Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems



The U.S. EPA is finalizing revisions and confidentiality determinations for the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Rule (GHGRP). These revisions include:

  • The addition of calculations methods and reporting requirements for GHG emissions from gathering and boosting facilities
  • Completions and workovers of oil wells with hydraulic fracturing
  • Blowdowns of natural gas transmission pipelines between compressor stations
  • The addition of well identification reporting requirements to improve the EPA’s ability to verify reported data
  • Finalizes confidentiality determinations for new data elements contained in these amendments.

This final rule is effective on January 1, 2016. It adds calculation methods, monitoring, and data reporting requirements and finalizes confidentiality determinations for the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Rule (GHGRP). These additions and revisions further EPA’s goal to improve completeness, quality, accuracy, and transparency of data from this sector, and improve the ability of agencies and the public to use these GHG data to analyze emissions and understand emission trends. Entities affected by this final rule are owners and operators of petroleum and natural gas systems that directly emit GHGs, including Crude petroleum and natural gas extraction (NAICS: 211111), Natural gas liquid extraction (NAICS: 211112), Natural gas distribution (NAICS: 221210), and Pipeline transportation of natural gas (NAICS: 486210).

Action Items Starting in 2016

Beginning January 1, 2016, operators should begin collecting data needed to calculate emissions occurring during 2016. The first annual reports of emissions calculated using the amended requirements will be those submitted by March 31, 2017, covering reporting year 2016. For reporting year 2015, operators will continue to calculate emissions and other relevant data according to the requirements in Part 98. EPA is allowing the use of best available monitoring methods (BAMM) on a short-term transitional basis for facilities new to reporting under Subpart W as well as reporters of facilities new to monitoring requirements associated with these revisions through 2016. The use of BAMM is not allowed for the reporting of well identification numbers. There are no provisions for extensions for the use of BAMM beyond the stated time period.

GHG Monitoring Plans for Subpart W reporters were due on April 1, 2011. While there is no date codified for reporters who become subject to Subpart W after that date, the common assumption is that monitoring plans are due by April 1 of the year in which monitoring is taking place.

Summary of Final Revisions and Other Amendments to Subpart W and Responses to Public Comment

In this action, EPA is amending subpart W to require:

  1. The reporting of GHG emissions from completions and workovers of oil wells with hydraulic fracturing as part of the existing Onshore Petroleum and Natural Gas Production industry segment
  2. The adding of requirements to the Onshore Petroleum and Natural Gas gathering and boosting systems
  3. The adding of requirements to the Onshore Natural Gas Transmission Pipeline segment for transmission pipeline blowdowns between compressor stations
  4. The reporting of well identification numbers for oil and gas well-specific information reported in the Onshore Petroleum and Natural Gas Production segment
  5. The addition of BAMM through 2016 for some sources

 

In addition to these amendments, EPA is “assessing the potential opportunities for applying remote sensing technologies and other innovations in measurement or monitoring technology to identifying and calculating emissions from affected sources under subpart W.”

Summary of Final Amendments for Oil Wells with Hydraulic Fracturing
The new requirements under Subpart W extend the current requirements for gas well completions and workovers to oil wells. The final amendments require the use of either Equation W-10A or W-10B for calculating GHG emissions from completions and workovers of oil wells with hydraulic fracturing. Equation W-10A is used to calculate emissions from wells using inputs obtained from a representative sample of wells within a sub-basin and the ratio of the gas flowback rate to the production flow rate. Equation W-10B is used to calculate emissions using inputs obtained from all wells within a sub-basin and the flow rate and flow volume of the gas vented or flared. EPA is finalizing that emissions be calculated and reported separately for gas wells and oil wells by sub-basin and well type combination. The final amendments require the use of Calculation Method 1 for calculating inputs to Equation W-12A and W-12B for oil wells.

For oil wells that do not meter gas production, such as some wells with a relatively low gas to oil ratio (GOR), EPA is proposing a new Equation W-12C to calculate, rather than measure, the value of PRs, p (the average gas production flow rate during the first 30 days of production after the completion or workover), which is used as an input to Equation W-10A. In this Equation W-12C, the value of PRs, p is calculated by multiplying the GOR of the well by the measured oil production rate over the first 30 days of production after the completion or workover.

The final monitoring and reporting requirements do not apply to completions and workovers of oil wells with hydraulic fracturing that have a GOR of less than 300 standard cubic feet per stock tank barrel (scf/STB).

