Shootin the Breeze About GHGs to Ensure GHG Reporting Compliance
September 25, 2014

All over the media there is news about climate change and greenhouse gases (GHGs).  Many in the oil and gas industry do not work directly with GHG issues but most realize that this matter is and will continue to affect their companies.  This is a brief summary of GHGs and the oil and gas industry that can help ensure GHG reporting compliance.     

What are the GHGs of concern?

The EPA greenhouse gases (GHG) requiring reporting by industry include the following:

Greenhouse Gas
Chemical formula
Primary Emission Sources
 Annual Reporting for O&G?
Carbon dioxide
CO2
Combustion of fossil fuels
Yes
Methane
CH4
Venting of Natural Gas
Yes
Nitrous oxide
N2O
Combustion of fossil fuels
Yes
Fluorinated gases
Various
Not emitted by O&G processes
No

 

The GHG pollutants of greatest concern for O&G are CH4 and CO2.  N2O emissions, primarily from burning fuels, are not very large for oil and gas operations based on current emission factors used. 

 Ensure GHG Reporting Compliance

 EPA Mandatory GHG Reporting Regulations – 40 CFR Part 98

The EPA’s GHG reporting rules are contained in 40 CFR 98 – Mandatory Greenhouse Gas Reporting.  The rule requires reporting of greenhouse gas (GHG) emissions from all sectors of economy. The rule requires a facility that has actual emissions of 25,000 metric tons or more of CO2e per year to submit an annual report of GHG in electronic format to the EPA.  

Applicability of 40 CFR Part 98

Two subparts of the reporting rule affecting the oil and gas industry include: 

  • 40 CFR 98 Subpart C – separate requirement for stationary combustion sources (e.g., engines, heaters, etc.) affecting offshore, gas gathering, gas processing and transmission, gas storage, and LNG facilities.  The first reporting year for Subpart C was 2010.
  • 40 CFR 98 Subpart W – Petroleum and Natural Gas Industry – primarily flare/vent/fugitive sources.  For oil and gas production facilities, the rule includes stationary and portable combustion sources (e.g., engines, heaters, etc.).  The first reporting year for Subpart W was 2011. 

GHG reporting is for actual emissions, unlike air permits which are for potential to emit (PTE) emissions.

Subpart W has different reporting requirements based on the source categories listed below:  

  • Onshore petroleum & natural gas production
  • Offshore petroleum & natural gas production
  • Onshore natural gas processing plants
  • Onshore natural gas transmission
  • Underground natural gas storage
  • Liquefied natural gas (LNG) storage
  • LNG gas import & export equipment
  • Natural gas distribution

This write up focuses on onshore petroleum and natural gas production GHG reporting to EPA.

Basins and Onshore O&G GHG Reporting

For the onshore petroleum and natural gas production category, operators must calculate actual GHG emissions and aggregate all GHG emissions from affected emission sources located in a “Basin.”  The aggregated emissions from each “Basin” are considered a facility and the GHG reporting unit.  The “Basin” map used is a map by the Am. Assoc. of Pet. Geol. (AAPG) Geologic Provinces Code Map: AAPG Bulletin, Vol. 75, No. 10 (October 1991).  To review the map go to:  AAPG Basin Map Link

Note that this is a departure from state air permits that are typically required for aggregated emissions from a cleared well pad area.

Affected Equipment for Oil and Gas

Equipment required to be tracked and reported include:  

  • Natural gas pneumatic devices
  • Natural gas driven pneumatic pumps
  • Well venting for liquids unloading
  • Gas well venting - well completions
  • Gas well venting - well workovers
  • Flare stack emissions
  • Storage tanks
  • Recip. compressor rod packing
  • Well testing venting and flaring
  • Assoc. gas venting and flaring
  • Dehydrator vents
  • EOR injection pump blowdown
  • Acid gas removal vents
  • EOR hydrocarbon liquids dissolved CO2
  • Centrifugal compressor venting
  • Fugitive emissions - equipment leaks
  • Engines (drilling rigs and stationary engines), heaters, reboilers, etc. using methods in 40 CFR 98 Subpart C

Global Warming Potentials (GWP)

Each GHG is assigned a global warming potential (GWP) to account for how much heat a greenhouse gas traps in the atmosphere.  The GWPs are found in 40 CFR 98 Subpart A, Table A-1.  The GWPs are used to convert the mass amount of the specific GHG to Carbon Dioxide Equivalent (CO2e).  The GWP factors for CH4 and N2O were updated for the 2013 reporting year.   

GHG Name
Chemical formula
Global warming potential factor
Carbon dioxide
CO2
1
Methane
CH4
25
Nitrous oxide
N2O
298

For example, if a facility emits 1000 metric tons of CH4, then its CO2e would be calculated as:  (1000 metric tons CH4)(25 tons CO2e/ton CH4) = 25,000 metric tons CO2e. 

How much is 25,000 metric tons CO2e?   

25,000 metric tons CO2e is equivalent to approximately:

  • Combustion of approximately 1.3 million standard cubic feet per day (MMSCFD) of natural gas for an entire year (varies with BTU value of the natural gas burned)
  • Venting 143 thousand standard cubic feet per day (MSCFD) of methane for an entire year 

Applicability to Offshore Operations and GOADS

Offshore petroleum and natural gas production facilities are required to use the data or methods in the BOEM Gulfwide Offshore Activities Data System (GOADS) inventory to report their Subpart W flaring/venting GHG emissions.  Platform combustion sources (engines, heater, etc.) must use 40 CFR 98 Subpart C to calculate GHG emissions.  The Subpart C and W annual emissions for affected facilities are reported separately using the e-GGRT system

For BOEM regulated production platforms in the Central and Western Outer Continental Shelf (OCS) of the Gulf of Mexico must use most recent published final GOADS reporting data.  Offshore oil and gas production facilities that are not under BOEM jurisdiction (territorial seas, coastal areas), must use the calculation methods used by GOADS.  GOADS is typically on a 3-year cycle, with 2014 being a reporting year for GOM OCS facilities. 

