carbon
content and heat content of the gas are not measured on a daily basis, CO2 emissions for each startup, shutdown, and
malfunction event would be calculated separately using engineering estimates of the quantity of gas discharged and
the carbon content of the flared gas. CH4 and N2O emissions from flares would be calculated using the methods
specified in 40 CFR part 98, subpart C.
Catalytic Cracking Units, Fluid Coking Units, and Catalytic Reforming Units
CO2 emissions would be calculated using the volumetric flow rate of the exhaust gas (measured or calculated) and
the measured carbon monoxide (CO) and CO2 concentrations in the exhaust stacks from the catalytic cracking unit
regenerator, fluid coking unit burner, or catalytic reforming unit catalyst regenerator prior to the combustion of other
fossil fuels. Catalytic reforming units would have the option of using an alternative method in which annual CO2
emissions would be calculated using the quantity of coke burned off, the carbon content of the coke (using either a
measured or a default value), and the number of regeneration cycles. CH4 and N2O emissions would be calculated
using the CO2 emissions and default emission factors. 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.
Onsite and Offsite Sulfur Recovery
CO2 emissions would 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).
March 2009 2 EPA-430-F-09-021
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This document was developed for the Proposed Mandatory GHG Reporting Rule.
For the final document, please visit the final Mandatory Reporting of
Greenhouse Gases Rule.
Coke Calcining Units
CO2 emissions would be calculated from 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. The CH4 and N2O emissions
from coke calcining units would be calculated using the calculated CO2 emissions and default emission factors.
Asphalt Blowing Operations
For uncontrolled asphalt blowing operations, CH4 emissions would be calculated using a facility-specific emission
factor based on test data or, where test data are not available, a default emission factor provided in the rule. For
controlled asphalt blowing operations, CO2 emissions would be calculated by using a mass balance approach in
which all of the CH4 generated by the asphalt blowing operation is converted to CO2.
Equipment Leaks
CH4 emissions from equipment leaks would 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 CH4 emissions depends on the material stored.
For storage tanks used to store unstabilized crude oil, facilities would use either: 1) the CH4 composition of the
unstabilized crude oil (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 CH4 in the vented
gas (using either a measured or a default value), and an emission factor provided in the rule. For storage tanks used
to store material other than unstabilized crude oil, facilities would use either the TANKS Model (Version 4.09D) or
a default emission factor provided in the rule for tanks storing material with a vapor-phase CH4 concentration of 0.5
percent by volume or more.
Delayed Coking Units
CH4 emissions from the depressurization of delayed coking vessels would be calculated using the method outlined
below for other process vents. The emissions released during the opening of vessels for coke cutting operations
would be calculated using the vessel parameters (height and diameter), the number of times the vessel was opened,
and the mole fraction of CH4 in the gas released (using a measured or a default value provided in the rule).
Other Process Vents
GHG emissions from other process vents would be calculated using the volumetric flow rate, the mole fraction of
the GHG in the exhaust gas, and the number of hours during which venting occurred.
Uncontrolled Slowdown Systems
March 2009 3 EPA-430-F-09-021
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This document was developed for the Proposed Mandatory GHG Reporting Rule.
For the final document, please visit the final Mandatory Reporting of
Greenhouse Gases Rule.
CH4 emissions from uncontrolled blowdown systems would 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.
Loading Operations
CH4 emissions from loading operations would be calculated using the method in Section 5.2 of AP-42: Compilation
of Air Pollution Emission Factor. Facilities would calculate CH4 emissions only for loading materials that have an
equilibrium vapor-phase CH4 concentration equal to or greater than 0.5 percent by volume. Other facilities would
report zero CH4 emissions.
What Information Would Be Reported?
In addition to the information required by the General Provisions at 40 CFR 98.3(c), under the proposal, refineries
would 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 would 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 series of information sheets is intended to assist reporting facilities/owners in understanding key provisions of
the proposed rule. However, these information sheets are not intended to be a substitution for the rule. Visit EPA's
Web site (www.epa.gov/climatechange/emissions/ghgrulemaking.html') for more information, including the
proposed preamble and rule and additional information sheets on specific industries, or go to
to access the rulemaking docket (EPA-HQ OAR-2008-0508). For questions that cannot be
answered through the Web site or docket, call 1-877-GHG-l 188.
March 2009 4 EPA-430-F-09-021
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