On April 17, 2012, The US Environmental Protection Agency (EPA)issued a set of comprehensive regulatory standards for the oil and gas industry under the Clean Air Act, requiring the reduction of emissions of volatile organic compounds (VOCs), air toxics and methane from sources in the industry, including the hydraulic fracturing of horizontal natural gas wells drilled or hydraulically re-fractured after August 23, 2011. Although the final rule subjects air emissions from other processes and equipment to regulation, the regulation of emissions associated with hydraulic fracturing for natural gas has drawn the most attention.  

Summary

In response to a consent decree in a suit filed by environmental groups, EPA issued New Source Performance Standards (NSPS) for VOCs and National  Emission Standards for Hazardous Air Pollutants (NESHAP) for oil and natural gas production.  EPA has now set NSPS for hydraulically fractured natural gas wells and for related associated equipment, including pneumatic controllers, compressors and storage vessels.  EPA also set new NESHAP standards for glycol dehydrators and for leak detection at natural gas processing plants.

First Federal Regulations on Hydraulic Fracturing

The rule does not apply to oil drilling from conventional or unconventional sites nor does it apply to equipment at petroleum refineries, which are covered by other rules. The new regulations are designed to reduce VOC emissions and methane; EPA considers methane a significant contributor to climate change.

Elements of the Rule

The new provisions apply to new wells drilled after August 23, 2011, and refracturing of existing wells drilled before August 23, 2011.  New wells drilled prior to January 1, 2015 must reduce VOC emissions either by using "completion combustion devices," or by capturing gas flow back using "reduced emissions completions" (also known as "RECs" or "green completions" ) with a completion combustion device to control gas not suitable for entry into the flow line.

A completion combustion device burns off the gas that would otherwise escape during the well-completion period and usually involves pit flaring, unless state or local laws prohibit such combustion or require more stringent controls.  A green completion uses equipment to separate gas and liquid hydrocarbons from the flow back that occurs as the well is being prepared for production, and may include gas gathering lines or collected system, sand traps, surge vessels and separator tanks.  

EPA did not define or prescribe a particular type of REC technology as it had in its proposed rule but rather gave industry the flexibility to choose or develop a REC that meets the performance standards under the rule.  EPA has provided an incentive for owners and operators to use green completions prior to 2015.  

Beginning January 1, 2015, owners and operators of newly fractured or refractured wells must capture the gas (not flare it) and make it available for use or sale, which they can do through use of green completions.

The new rule defines the time period when these technologies must be used as the "well completion period," or the period of time between when fracturing has begun and ending when either the well is shut in or when natural gas from the well continuously flows to flow line or storage vessel for collection (generally 3-10 days according to EPA), whichever happens first.

Finally, EPA established a pre-notification requirement of 2 days before completion work begins, and allowed notification by email, but deemed state pre-notification requirements sufficient.  EPA also required annual recordkeeping but authorized an alternative streamlined option of reporting emissions by company rather than a separate report for each well or source.  

Exceptions

There are several exceptions to the rule: (i) combustion devices need not be used if there is a safety hazard or such combustion is prohibited by state or local regulations; (ii) RECs are not required for "wildcat" wells or delineation wells used to define the borders of a natural gas reservoirs.    This is because neither type of well would presumably allow captured gas to be loaded to a nearby a pipeline that could bring the gas to market. (iii) hydraulically fractured low-pressure wells, such as many coal bed methane wells, where natural gas cannot be easily routed to a gathering line.  According to EPA, owners and operators of these exempted wells may use a simple formula based on well depth and well pressure to determine whether a well is low-pressure1.   Wildcat and delineation wells are not totally exempt from regulation: owners and operators must still reduce emissions from these wells using combustion devices during the well-completion process, unless such a process is a safety hazard or is prohibited by state or local regulations.   

Significant Changes and Stakeholder Concerns

The American Petroleum Institute complained that immediate implementation of the rule would significantly limit production of natural gas due to a lack of RECs and trained personnel.  EPA took this concern into account and extended the compliance period for two years, to 2015.

EPA did not apply emission control requirements past the point where gas enters the transmission pipeline because it believed the VOC content of the gas would be very low.  EPA rejected industry's request that wells that produce a limited amount of VOCs (e.g. less than 10% by weight) be exempted from the rule.  

Finally, as described above, EPA simplified pre-notification requirements and annual reporting. 