Emission Calculations/Measurement

The calculation methods in the rule are very prescriptive and use language that specifies the required activity data, equations, simulation models and emission factors to be used. 

There is flexibility in regards to the use of direct measurement of vents for storage tanks and venting from well unloading operations and other associated venting and flaring sources.  Where allowed by EPA, operators are using direct measurement of vent gas for GHG reporting in lieu of using EPA emission factors.  Direct measurement can provide more accurate data and possibly lower emissions than the EPA GHG emission factors. 

HY-BON uses its IQR process to help operations collect and measure vent gas from your facilities.  Based on the facility, direct measurement data could be lower than the emission factors that EPA uses in the reporting rules. 

GHG Data Management

For GHG reporting there are two types of data collected for emission sources: 

  • Descriptive data that includes make, model, capacity, size, horsepower, MMBTU/hr rating, emission controls design capacity, etc. 
  • Activity data includes fuel used, throughput, volumes of natural gas vented or flared, hours operating, hours venting/flaring, etc. 

The activity data is tracked during the calendar year and used with the descriptive data and GHG prescribed calculation methods to yield the annual total CO2e emissions for each emission source and facility required to report. 

Many operators are using databases and environmental management systems to collect, manage, and archive data used for GHG reporting.  Automation of data collection is rapidly occurring.  This will lower compliance costs and reduce transcription errors that can occur when transferring data from one system to an Excel spreadsheet based system. 

Recordkeeping for GHG Reports

Extensive recordkeeping of all records used to generate GHG reports are required to be kept for at least 3 years from the date of submission of the annual GHG report for the reporting year in which the record was generated.

Annual Reporting Under 40 CFR 98

March 31 of each year is the normal due date for the required annual GHG report.  The report must be submitted in the required electronic format using the EPA’s e-GGRT system.  The report is for the previous calendar year.  New e-GGRT users must complete a one-time registration process. After establishing a user account the user can register and report for their facilities.

 If a facility’s (Basin aggregate for oil and gas production) GHG emissions are reduced to below 25,000 metric tons per year for 5 consecutive years, then the facility can submit a notification to the EPA to discontinue reporting.  If GHG emissions are below 15,000 metric tons per year for 3 consecutive years, then the facility can also submit a notification to EPA to discontinue reporting.  If the facility ceases operations or is transferred to another operator, then a notification can be sent to stop reporting for the year following cessation of operations or transfer of facility. 

Certification by Designated Representative for GHG Reports

All reports require certification by the company’s designated representative to submit the electronic report as defined in 40 CFR 98 Subpart A – General Provisions.  This is done via e-GGRT system. 

GHG Air Permitting Requirements – “Tailoring Rule”

State agencies are requiring oil and gas operations to include GHG emissions in their air permit applications to determine the applicability of the EPA’s “Tailoring Rule.”  The Tailoring Rule is different from the GHG reporting rule (40 CFR 98) because it only covers stationary emission sources at a typical “cleared area” facility – just like a facility’s air permit. 

There is no requirement to aggregate emissions from a “Basin” to determine applicability of the Tailoring Rule.  Also, the list of GHG emission sources required for air permits is shorter than those required to report under Subpart W. 

The tailoring rule requirements are given in 40 CFR 49, 51, 52, 70 and 71. 

Under the Tailoring Rule, new stationary source facilities with the potential to emit (PTE) 100,000 tons or more CO2e per year (tpy) must get an air permit for those emissions.  Existing facilities with 100,000 tpy CO2e or more and making changes that would increase GHG emissions by 75,000 tpy CO2e or more are required to obtain Prevention of Significant Deterioration (PSD) permits.  Also facilities that must obtain a PSD permit anyway (due to emissions of NOx, CO, SO2, etc), must also permit GHG emissions increases of 75,000 tpy CO2e or more.

The process for PSD permitting includes a requirement to determine the Best Available Control Technology (BACT) for the GHG emission sources. 

In addition, new and existing sources with GHG emissions above 100,000 tpy CO2e must also obtain Title V operating permits. 

The tons per year (tpy) units for the Tailoring Rule are in regular short tons (2000 pounds per ton) not metric tons. 

As an example, 100,000 tpy CO2e would be exceed for the following:

  • Venting approximately 518,400 SCF of methane per day for 1 year
  • Burning approximately 5 million SCF per day of natural gas for 1 year

 GHG Emission Controls

The reporting rule does not require oil and gas operators to control GHG emissions but the tailoring rule does require BACT for larger emitters of GHGs.  The EPA is analyzing the data from previous annual reports.  Many expect the regulation of GHG emissions, including emission controls, in the future.  

The Quad O (40 CFR 60 Subpart OOOO) rule requires emission controls for VOCs that also results in GHG emission reductions.  

Typical methods to reduce GHG and VOC emissions would be to reduce venting, flaring and fuel usage. 

Some operators elect to voluntarily reduce their flaring of natural gas and vented CH4 emissions by installing a vapor recovery unit (VRU) to collect natural gas from storage tanks and sending the gas to a sales pipeline.  

 Remember:  Reducing 1 ton of CH4 is the same as reducing 25 tons of CO2e.  

With the ever increasing alphabet soup of regulations affecting O&G operations, HY-BON can help navigate through and comply with these regulations.  Our 60 plus years of experience with vent gas management and our Identify, Quantify, Rectify (IQR) methodology can put you on the path to meeting your compliance and sustainability index.