Summary of Final Amendments for the Onshore Petroleum and Natural Gas Gathering and Boosting Segment
EPA is finalizing the definition of the Onshore Petroleum and Natural Gas Gathering and Boosting segment in 40 CFR 98.230 as gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the petroleum and/ or natural gas to a natural gas processing facility, a natural gas transmission pipeline, or a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to, gathering pipelines, separators, compressors, acid gas removal (AGR) units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. The Onshore Petroleum and Natural Gas Gathering and Boosting segment does not include equipment and pipelines that are reported under any other industry segment defined in Subpart W. The segment definition excludes:

  1. Gathering pipelines operating on a vacuum, because they would not be expected to have emissions
  2. Gathering pipelines with a GOR less than 300 scf/STB (where “oil” is defined as hydrocarbon liquid of any gravity)

 

BAMM usage is permitted for the boosting and gathering industry segment for 2016 without a need for EPA approval.

The EPA has finalized the definitions of a number of important terms:

  • Gathering and boosting systems: single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more connection points to gas and oil production and a downstream endpoint, typically a gas processing plant, transmission pipeline, local distribution company (LDC) pipeline, or other gathering and boosting system
  • Gathering and boosting system owner or operator: any person that holds a contract in which they agree to transport petroleum or natural gas from one or more onshore petroleum and natural gas production wells to a natural gas processing facility, another gathering and boosting system, a natural gas transmission pipeline, or a distribution pipeline or is responsible for custody of the petroleum or natural gas transported. In complex ownership scenarios, the owner/operator assigns a designated representative responsible for reporting consistent with 40 CFR 98.4
  • Facility with respect to onshore petroleum and natural gas gathering and boosting: all gathering pipelines and other equipment located along those pipelines that are under common ownership or common control by a gathering and boosting system owner or operator and that are located in a single hydrocarbon basin as defined in 40 CFR 98.238 where a person owns or operates more than one gathering and boosting system in a basin, then all gathering and boosting systems and equipment that the person owns or operates in the basin are considered one facility. Any gathering and boosting equipment that is associated with a single gathering and boosting system, including leased, rented, or contracted activities is considered to be under common control of the owner or operator of the gathering and boosting system. Emissions from an onshore petroleum and natural gas gathering and boosting facility only need to be reported if the collection of emissions sources emits 25,000 metric tons CO2e or more per year.

Boosting and Gathering reporters must calculate emissions from the following equipment, and aggregate the emissions across the hydrocarbon basin to determine if reporting is required. All emission sources are currently existing in other portions of Subpart W.

  1. Blowdowns - blowdown emissions will be calculated using the same methods that are used for other segments subject to reporting blowdown emissions. The same exemptions, including those for volumes less than 50 cubic feet and for desiccant dehydrator reloading, apply to the Onshore Petroleum and Natural Gas Gathering and Boosting segment.
  2. Storage Tank Vented Emissions - Calculating emissions for atmospheric storage tanks located in the Onshore Petroleum and Natural Gas Gathering and Boosting segment will be performed as is currently codified for other segments subject to reporting emissions from storage tanks. Additional guidance has been added for storage tanks that receive product from non-separator and non-wellhead sources. Use of software that uses the Peng-Robinson equation of state will meet the necessary requirements.
  3. Gathering Pipelines - For gathering lines, reporters will use the population count (miles of gathering pipeline, similar to the approach used for calculating emissions from natural gas distribution pipelines in the Natural Gas Distribution segment) and emission factor (in Table W-1A for gathering pipelines are whole gas emission factors based on the U.S. GHG Inventory) approach in 40 CFR 98.233 (r). Gathering pipeline is to be assessed in four different material type categories: protected steel, unprotected steel, plastic/composite, and cast iron. Gathering pipelines with a GOR less than 300 scf/STB are not included in this segment.
  4. Reciprocating Compressors, Centrifugal Compressors, Pneumatic Devices, Pneumatic Pumps, and Equipment Leaks - The methods for calculating these emissions are the same as the methods for these sources in both the Onshore Petroleum and Natural Gas Production segment. A reporter will need to establish an inventory of the applicable equipment, apply the emission factors, and then update the inventory each year to account for new or retired components or equipment.
  5. Acid Gas Removal Units, Dehydrators - The calculation methods for these units will remain as currently required for the natural gas processing segment.
  6. Flares - Flares will be calculated as found in the natural gas processing or production segments.
  7. Combustion Equipment - As is found in the production segment, gas gathering and boosting operators must calculate emissions from stationary or portable fuel combustion equipment that cannot move on roadways under its own power and drive train. Stationary or portable equipment includes the following equipment, which are integral to the movement of natural gas: natural gas dehydrators, natural gas compressors, electrical generators, steam boilers, and process heaters. The calculation methodologies are consistent with what is used under Subpart C for stationary combustion, however, the emissions are expected to be reported under W (rather than C, as is the case for gas processing facilities).

