Petroleum and Natural Gas Systems

Final Rule: Subpart W of 40 CFR Part 98



United States
Environmental Protection
Agency

Under this final rule to 40 CFR Part 98, owners or operators offacilities that contain petroleum
and natural gas systems (as defined below) and emit 25,000 metric tons or more of GHGs per
year (expressed as carbon dioxide equivalents) from process operations, stationary combustion,
miscellaneous use of carbonates, and other source categories (see information sheet on General
Provisions) will report emissions from all source categories located at the facility for which
emission calculation methods are defined in the ride. Owners or operators will collect emission
data; calculate GHG emissions; andfollow the specified procedures for quality assurance,
missing data, recordkeeping, and reporting.

How Is This Source Category Defined?

Under this final rule, this source category consists of emission sources in the following segments of the
petroleum and natural gas industry:

•	Onshore petroleum and natural gas production

•	Offshore petroleum and natural gas production

•	Onshore natural gas processing plants

•	Onshore natural gas transmission compression

•	Underground natural gas storage

•	Liquefied natural gas (LNG) storage

•	Liquefied natural gas import and export equipment

•	Natural gas distribution

Who Must Report?

Facilities that emit 25,000 metric tons or more of C02e per year must report. The rule defines three
different types of facilities. You must apply the 25,000 ton per year threshold separately to each facility
to determine if that facility must report.

•	For the onshore petroleum and natural gas production industry segment, a facility1 is defined
generally as all emission source types (see Table 1) on a well pad or associated with a well pad
that are under common ownership or control in a single hydrocarbon basin, as defined by the
American Association of Petroleum Geologists.

•	For natural gas distribution industry segment, a facility1 generally is defined as the collection of
all pipelines, metering stations, and regulating stations that are operated by a single local
distribution company.

•	For all other industry segments, use the facility definition in the General Provisions to part 98.
Under this definition, a facility is defined generally as all sources for which emission calculation
methods are provided in 40 CFR part 98 (including those in Table 1) and that are located on a
contiguous property and under common ownership or common control.

1 See 40 CFR part 98, subparts A and W for the precise definition of each of the three "facility" types.

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What Gases Must Be Reported?

Each facility must report:

•	Carbon Dioxide (C02) and methane (CH 4) emissions from equipment leaks and vented
emissions. Table 1 identifies each source type that industry segments are required to report. For
example, natural gas processing facilities must report emissions from seven specific source types,
and underground storage must report for five source types.

•	C02, CH4, and nitrous oxide (N20) emissions from gas flares by following the requirements of
subpart W.

•	C02, CH4, and N20 emissions from stationary and portable fuel combustion sources in the
onshore production industry segment following the requirements in subpart W.

•	C02, CH4, and N20 emissions from stationary combustion sources in the natural gas distribution
industry segment following the requirements in subpart W.

•	C02, CH4, and N20 emissions from all other applicable stationary combustion sources following
the requirements of 40 CFR 98 subpart C (General Stationary Fuel Combustion Sources).

Table 1. Summary of Source Types by Industry Segment

Source Type

Offshore
Production

Onshore
Production

Natural Gas
Processing

Natural Gas
Trans-mission
Compression

Under-
ground
Storage

LNG
Storage

LNG Import
and Export
Equipment

Distribution

Natural gas
pneumatic
device venting



X



X

X







Natural gas
driven

pneumatic pump
venting



X













Acid gas
removal vent



X

X











Dehydrator vent



X

X











Well venting for

liquids

unloading



X













Gas well venting
during well
completions and
workovers with
hydraulic
fracturing



X













Gas well venting

during well

completions and

workovers

without

hydraulic

fracturing



X













Blowdown vent
stacks



X

X

X





X



Onshore
production
storage tanks



X













Transmission
storage tanks







X









Well testing
venting and



X













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Source Type

Offshore
Production

Onshore
Production

Natural Gas
Processing

Natural Gas
Trans-mission
Compression

Under-
ground
Storage

LNG
Storage

LNG Import
and Export
Equipment

Distribution

flaring

















Associated gas
venting and
flaring



X













Flare stacks"



X

X











Centrifugal
compressor
venting



X

X

X

X

X

X



Reciprocating
compressor rod
packing venting



X

X

X

X

X

X



Other emissions
from equipment
leaks



X

X

X

X

X

X

X

Population
Count and
Emissions
Factor



X





X

X

X

X

Vented,
Equipment
Leaks and Flare
Emissions
Identified in
BOEMRE
GOADS Study

X















Enhanced Oil
Recovery
hydrocarbon
liquids dissolved
CO,



X













Enhanced Oil
Recovery
injection pump
blowdown



X













Onshore
Petroleum and
Natural Gas
Production and
Natural Gas
Distribution
Combustion
Emissions



X











X

How Are Greenhouse Gas Emissions Calculated?

