Final NSPS OOOOa Targets GHG and VOC Emissions from Oil & Gas Sources



On June 3, 2016, the U.S. Environmental Protection Agency (EPA) issued a final New Source Performance Standard (NSPS) Subpart OOOOa to reduce greenhouse gases (GHG) and volatile organic compounds (VOCs) from new, reconstructed, and modified sources located in the “crude oil and natural gas source category.” EPA defines this category of sources as:

  1. Crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and
  2. Natural gas production, processing, transmission, and storage, which includes the well and extends to, but does not include, the local distribution company custody station.

The final NSPS OOOOa rule builds on the 2012 NSPS OOOO requirements by setting emission limits for GHG (in the form of methane) and adding requirements for previously unaffected sources. Some major highlights of the rule include the following:

  1. Semi-annual leak detection and repair (LDAR) requirements for well sites;
  2. Quarterly LDAR requirements for boosting and gathering compressor stations and natural gas transmission compressor stations;
  3. Emission limits and control requirements for pneumatic pumps at natural gas well sites, oil well sites, and natural gas processing plants;
  4. Reduced emission completions (i.e., green completions) at hydraulically fractured well sites with a gas-to-oil ratio (GOR) greater than or equal to 300 standard cubic feet (scf) of gas per barrel;
  5. Centrifugal and reciprocating compressors subject to requirements at natural gas transmission compressor stations;
  6. Addition of emission limits for pneumatic controllers in the natural gas transmission segment; and
  7. Professional engineer (P.E.) certification requirements for technical infeasibility determinations for controlling pneumatic pumps and for verification of proper closed vent system (CVS) design.

The final NSPS OOOOa regulation included the following changes from the initially proposed version:

  • Setting a fixed schedule (e.g., quarterly or semiannually) for leak monitoring rather than a variable schedule based on performance;
  • Allowing the use of Method 21 to identify leaks as an alternate option to optical gas imaging;
  • Removing pneumatic pump control requirements for natural gas boosting and transmission compressor stations;
  • Encouraging owners/operators to use new technologies to monitor and find leaks by allowing alternative methods of compliance; and
  • Phasing in the requirements to use a “green completion” process to capture emissions from hydraulically fractured oil wells, allowing a six-month timeframe for compliance.

A high-level summary of the requirements of NSPS OOOO and OOOOa (highlighted in red) is provided in the table on the adjacent page.

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Real-World Implications: Complying With the New LDAR Requirements

Well sites and compressor stations that are new, modified, or reconstructed well sites after September 18, 2015 must conduct LDAR surveys. Well sites must perform surveys semi-annually, and compressor stations must survey quarterly. Operators can use optical gas imaging (OGI) or Method 21 to conduct the required surveys.EQ_Spring_2016_NSPS OOOOa_table1 Companies have 12 months from June 3, 2016, to develop the required LDAR Monitoring Plans (which must include extensive details on the monitoring program and approach) and to perform the first required survey.

While the compliance requirements found in NSPS OOOOa can be largely straightforward, the recordkeeping requirements are extensive. The race is on to develop LDAR monitoring plans for “company-defined areas.” While that term is not defined, EPA has stated that it expects these “company-defined areas” will include similar sites located in a geographically similar area. The LDAR Monitoring Plan must include the following:

  • LDAR method (optical gas imaging [OGI] or Method 21);
  • Frequency of surveys;
  • Details of the equipment used to detect leaks (if using OGI, verification that the OGI camera meets the specifications detailed in the rule);
  • Procedures and timeframes for identifying and repairing components, including those that are unsafe to repair;
  • Specific procedures for conducting surveys including ensuring adequate thermal background, adverse monitoring condition procedures, training and experience of the operator conducting surveys, and equipment calibration procedures;
  • Site maps with defined observation path; and
  • Additional information required by Method 21, if applicable.

While EPA is allowing operators to develop plans for “company-defined areas,” many operators may find that sites within similar geographic regions are still highly variable, which can add to the burden of developing LDAR Monitoring Plans. EPA does not require operators to submit the LDAR Monitoring Plan initially, but it must be submitted upon request.