 

Summary of Final Amendments for the Onshore Natural Gas Transmission Pipeline Segment
EPA has created a new segment, the Onshore Natural Gas Transmission Pipeline segment. This segment must report blowdowns of a pipeline or section of pipeline.

For interstate pipelines, the onshore natural gas transmission pipeline owner or operator is defined as: …The person identified as the transmission pipeline owner or operator on the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717f. For intrastate pipelines, the onshore natural gas transmission pipeline owner or operator is the person identified as the owner or operator on the transmission pipeline’s Statement of Operating Conditions under section 311 of the Natural Gas Policy Act (NGPA). If the intrastate pipeline is not subject to section 311 of the NGPA, the onshore natural gas transmission pipeline owner and operator on reports to the state regulatory body regulating rates and charges for the sale of natural gas to consumers. The owner or operator of a pipeline that falls under the “Hinshaw Exemption” is the person identified as the owner or operator on blanket certificates issued under 18 CFR 284.224.

The finalized definition of “facility” for this segment is the total U.S. mileage of natural gas transmission pipelines owned or operated by an onshore natural gas transmission pipeline owner or operator. If an owner or operator has multiple pipelines in the United States, the facility is considered the aggregate of those pipelines, even if they are not interconnected.

Calculating Emissions
Reporters will use the existing methods found in 40 CFR 98.233 (i) to calculate or measure emissions from pipeline blowdowns events. Method One allows a reporter to calculate emissions based on the volume of the pipeline segment between isolation valves that is blown down and the pressure and temperature of the gas within the pipeline. The second method allows the reporter to measure the emissions from the blowdown using a flow meter on the blowdown vent stack. In both methods, the reporter calculates both methane and carbon dioxide emissions from the volume of natural gas vented using either default gas composition or engineering estimates of composition provided within the rule.

Instead of proposing requirements to report the emissions and location of each blowdown event, the EPA is requiring that Onshore Natural Gas Transmission Pipeline reporters report the total methane and carbon dioxide emissions in each state, the number of blowdowns in each states, and the miles of pipeline in each state.

Summary of Final Amendments for Well Identification Numbers
EPA is finalizing some proposed amendments to add reporting requirements for well identification numbers to improve data quality by enabling identification of wells. The well ID numbers will be reported for the first time in the report covering 2016 emissions; reporters will not be required to report well ID numbers for previous years. For most of the wells, the well ID number reported will be the US Well number (formerly the API well Number). For any well that doesn’t already have a US Well number, the reporter will be required to provide the unique well number assigned by the permitting authority for drilling of oil and gas wells. The EPA is requiring the reporting of well ID numbers for the Onshore Petroleum and Natural Gas Production segment only for information related to wells. For reporters in the Onshore Petroleum and Natural Gas Production segment that report emissions using input data that are calculated from measurements at individual wells or equipment associated with individual wells, the report must include the well ID number for which those measurements were made and the well ID numbers of other wells to which the measurements will be applied. EPA is finalizing change to update references to the “API well number” in subpart W to “well identification number.” Reporters will still need to report well ID numbers for liquids unloading and for any exploratory wells for which reporting has been delayed for 2 years.

Confidentiality Determinations

EPA is finalizing the decision to require each of the new data elements to be designated as “not Confidential Business Information (CBI).” EPA is providing reporters with the option to delay reporting of five data elements as proposed and additional data elements for two reporting years in situations where exploratory wells are the only wells in a sub-basin. For a given sub-basin, in situations where wildcat wells and/ or delineation wells are the only wells in a sub-basin that can be used for the required measurement, the following seven data elements associated with the delineation or wildcat well may be delayed for two reporting years:

  1. The cumulative gas flowback time, in hours, for each sub-basin, from when gas is first detected until sufficient quantities are present to allow separation>
  2. The cumulative flowback time, in hours, for each sub-basin, after sufficient quantities of gas are present to enable separation
  3. The measured flowback rate, in standard cubic feet per hour, for each sub-basin
  4. The gas to oil ratio for the well
  5. The volume of oil produced during the first 30 days of production after completions of each newly drilled well or well workovers using hydraulic fracturing
  6. The total annual gas-liquid separator oil volume that is sent to applicable onshore storage tanks, in barrels
  7. The total annual oil throughput that is sent to all atmospheric tanks, in barrels

 

The finalized rule can be found here: http://www2.epa.gov/sites/production/files/2015-10/documents/2015-revisions-and-confidentiality-determinations-for-petroleum-and-natural-gas-systems-pre.pdf