Under this rule, facilities will detect, as applicable, and calculate GHG emissions according to the
specified quantification methods. Table 2 summarizes the calculation methodologies by source type.
Where volumetric emissions are measured, mass emissions of C02 and CH4 will be estimated based on
the annual mole fraction and density of each GHG.

• The engineering calculation methods use monitored process operating parameters and either
software models, engineering calculations, or emission factors.

2 Calculation methodologies for determining flare emissions are outlined in subpart W under applicable emissions
sources.

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•	For emissions detection, the rule allows the use of optical gas imaging instruments, organic vapor
analyzers (OVA), toxic vapor analyzers (TVA) and infrared laser beam illuminated instruments
or acoustic leak detection instruments for accessible components. For inaccessible components,
reporters must use an optical gas imaging instrument.

•	Direct measurement involves the use of the high-volume sampler; or calibrated bagging; or
rotameters, turbine meters, or other meters, as appropriate, depending on the individual
component for emissions measurement.

•	For the use of leaking factors, the relevant emission factors will be applied to leaking components
determined by using an applicable instrument and applying leaking factors. For the use of
population factors, the relevant emission factor will be applied to all components.

What Information Will be Reported?

Under the final rule, covered facilities will report the following information:

•	Annual C02, CH4, and N20 emissions reported separately for onshore and offshore petroleum and
natural gas production, onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, LNG storage, LNG import and export terminals,
and natural gas distribution.

•	Within each industry segment, C02, CH4, and N20 emissions aggregated or individually for each
source type as specified. For example, an onshore natural gas production operation with multiple
reciprocating compressors must report emissions from all reciprocating compressors as an
aggregate number.

•	Activity data as specified, either aggregated or individually for each source type.

•	Annual throughput for each facility.

•	C02, CH4, and N20 emissions reported separately for portable equipment.

•	For offshore petroleum and natural gas production facilities, the number of connected wells, and
whether they are producing oil, gas, or both.

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 rule. They are not
intended to be a substitute for the rule.

Visit EPA's web site (www.epa.gov/climatechange/emissions/ghgrulemaking.html) for more information
and additional information sheets, or go to www.regulations.gov to access the rulemaking docket EPA-
HQ-OAR-2009-0923.

Table 2. Emission Calculation Methods









Equipment







Leak Detection

Count and



Engineering

Direct

and Leaker

Population

Source Type

Estimates

Measurement

Emission Factor

Emission

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Factor

Natural gas pneumatic device venting







X

Natural gas driven pneumatic pump venting







X

Well venting for liquids unloading

X

X





Gas well venting during well completions
without hydraulic fracturing

X







Gas well venting during well completions with
hydraulic fracturing



X





Gas well venting during well workovers without
hydraulic fracturing

X







Gas well venting during well workovers with
hydraulic fracturing



X





Onshore production storage tanks

X





X

Transmission storage tanks



X





Reciprocating compressor rod packing venting



X





Well testing venting and flaring

X







Associated gas venting and flaring

X







Dehydrator vent

X





X

EOR injection pump blowdown

X







Acid gas removal vent

X

X





EOR hydrocarbon liquids dissolved C02



X





Centrifugal compressor venting



X





Other emissions from equipment leaks





2,3,4,5,6,7

ŠJŁl ,4,5,6,7

Blowdown vent stacks

X







Flare stacks

X

X





Stationary and portable combustion emissions

X

X





Above ground meters and regulators at city gate
station equipment leaks





X



Below ground meter and regulator station
equipment leaks







X

Pipeline main equipment leaks







X

Service line equipment leaks







X

Note: Applicable only to the industry segments enumerated as follows: 1. Production 2. Processing 3. Transmission
Compression 4. Underground storage 5. LNG storage 6. LNG Import and Export 7. Distribution. Sources with
multiple methods indicate options for monitoring.

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