 

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Building a Strong Foundation for the LDAR Program

It is worth the effort to spend time up-front to clearly document LDAR survey procedures, equipment to be surveyed (and detailed lists of equipment not to be surveyed), qualification requirements of surveyors, and other procedures. A proper LDAR plan can assist in avoiding unnecessary repairs and deviations associated with inadequate monitoring and/or recordkeeping. EPA has indicated its intent to migrate NSPS OOOOa reporting to electronic reporting. This will increase the transparency of reported emissions (and subsequent deviations), making the information potentially available to the public and other interested parties. As the information will likely be more publicly accessible, shoring up programs to reduce the number of deviations will be critical.

 

P.E. Certifications

EPA is now requiring P.E. certifications for several elements in the rule, including any CVS used to control emissions from new or modified storage vessels, pneumatic pumps, and centrifugal or reciprocating compressors. EPA’s main concern is ensuring the CVS is appropriately designed to handle the volume and composition of gas controlled through the CVS. EPA is also requiring P.E. certifications for any claim that emissions control for a non-greenfield site equipped with a pneumatic pump affected source is “infeasible.” Exactly which CVS will require P.E. certifications depends on how each state treats CVS on non-NSPS OOOOa affected tanks; it will be important to look at this closely for each state in which you operate.

 

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Natural Gas Diaphragm Pneumatic Pumps

The rule now requires operators to reduce emissions from many natural gas driven diaphragm pneumatic pumps located at well sites and gas processing plants. For gas processing facilities, pneumatic pumps must be air actuated, which is already required for pneumatic devices under NSPS OOOO. Pneumatic pumps at well sites must achieve a 95% reduction in emissions, with some exceptions. For new (i.e., greenfield) well sites, operators will need to consider ways to route emissions from natural gas driven pneumatic diaphragm pumps to a control device located on-site (even if the device cannot meet the required 95% reduction) or otherwise route the emissions into the process.

 

For non-greenfield sites with new or modified natural gas diaphragm pumps, emissions must be routed to a control device if one is on site. If the site is not equipped with a control device, the operator must submit a certification as part of the annual report identifying that there is a potentially affected pneumatic pump on-site, but no control device is in place. Alternatively, an operator may make the determination that routing the emissions to the existing control device is not feasible; in this case, a P.E. certification must be submitted as part of the annual report identifying the option as “infeasible.”

 

Reciprocating and Wet Seal Centrifugal Compressors at Transmission Compressor Stations

The compliance requirements for reciprocating and wet seal centrifugal compressors found in NSPS OOOOa are largely the same as those found in OOOO; however, OOOOa expands applicability to compressors in the natural gas transmission segment. Wet seal centrifugal compressors must reduce emissions by 95% from the wet seal oil degassing system; reciprocating compressors must either collect rod packing emissions or track rod packing replacements. From a practical perspective, this change will subject many more wet seal centrifugal compressors to regulation than were previously regulated under NSPS OOOO. The nuances surrounding modification or reconstruction of a wet seal centrifugal compressor have been largely untested under NSPS OOOO, and these determinations will become much more common under NSPS OOOOa.

 

Preparing for Compliance under NSPS OOOOa

The timeframe to develop compliance tools for NSPS OOOOa is compressed. Many operators now subject to LDAR requirements may never have had to implement a LDAR program in the past and have less than one year to respond. Regulations applying to equipment under NSPS OOOO have been expanded into the natural gas transmission segment, including equipment such as reciprocating compressors, centrifugal compressors with wet seals, and continuous bleed pneumatic controllers. Similarly, requirements that have been in place for hydraulically fractured natural gas wells have been expanded to a much wider universe of wells. While many of the compliance requirements are the same for equipment already covered in NSPS OOOO, NSPS OOOOa has expanded the equipment subject to regulation, and the recordkeeping and reporting requirements are extensive. Up front planning, including LDAR program development and applicability analyses, can be particularly valuable and it is never too early to start.