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:
- Offshore petroleum and natural gas production;
- Onshore petroleum and natural gas production;
- Natural gas processing plants;
- Natural gas transmission compression;
- Underground natural gas storage;
- Liquefied natural gas (LNG) storage;
- LNG import and export equipment; and
- 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)
|Natural gas pneumatic device venting||X||X||X|
|Natural gas driven pneumatic pump venting||
|Acid gas removal 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|
|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||
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, firstname.lastname@example.org; John Yates, 800-759-5614, email@example.com; and Chris Dawdy, 866-250-3670, firstname.lastname@example.org. You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.
If you are following the new 40 CFR 98 Mandatory Greenhouse Gas Reporting Rule (GHG Rule) you will know that facilities were to have started collecting reporting data on January 1, 2010. You may be studying the requirements specific to your facility or industry group, but be sure to also take a careful look at Subpart A – General Provisions. Subpart A contains provisions that are applicable to all facilities subject to the GHG Rule requirements. A thorough understanding of Subpart A is a necessary prerequisite to complying with this new regulation. Key elements include:
- Who must report;
- When you can stop reporting;
- How and when reports must be submitted;
- What the annual report must contain;
- Special provisions that have been made for 2010 reporting;
- Recordkeeping requirements;
- Calibration requirements; and
- Definitions as well as tables of greenhouse gases (GHGs) and their global warming potentials.
The who, how, and when of reporting were addressed in our December 23, 2009 posting, but it is important to note that reporting is required on a facility-specific basis. A facility, as defined in Subpart A, can be limited to a single stationary piece of equipment that emits a GHG.
The criteria for determining when reporting can cease is a function of whether or not the facility continues to emit GHGs and at what levels. Continuous annual reporting is required unless:
- The facility has five consecutive years of emissions below 25,000 metric tons (mt);
- Three consecutive years of emissions below 15,000 mt; or
- All GHG-emitting processes and operations subject to the rule cease to operate (although this provision does not apply to MSW landfills).
At least 60 days prior to submitting the first annual report, an electronic certificate of representation must be submitted to EPA. EPA expects each facility to have only one designated representative who will be responsible for certifying, signing, and submitting GHG reports. The contents of the annual report will include:
- Facility name or supplier name and address;
- The period of time covered by the report;
- The date of the report;
- For facilities – annual emissions of GHG as follows:
- aggregate annual emissions (excluding biogenic CO2) for all GHG from all applicable source categories and expressed as carbon dioxide equivalents (CO2e);
- aggregate annual emissions of biogenic CO2e;
- individual GHG totals for each applicable source category; and
- other data as specified in the respective subparts.
- For suppliers – annual quantities of GHG that would be emitted from combustion or use of the supplied products during the year, as follows:
- aggregate annual emissions for all GHG from all applicable supply categories expressed as CO2e;
- individual GHG totals for each applicable supply category; and
- other data as specified in the respective subparts.
One special provision for the 2010 report is the allowance for best available monitoring methods. EPA expects GHG emissions to be estimated according to the specified methods. However, due to the limited notice provided prior to the effective date, if it was not reasonably feasible to acquire, install, and operate required monitoring equipment by January 1, 2010, then best available monitoring methods may be used until March 31, 2010. Best available methods may include:
- Monitoring methods currently used by the facility that do not meet the specification of the relevant subpart;
- Supplier data;
- Engineering calculations; and
- Other company records.
Extensions for continued use of best available monitoring methods beyond April 1, 2010 may be requested, but such requests need to be submitted by January 28, 2010.
Another special provision for the 2010 report applies to facilities where the only sources of CO2e are general stationary fuel combustion. For such facilities, a simplified report will be accepted. It would include the aggregate facility-wide GHG emissions and associated process information as well as general facility information and certification.
Records must be maintained for three years in either electronic or hard-copy format. Specific records that must be retained include:
- A list of all units, operations, processes, and activities for which GHG emissions were calculated;
- The data used to calculate GHG emissions including:
- emission calculations,
- analytical results for the development of site-specific emission factors,
- results of all required analyses (e.g., high heat value and carbon content), and
- any facility operating data or process information used in GHG calculations,
- Annual GHG reports;
- Missing data documentation;
- A written GHG Monitoring Plan;
- The results of all required certification and quality assurance (QA) tests of continuous monitoring systems, flow meters, and other instrumentation; and
- Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation.
