Oil and Gas Industry Faces Significant New Air Quality Requirements



EQ Summer 2012_Oil and Gas banner

On April 17, 2012, the EPA Administrator signed a suite of final air quality regulations affecting both the Production/Processing and Transmission/Storage sectors of the oil and natural gas industry. The final rules mandate the use of emission controls as well as work practices through two different air regulatory programs – New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP). The rules were proposed in the Federal Register on August 23, 2011, and EPA received more than 156,000 written comments.

While many in the press have heralded the rules as “Fracking Regulations,” the scope of these new regulations reaches far beyond that of hydraulic fracturing at natural gas wellheads. In addition to covering air emissions resulting from hydraulic fracturing at gas wells, these rules also regulate a variety of other new, modified, or reconstructed sources, including downstream compressors, pneumatic controllers, storage tanks, and fugitive leaks. Promulgation of the final rules will result in new control equipment requirements as well as increased and potentially burdensome monitoring, recordkeeping, and reporting requirements for owners, operators, contractors, and vendors. At a minimum, affected sources should ensure the following in preparation for the rule:

  • Review and analyze the final published rules (which contain differences from the proposed rules)
  • Inventory all existing facilities, equipment, and operational characteristics to establish a basis for much determining applicability of any new, modified, or reconstructed emission sources, with a particular focus on those installed after August 23, 2011
  • Train staff on operational, monitoring, recordkeeping, and reporting requirements
  • Budget for increased costs associated with installation of control equipment, more stringent maintenance and replacement schedules, and
    resources to handle increased monitoring, recordkeeping, and reporting requirements
  • Acquire and install control equipment and conduct performance testing as applicable

The final NSPS and NESHAPs are highlighted in the following sections, along with the anticipated impacts of the regulations.

40 CFR Part 60, NSPS Subpart OOOO

The New Source Performance Standards under Subpart OOOO apply to affected facilities that commence construction, reconstruction, or modification after August 23, 2011. However, the compliance date for affected facilities depends on the type of emission source. Affected facilities include: hydraulically fractured natural gas wells, compressors, continuous bleed pneumatic controllers, storage vessels, fugitive equipment components at onshore natural gas processing plants, and sweetening units at onshore natural gas processing plants. Table 1 outlines the sources in each industry segment impacted by this regulation.

EQ Summer 2012 OG Table1

Notable changes from the proposed rule to the final rule are highlighted below:

  • Phased timeline for implementation of control measures for pneumatic controllers, storage vessels, and well completions
  • Exemptions for equipment meeting design or control standards (e.g., low pressure gas wells, dry seal centrifugal compressors, low bleed controllers)
  • Final rule sets six (6) ton per year (tpy) threshold for volatile organic compound (VOC) emissions as the trigger for control requirements on storage tanks
  • Certain equipment in transmission gas service is not subject to the final rule
  • A 30-day advance notice of well completion is not required. Final rule states that a 2-day advance email is sufficient for notification.

EPA eliminated the startup, shutdown, malfunction (SSM) exemptions such that compliance with the requirements in the final rule is required at all times. In conjunction with this change, EPA added a provision for affirmative defense to civil penalties for exceedances of emission limits caused by malfunctions.

Hydraulically Fractured Gas Wells

Starting 60 days following the Rule’s publication in the Federal Register, this rule will require operators of all new, reconstructed, and modified affected facilities to capture and route flowback emissions to a completion combustion device during completion operations after hydraulic fracturing at gas wellheads unless there is a risk of fire or explosion. If more stringent state requirements are already in place (for example Colorado and Wyoming already require the use of green completion technologies), the more stringent state requirements would apply.

Operators performing completions after hydraulic fracturing at gas wellheads commencing after January 1, 2015 must employ “green completions technologies,” or reduced emissions completions (REC) and route all salable quality gas to the gas flow line as soon as practicable. Documentation of compliance with this requirement is completed through a photograph of the recovery and completion combustion equipment that contains the location of the wellhead and the date of the completion operations. No third party verification of completions is required in the final rule. Wildcat, delineation, and low pressure wells are not required to comply with REC/green completion requirements. In the final rule, EPA defined low pressure wells using an equation based on the reservoir and flow line pressures.

EPA included a general duty clause that requires owners/operators to safely maximize resource recovery and minimize releases to atmosphere during flowback and recovery. This requirement applies to all completion activities regardless of when and where the activity is conducted.

Hydraulically refractured gas wellheads are not affected should the owner/operator comply with all completion emission reductions requirements. It is important to note that refracturing does not affect the modification status of other equipment located at a well site.

Continuous Bleed Pneumatic Controllers

New, reconstructed, and modified continuous bleed gas-driven pneumatic controllers located between a wellhead and the point of custody transfer to the natural gas transmission and storage segment (and not located at a natural gas processing plant) with a natural gas bleed rate greater than six standard cubic feet per hour (scfh), and continuous bleed gas-driven pneumatic controllers at natural gas processing plants, are potentially subject.

