Petroleum and Natural Gas Systems Greenhouse Gas Reporting Requirements

Posted on January 11, 2011 by Kristian Macoskey, QEP

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

Source Type Industry Segments 
(see list above)
1 2 3 4 5 6 7 8
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 flaring   X            
Associated gas venting and flaring   X            
Flare stacks   X X          
Centrifugal compressor venting   X X X X X X  
Reciprocating compressor and 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 CO2   X            
Enhanced oil recovery injection pump blowdown   X            
Onshore petroleum and natural gas production and natural gas distribution combustion emissions   X          

X

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; John Yates, 800-759-5614, jyates@cecinc.com; and Chris Dawdy, 866-250-3670, cdawdy@cecinc.com.  You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.

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U.S. Environmental Protection Agency Proposes Transport Rule To Reduce Interstate Transport of Air Pollution

Posted on August 17, 2010 by Christopher Dawdy

On July 6, 2010 the U.S. Environmental Protection Agency (EPA) proposed a rule to address interstate transport of air pollution.  This proposed rule would replace the 2005 Clean Air Interstate Rule (CAIR).  The proposed rule, known as the Transport Rule, would require 31 states and the District of Columbia to improve air quality by reducing emissions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from electric generating power plants that contribute to ozone and fine particulate pollution in other states.  SO2 and NOx react in the atmosphere to form fine particulate matter less than 2.5 micron (PM2.5).  NOx also contributes to ozone formation.  The SO2 and NOx are then transported across states, making it difficult for states downwind to comply with National Ambient Air Quality Standards (NAAQS).

This proposed rule would clarify state obligations to reduce pollution affecting other states under the Clean Air Act by defining “significant contribution” and “interfere with maintenance.” In defining these obligations, the EPA proposes to consider the magnitude of a state’s contribution, the air quality benefits of reductions, and the cost of controlling pollution from various sources.

The emission reductions are scheduled to begin in 2012, within one year after the rule is finalized.  EPA estimates that by 2014, in conjunction with other state and federal programs, that emissions of SO2 and NOx from power plants would be reduced by 71 and 52 percent, respectively from 2005 levels.  Compared to 2005, EPA estimates that by 2014 this proposal and other federal rules would lower emissions by:

  • 6.3 million tons per year of SO2
  • 1.4 million tons per year of NOX, including 300,000 tons per year of NOX during the ozone season.

The proposed rule is expected to annually cost electric utilities and consumers $2.8 billion, but is expected by EPA to yield $120 to $290 billion in annual health and welfare benefits in 2014.  EPA also estimates that between 14,000 to 36,000 premature deaths will be avoided.

The rule specifies  that twenty-eight states would be required to achieve reductions in both SO2 and NOx emissions to assist downwind states in meeting attainment with the annual and 24-hour PM2.5 standards.  Furthermore, the rule requires twenty-six states to reduce NOx emissions during the ozone season to assist downwind states in reducing ground-level ozone concentrations in order to comply with the ground-level ozone standard.  The following map identifies the states subject to the rule and the emissions to be controlled.

US map of transport rule

Proposed transport rule coverage

EPA’s approach for reducing SO2 and NOX emissions in states covered by this rule is to set a pollution limit (or budget) for each of the 31 states and the District of Columbia. This approach allows limited interstate trading among power plants but assures that each state will meet its pollution control obligations.

EPA is also taking comments on two alternative approaches. The first alternative would set a pollution limit or budget for each state. This option allows trading only among power plants within a state.  The second alternative would set a pollution limit for each state and specify the allowable emission limit for each power plant and allow some averagingof the emissions.

To assure emissions reductions, EPA is proposing Federal Implementation Plans, or FIPs, for each of the states covered by this rule. The FIPs would put in place requirements necessary to reduce pollution in the covered states that significantly contributes to nonattainment of or interferes with maintenance of the national ambient air quality standards in other states.

States may choose to develop a State Implementation Plan (SIP) to achieve the required reductions, replacing its federal plan.

In order to achieve emission reductions outlined in the Transport Rule, power plants may be required to:

  • operate already installed air pollution control equipment more frequently,
  • use low sulfur coal, or
  • install control equipment such as low NOx burners, Selective Catalytic Reduction, or Flue Gas Desulfurization.

If your facility will be affected by the Transport Rule, or if you have questions regarding the rule, please contact Chris Dawdy at 866-250-3679 or through email at cdawdy@cecinc.com

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