The written GHG Monitoring Plan needs to identify who is responsible for collecting the data, what processes and methods are used to collect the data, and what procedures and methods are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other relevant instrumentation.
Relative to QA, EPA expects facilities to calibrate their flow meters and other measurement devices prior to April 1, 2010. Fuel billing meters are exempted from the requirement, but unless a device cannot be removed because of continuous operation, calibration in accordance with manufacturer recommendations is required. If a postponement in calibration is needed due to continuous operations, it must be documented in the GHG Monitoring Plan.
Other important elements of Subpart A include definitions that are applicable to the remaining subparts as well as Table A-1 that lists all 70 GHGs and their respective assigned global warming potentials.
CEC recommends that facilities develop a thorough GHG Monitoring Plan to document both the applicability determination as well as procedures that will be used to collect the required data, meet the QA requirements, and estimate emissions. In our next posting we will take an in-depth look at Subpart C – General Stationary Fuel Combustion Sources.
If you have any questions regarding the requirements of Subpart A or other portions of the GHG Rule, please contact one of CEC’s GHG experts, Kris Macoskey, Chris Dawdy, or John Yates. Their contact information can be found on the CEC Experts page.
The U.S. EPA promulgated the Mandatory Greenhouse Gas Reporting Rule (GHG Rule) on October 30, 2009. Sections applicable to Municipal Solid Waste (MSW) Landfills include various provisions of the general requirements (Subparts A, B and C) as well as Subpart HH which sets forth MSW Landfill compliance obligations. The Rule becomes effective December 29, 2009 with key provisions of the GHG Rule, including obligations regarding data collection, beginning on January 1, 2010.
In general, the portions of the GHG Rule applicable to MSW landfills appears to have been crafted following the protocol for GHG accounting established by various international organizations including the United Nations Framework Convention on Climate Change (UNFCCC). Several calculation methodologies and “verification” procedures included in the GHG Rule mimic those established by the UNFCCC and the associated Intergovernmental Panel on Climate Change (IPCC). As a result, the GHG Rule is not well coordinated with existing Clean Air Act (CAA) standards already applicable to MSW landfills.
Although a convincing argument can be made that all of the data required by the GHG Rule could easily be gathered under existing CAA regulations within a reasonable degree of accuracy and repeatability and with no additional cost for affected landfill facilities, that approach is not acceptable under the GHG Rule. In general, most MSW landfills currently fall short of minimum GHG Rule requirements for both landfill gas metering and sampling frequency. CEC has developed an alternative strategic GHG compliance strategy to reduce the cost of complying with the GHG Rule.
In summary, two specific standards – 98.343(b)(1) and 98.343(b)(2) – are set forth in the GHG Rule for measurement of landfill gas volume and methane content. For the purposes of this discussion, each standard is referred to by its paragraph designation, namely b(1) and b(2):
- Standard b(1) represents the most rigorous and costly compliance option, requiring considerable and costly upgrades in existing flow and methane measurement equipment for most MSW landfill facilities. For compliance with standard b(1) “spec” metering equipment must conform to 40 CFR §98.344 and includes use of gas chromatographs for methane content determination and differential pressure meters for flow determination (various alternates/options are also available although costs are comparable). Implementation of this standard would require upgrade of both flow and methane content measurement devices for most MSW Landfill facilities at an estimated cost of approximately $50,000 per facility.
- Standard b(2) in comparison is less rigorous with respect to equipment specifications and costs, but potentially more labor intensive, requiring weekly monitoring of various gas flow and methane content parameters. However, at least a portion of existing “non-spec” gas monitoring equipment (flow meters) can be utilized at most facilities. This will result in lesser initial capital costs for equipment but may result in increased long-term costs (e.g., labor) if weekly manual monitoring is utilized. However, if b(2) level monitoring is coupled with remote data collection, savings of long-term labor costs will be realized. Based on the most cost efficient strategy evaluated by CEC under this standard, implementation costs are estimated at $25,000 per facility.