Unless the use of a high bleed controller is deemed necessary due to functional needs such as response time, safety, or positive actuation, the following bleed rates must be met:

  • Pneumatic controllers located between a wellhead and a natural gas processing plant: a natural gas bleed rate less than or equal to six scfh
  • Pneumatic controllers located at a natural gas processing plant: a natural gas bleed rate of zero (i.e., no bleed or non-gas driven)

The natural gas bleed limits for controllers between gas wellheads and natural gas processing plants are applicable to controllers installed one year from the date of publication of the final rule. This phase in period is not applicable to controllers located at gas plants. Existing units already in stock and ordered before August 23, 2011 are exempt from these requirements.

Continuous bleed pneumatic controllers subject to the rule must be tagged with the month and year of installation, reconstruction, and/or modification, as well as the design bleed rate.

Reciprocating and Centrifugal Compressors

Compressors regulated by the final rule are new, reconstructed, and modified reciprocating compressors or centrifugal compressors equipped with wet seals. The compressor must be located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment to be affected. Compressors located at a well site, or adjacent to a well site and servicing more than one well site, are not affected facilities under the final rule. In the proposed rule, centrifugal compressors were required to be equipped with dry seals. In the final rule, centrifugal compressors with dry seals are not affected sources, while the option to install wet seal compressors equipped with controls was added.

Reciprocating compressor affected sources must replace the rod packing either (1) before the compressor has operated 26,000 hours from initial startup or the last packing replacement (which requires continuous monitoring of the hours of operation); or (2) prior to 36 months from startup or the last rod packing replacement.

Centrifugal compressors impacted by this regulation must reduce VOC emissions from each wet seal fluid degassing system by 95.0 percent or more. If using a control device, the system must be equipped with a cover and closed vent system. Continuous compliance is demonstrated through inspections and parametric monitoring.

Storage Vessels

Individual storage vessels located in the oil and natural gas production segment, natural gas processing segment, or natural gas transmissions and storage segment are affected facilities under the final rule. The definition of storage vessel in the final rule was changed from the proposed rule and excludes the following:

  • Vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive days 
  •  Process vessels such as surge control vessels, bottoms receivers or knockout vessels  
  • Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere  

For skid-mounted or storage vessels attached to mobile equipment, records must be maintained to document the number of consecutive days that the vessel is located at a site. If a vessel is removed from a site and, within 30 days, is either returned to or replaced by another vessel at the site to serve the same or similar function, then the entire period since the original vessel was first located at the site, including the days when the storage vessel was removed, will be included in calculating the number of consecutive days.

EQ Summer 2012 OG tanksUnlike the proposed rule, where control requirements were based on throughput, the final rule requires controls for new, reconstructed, and modified storage vessels that have VOC emissions equal to or greater than six tpy. New, reconstructed, and modified storage vessels with VOC emissions exceeding 6 tpy must have controls to reduce VOC emissions by 95% installed no later than one year after publication in the Federal Register. If using a control device, the system must be equipped with a cover and closed vent system. Continuous compliance is demonstrated through inspections and parametric monitoring.

EPA did not specify a preferred methodology for calculating emissions from storage vessels for applicability determinations, instead allowing the use of any generally accepted model or calculation methodology. For storage vessels located at well sites without wells in production, owners and operators must determine the VOC emission rate for each storage vessel affected facility within 30 days after startup, and minimize emissions to the extent practicable during the 30-day period using good engineering practices. For each subject storage vessel triggering control requirements, the owner or operator must comply within 60 days after startup. For each subject storage vessel at a well site with one or more wells already in production, control requirements must be met upon startup.

Standards for VOC Emissions from Leaks at Natural Gas Processing Plants

NSPS Subpart OOOO regulates the group of fugitive equipment leaks within a process unit as an affected facility. Equipment includes pumps, pressure relief devices, open-ended lines, valves, flanges, and other connectors that are in VOC or wet gas service and other systems or devices required by the rule. Compressors are excluded from this group as they are regulated separately under the final rule. Addition or replacement of equipment for the purpose of process improvement that is accomplished without a capital expenditure is not by itself considered a modification.

A process unit is defined as components assembled for: 1) the extraction of natural gas liquids from field gas, 2) the fractionation of the liquids into natural gas products, or 3) other operations associated with the processing of natural gas products. The definition of natural gas processing plant in the final rule was revised to exclude Joule-Thompson valves, dew point depression valves, or isolated standalone Joule-Thompson skids.

Owners or operators with equipment subject to the rule must implement a leak detection and repair (LDAR) program. With some exceptions, the standards in NSPS OOOO that apply to equipment leaks of VOC follow those set forth in NSPS Subpart VVa. Semiannual compliance reports are required for applicable facilities.

Sweetening Units at Natural Gas Processing Facilities

The final rule applies to new, reconstructed, and modified sweetening units located at onshore natural gas processing plants. Units that have a design capacity less than 2 long tons per day of hydrogen sulfide in the acid gas (expressed as sulfur) are only subject to the recordkeeping and reporting in the final rule. Sweetening units producing acid gas that is completely reinjected into oil-bearing or gas-bearing geologic strata, or acid gas not otherwise released to the atmosphere, are not subject to emission limits or the additional recordkeeping and reporting requirements in the final rule.

