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. 40 CFR 98, subpart W November 2010 1 ------- 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 40 CFR 98, subpart W November 2010 2 ------- 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. 40 CFR 98, subpart W November 2010 3 ------- 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 40 CFR 98, subpart W November 2010 4 ------- 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. 40 CFR 98, subpart W November 2010 5 ------- |