CEC notes that landfills already equipped with flow and methane monitoring equipment meeting the “b(1)” or §98.344 specifications are obligated to use this equipment for data GHG emission calculations. Section III.HH of the GHG Rule preamble as well as paragraphs b(1) and b(2) which set forth these requirements are listed as follows:
Preamble Section III.HH. “We do require landfill gas collection systems already equipped with continuous monitoring systems to determine daily average flow and concentrations and to use these data in their gas recovery calculations. For collection systems that do not have continuous gas monitors, weekly sampling is required. Weekly monitoring provides an adequate number of samples to evaluate the variability and uncertainty associated with methane generation.”
§98.343 (b)(1). “…If you continuously monitor the flow rate, CH4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) using a monitoring meter specifically for CH4 gas, as specified in § 98.344, you must use this monitoring system and calculate the quantity of CH4 recovered for destruction using Equation HH–4 of this section. A fully integrated system that directly reports CH4 content requires no other calculation than summing the results of all monitoring periods for a given year.”.”
§98.343 (b)(2). “If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) at least weekly according to the requirements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section…”
CEC would be pleased to provide a compliance summary for your facility. Items to be evaluated include:
- Does your landfill generate more than 25,000 metric tons of CO2e?
- Are you prepared to collect the required data from your landfill?
- Have you cataloged all of your stationary sources of combustion?
Please call Ralph Hirshberg at CEC Greenhouse Gas Help Line 1-888-364-2324 or Email your questions to LFGHG.Help@CECinc.com.
2010 Greenhouse Gas Reporting Required
EPA’s December 7, 2009 announcement that CO2 is a “threat” to public health and the environment has brought additional focus to the ongoing legislative debate regarding climate change and the final Mandatory Greenhouse Gas Reporting rule (40 CFR 98). This rule was signed on September 22, 2009, published on October 30, 2009, and is effective December 29, 2009.
The rule covers approximately 85 percent of the nation’s greenhouse gas (GHG) emissions and will apply to roughly 10,000 facilities. EPA will develop an electronic reporting system for calendar year 2010. Reports for 2010 are due on March 31, 2011.
This rule requires facilities to calculate CO2 emissions or install monitoring systems where valid emission estimating methods are not currently available. This rule applies to:
- Operations that are one of 17 source categories (adipic acid production, aluminum production, ammonia manufacturing, cement production, electricity generation, HCFC-22 production, HFC-23 destruction processes, lime manufacturing, manure management systems, municipal solid waste landfills, nitric acid production, petrochemical production, petroleum refineries, phosphoric acid production, silicon carbide production, soda ash production, titanium dioxide production) unless excluded by specific caveats;
- Operations in one of seven source categories (ferroalloy production, glass production, hydrogen production, iron and steel production, lead production, pulp and paper manufacturing, zinc production) if the facility emits more than 25,000 metric tons (mt) of carbon dioxide equivalents (CO2e);
- Facilities with annual CO2e emissions from stationary fuel combustion sources (i.e., boilers, stationary internal combustion engines, process heaters, combustion turbines, and other stationary fuel combustion equipment with certain exclusions) that exceed 25,000 mt; and
- Suppliers of coal-based liquid fuels, natural gas and natural gas liquids, petroleum products, and industrial GHGs (fluorinated gases, nitrous oxide, and carbon dioxide).
To determine whether your facility is subject to the rule, you may wish to use EPA’s applicability tool.
Reporting of indirect electricity use is not required because the electricity generators will report those emissions. Portable equipment, emergency generators, emergency equipment, flares, and hazardous waste combustors (except those co-fired with fossil fuel) are exempt.
On January 1, 2010, monitoring or use of best available monitoring methods to calculate CO2e emissions must begin. EPA expects that most facilities will begin to comply with monitoring requirements by April 1, 2010, although extensions for continued use of best available monitoring beyond that date will be considered. Requests for extensions need to be submitted no later than January 28, 2010.
EPA’s stated purpose for this reporting is to collect accurate and timely data on GHG emissions data that can be used to inform future policy decisions. Expectations are that the information will be used to help establish emission baselines which will in turn impact future emission allowances, emission offsets, and carbon trading. The emissions data reported to EPA will be available to the public allowing for the identification of significant GHG emission sources.
If you are unclear about how this rule affects your facility, please contact one of CEC’s GHG experts:
Kris Macoskey (Pittsburgh), 800-365-2324, email@example.com
John Yates (Chicago), 877-963-6026, firstname.lastname@example.org
Chris Dawdy (St. Louis), 866-250-3670, email@example.com
You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.