Petroleum and Natural Gas Systems Greenhouse Gas Reporting Requirements

U.S. EPA continues to roll out new subparts and revisions to the Greenhouse Gas (GHG) Reporting Rule (40 CFR 98).  This time we take a look at Subpart W – Petroleum and Natural Gas Systems which was published in the November 30, 2010 Federal Register.  GHG emissions from this industry are generated by combustion (e.g., heaters, engines, furnaces, etc.), fugitive equipment leaks, and process vents.

As with the other 40 CFR 98 subparts, facilities that emit 25,000 metric tons (mt) or more of carbon dioxide equivalents (CO₂e) per year must report.  However, the definition of a facility is slightly more complicated here than for other subparts.

First, there are eight segments of the petroleum and natural gas industry that need to be considered.  Each industry segment is defined in the rule (see §98.230) and more detailed descriptions can be found in the 144-page Background Technical Support Document.  The eight industry segments are:

1. Offshore petroleum and natural gas production;
2. Onshore petroleum and natural gas production;
3. Natural gas processing plants;
4. Natural gas transmission compression;
5. Underground natural gas storage;
6. Liquefied natural gas (LNG) storage;
7. LNG import and export equipment; and
8. Natural gas distribution.

The next step in defining a facility under Subpart W is to consider the 21 categories of emission sources that have been identified within the eight industry segments.  For example, the onshore petroleum and natural gas production facility (Segment 2) includes 19 different types of emission sources that need to be inventoried to determine if the annual 25,000 mt CO₂e applicability threshold is exceeded (e.g., dehydrator vents, flare stacks, and well testing vents).

For six of the industry segments, the facility definition stops there.  One simply accounts for all of the sources located on contiguous property or under common ownership/control and for which calculation approaches have been provided in the rule.  Two of the industry segments require one more step to define the facility.

For the Onshore Petroleum and Natural Gas Production industry segment, the rule defines a facility as all of the equipment on or associated with a well pad that is under common control or ownership and that is located within a single hydrocarbon basin, as defined by the American Association of Petroleum Geologists Geologic Provinces Code Map.  (This 1991 publication is not provided by EPA but can be obtained from AAPG here.   As one might imagine, geologic provinces cover large areas (e.g., most of Pennsylvania as well as parts of New York, West Virginia, and five other southern states is covered by Code 160A – Appalachian Basin Eastern Overthrust Area).   This means that operations at multiple well pad locations will have to be aggregated for applicability determinations and reporting purposes.

The facility definition for the Natural Gas Distribution industry segment is not based on geography.  Instead, EPA has simply included “all distribution pipelines, metering stations, and regulating stations” that physically deliver natural gas to end users as operated by a single local distribution company (LDC).  The caveat relative to an LDC is that it is regulated as a separate operating company by a public utility commission or it is operated as an independent municipally-owned distribution system.

The eight industry segments and the associated 21 categories of emission sources for which GHG calculation procedures have been developed are summarized in the following table.

Summary of Source Types by Industry Segment

EPA has developed extensive checklists that describe in detail what needs to be monitored at the seven onshore industry segments.  For example, Natural Gas Distribution facilities (Segment 8 ) need to account for the total number of leaking control valves and the operating time of leaking orifice meters, among many other things.  Emission calculation methods specified in the rule include engineering estimates, direct measurement, leak detection emission factors, and equipment counts with population emission factors.

The rule requires affected facilities to develop Monitoring Plans in accordance with the General Provisions by April 1, 2011.  Best available monitoring methods (BAMM) will be allowed for certain data gathering requirements for periods up through December 31, 2011.  Requests to use BAMM for extended periods must be submitted to EPA in accordance with the timing requirements specified in the rule (either April 30 or September 30, 2011).

CEC recommends that facilities carefully review the regulation, the EPA guidance, the applicability tools, and the emission estimation tools available at EPA’s site on their Greenhouse Gas Reporting Program page.  If you are unclear about how this rule affects your facility, please contact one of CEC’s GHG experts: Kris Macoskey, 800-365-2324, kmacoskey@cecinc.com.  You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.