The emission limits in the final rule for subject sweetening units remains unchanged from the proposed rule. The sulfur dioxide emission reduction efficiency for subject units is calculated based on the sulfur feed rate and the sulfur content of the acid gas.

Reporting and Recordkeeping

The following notifications are required for all affected facilities under NSPS OOOO except gas wells, pneumatic controllers, and storage vessels:

  • A notification of the date construction or reconstruction of an affected facility is commenced, postmarked no later than 30 days after such date
  •  
  • Notification of any change that may increase emissions of pollutants to which a standard applies within 60 days or as soon as practicable before implementing the change  

Notification of well completion is required no later than two days prior to the commencement of each well completion. The notification must include owner/operator contact information, API well number, location of the gas well, and planned date of the beginning of flowback. The notification can be submitted in writing or via email. If state regulations also require advance notification of well completions, those notifications can be used in lieu of the well head notification requirements under NSPS OOOO .

The rule requires annual reporting for affected facilities. The annual report is due 30 days from the date the compliance period ends, with subsequent annual reports due on the same date. Owners or operators can submit a combined report for all affected facilities. The annual reports, which must be certified by a responsible official, must contain identification of affected facilities, and deviations from work practice or emission/operating limits.

Recordkeeping requirements include the information contained in the annual reports, information about duration of well completion activities, manufacturer’s specifications for pneumatic controllers, and emission calculations for storage vessels.

Amendments to NESHAP 40 CFR Part 63, Subparts HH and HHH

Amendments to the two existing major source natural gas industry NESHAPs (Subpart HH: National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities and Subpart HHH: National Emission Standards for Hazardous Air Pollutants From Natural Gas Transmission and Storage Facilities) were finalized along with NSPS OOOO. The NESHAP amendments are a result of EPA’s periodic residual risk review process. The rule amendments affect equipment not previously subject to NESHAP requirements, such as small dehydrators. A number of other updates to NESHAPs HH and HHH are related to the compliance demonstration requirements.

EPA has amended the standards for major sources of hazardous air pollutants (HAPs) but not for area sources of HAPs. However, EPA revised potential to emit calculations to include all storage vessels (not just those with potential for flash) in the production segment and to assume worst-case glycol circulation rate for glycol dehydrators in both rules. For those area sources that become major sources based on the new calculation methodology, there is a three-year compliance timeline. For area sources with actual emissions greater than 50% of the major source threshold (5 tpy of individual HAP/12.5 tpy of total HAP), owners or operators must review the major source determination annually using gas composition data measured within the last 12 months.

In both the production and transmission/storage sectors, small dehydrators were previously exempt from the NESHAP rules. In the amended final NESHAP rules, EPA revised the emission limits for small dehydrators at major sources. Existing small glycol units that are subject to the NESHAP for the first time (i.e., commenced construction before August 23, 2011) have three years from the effective date of the amended final rules to comply. Table 2 summarizes the emission limits for small dehydrators in each amended NESHAP Subpart.
EQ Summer 2012 OG Table 2
In the proposed amendments, EPA had proposed to remove the 1 tpy benzene alternative compliance option for major sources and require controls of all storage vessels (including those without the potential for flash emissions). However, in the final amended rules EPA retained the 1 tpy benzene option and did not include control requirements for storage vessels without the potential for flash emissions.

In both sectors, EPA included an alternate compliance option for non-flare combustion devices allowing manufacturers to demonstrate the destruction efficiency for a specific model in lieu of facilities conducting site-specific tests for those specific control devices. In addition, the following compliance related amendments were made to the final rules:

  • Revisions to the parametric monitoring provisions, including the development of a site-specific monitoring plan
  • Addition of periodic performance testing where applicable
  • Removal of the allowance of a design analysis for all control devices other than condensers
  • Removal of the requirement for a minimum residence time for an enclosed combustion device
  • Addition of recordkeeping and reporting requirements to document carbon replacement intervals
  • Lowering leak detection limit for valves to 500 parts per million 

Similar to other recently promulgated NESHAPs, EPA eliminated the SSM exemptions such that the established standards in these two NESHAPs apply at all times. In conjunction with this change, EPA added a provision for affirmative defense to civil penalties for exceedances of emission limits caused by malfunctions.

What’s Next?

EPA has made it clear that oil and gas production and processing sources will be the focus of its National Enforcement Initiative (NEI) for fiscal years 2012 and 2013. With the new NSPS and revised NESHAPs in place, EPA has the tools it needs to enforce in a comprehensive manner. Take time to review these regulations in detail: the impacts are far reaching, the recordkeeping is not insignificant, and inaccurate or missed reporting can lead to enforcement actions years from now if not approached carefully. While the political landscape may change months, or even years, from now, air quality regulations for the oil and gas industry are not likely to lessen overnight – if at all. Now is the time to review, prepare, plan – and most importantly, participate. Provide comments on future proposed rules, work with legislators and rule makers to achieve common sense solutions, and participate with your industry organizations that may be negotiating with EPA, state, and local agencies regarding oil and gas rules.