Incentives for Early Action

Gas wells that are refractured with green completion controls will not be considered to be "modified" if the green completion is used to control emissions rather than flaring (and new notification and reporting requirements are met) so NSPS wouldn't be triggered by refracturing, and in a number of states, owners or operators can hydraulically refracture existing wells without triggering state permitting requirements.  Existing wells that are refractured with only combustion devices prior to January 1, 2015 will be considered "modified" for Clean Air Act NSPS and state permitting requirements, as are newly fractured wells.  The fact that a well has been modified, however, does not by itself trigger permit requirements for other parts of the system.

Regulation of Related Oil and Gas Production Equipment

EPA has set NSPS and NESHAP standards for associated equipment used in gas compression and pumping and at other locations in oil and gas production.  EPA did not to set standards for the transmission and storage stages at this time.  EPA set standards for the following equipment that is constructed, modified or reconstructed after August 11, 2011:

  • NSPS for new and modified pneumatic controllers used for maintaining liquid level, pressure and temperatures at oil and gas wells, gathering and boosting stations, and natural gas processing plants.  The rule affects high-bleed, gas-driven controllers that are located between the wellhead and the point where gas enters the transmission pipeline, with standards phased in over a year.  The rule sets bleed limits on natural gas, which is phased in over a year, provides some exceptions for operations and safety, and sets requirements for initial performance testing, recordkeeping and annual reporting.  No emissions are allowed for pneumatic controllers at onshore natural gas processing plants.
  • NSPS and NESHAP for storage tanks at natural gas well sites, compressor stations, gathering and boosting stations and natural gas processing plants, used to store condensate, crude oil and produced water.  New storage tanks with VOC emissions of 6 tons a year or more must reduce them by 95%, presumably through use of a combustion device, with a one year phase-in period.  After one year, owners and operators of new storage tanks at sites with wells in production must comply, while those at sites with no wells in production will have more time.  EPA did not establish NESHAP for storage vessels without the potential for flash emissions, determining it needed more data before taking action.  Existing NESHAP standards for vessels with the potential for flash emissions remain in place, unchanged by the new rule.
  • EPA also amended the definition of "associated equipment" so that emissions from all storage vessels now will be counted toward determining if a facility is a major source under the NESHAP for Oil and Natural Gas Production.
  • NESHAP for glycol dehydrators located at well sites, compressor stations, gathering and boosting stations and natural gas processing plants.  The rule keeps in place the current NESHAP for large glycol dehydrators but sets new unit-specific emission limits for small glycol dehydrators depending on location.  New small glycol dehydrators must comply upon startup or within 60 days of final rule publication, whichever is later, but existing equipment has a three year compliance date.
  • NSPS and NESHAP for centrifugal and reciprocating compressors located between the wellhead and the point where gas is delivered for transmission at natural gas gathering and boosting stations and processing plants, including requirements for emission reductions, replacements, initial performance testing, recordkeeping and annual reporting.
  • Finally, the rule strengthens leak detection and repair requirements at existing onshore natural gas processing plants as well as sulfur dioxide limits at new and modified sweetening units at natural gas processing plants.  

Other Expected Regulatory Actions on Hydraulic Fracturing

EPA and other agencies will propose other types of regulations addressing the practice.  For example, the Department of Interior is set to issue regulations in the near future which would impose standards on hydraulic fracturing on publicly-owned lands, including providing full disclosure of chemicals used in the process.  

EPA will soon complete the first phase of a comprehensive life-cycle analysis of water use during hydraulic fracturing, including intake, surface spills, impacts on groundwater, and wastewater.  The report will be finalized in 2014, and we expect that EPA will propose further regulations on such use.  EPA also recently announced it would consider wastewater treatment rules and effluent guidelines for hydraulic fracturing under the Clean Water Act.  

Finally, EPA said it would soon issue guidance on permits for use of diesel in hydraulic fracturing under the Safe Drinking Water Act and is considering action under the Toxic Substances Control Act to require full disclosure of the identity and toxicity of chemicals used in hydraulic fracturing.  When it finishes its work, EPA may have in place a fairly comprehensive regime regulating hydraulic fracturing.  At the same time, EPA regions have engaged in specific responses to perceived regional contamination, such as in Wyoming, Pennsylvania and Texas, and the President recently established a multi-agency task force to coordinate regulatory efforts on hydraulic fracturing.  

These regulations are in addition to those imposed by states (at least two of which, Colorado and Wyoming, already require green completion), and could substantially overlap with state regulations.