On April 17, 2012, United States Environmental Protection Agency (EPA) Administrator Lisa Jackson signed final New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPs) for the upstream and midstream oil and gas industries. For the first time, EPA will regulate air emissions from natural gas wells that are hydraulically fractured, as well as other emission sources associated with exploration, production, processing, and transportation of oil and natural gas. EPA, however, made several key concessions in response to the thousands of comments it received, making the final rules somewhat less stringent than the proposed rules in several important ways. For example, EPA has provided phase-in periods for several of the emission standards to give operators more time to comply, included additional exemptions for some of the emission standards, and reduced or streamlined some reporting obligations. Moreover, with regard to some source types, such as large glycol dehydrators, that were already subject to standards for air toxics under existing rules, EPA decided to leave the existing standards in place rather than impose new, more stringent standards. The final rules will appear in the Federal Register in the coming weeks, and will take effect 60 days thereafter.
We released a detailed summary of the proposed rules that EPA published in the Federal Register on August 23, 2011, which is available here. Here, we summarize the key changes in the final rule from EPA's proposal.
Summary of Changes to NSPS
EPA finalized a new NSPS at 40 C.F.R. Part 60, Subpart OOOO. The new Subpart OOOO regulates emissions of volatile organic compounds (VOC) and sulfur dioxide (SO2) from a variety of oil and gas exploration, production, processing, and transportation facilities, including natural gas wells, certain compressors and pneumatic controllers, storage vessels, and sweetening units at onshore natural gas processing plants.
NSPS Applicability and Compliance Dates
Consistent with the proposed rule, the new NSPS will apply to new facilities that commence construction after August 23, 2011, the date the proposed rule was published in the Federal Register, as well as existing facilities that commence modification or reconstruction after August 23, 2011. However, facilities subject to the rule will not have to be in compliance with the rule's requirements on the date the final rule is published in the Federal Register, as proposed. Instead, existing facilities subject to the rule will have 60 days after the final rule is published in the Federal Register to come into compliance.
Standards for Hydraulically Fractured Natural Gas Wells
Phase-in Period for Requirement to Use REC Technology
The final rule, consistent with the proposed rule, will require that natural gas wells that are hydraulically fractured employ reduced emission completion (REC) technology (also known as "green completion" technology) to control emissions during flowback.1 The requirement to employ REC technology, however, will only apply to well completion operations using hydraulic fracturing that commence on or after January 1, 2015. EPA explained that it is phasing in the REC requirement to allow more time for sufficient REC equipment and qualified service providers to become available. For natural gas wells for which well completion operations begin before January 1, 2015, the operator need only capture and direct flowback emissions to a "completion combustion device,"2 which in most cases will be a flare.
Exclusion from REC Requirements for Low Pressure Gas Wells and When "Infeasible"
The final rule expressly excludes "low pressure gas wells" from the requirement to use REC technology. Whether a well qualifies as a low pressure well is determined based on the well's vertical depth, reservoir pressure, and the flow line pressure at the sales meter, using a prescribed equation.3 Low pressure gas wells, along with delineation wells and wildcat wells, will only be required to use a completion combustion device to control emissions during flowback. EPA estimates that this exclusion for low pressure gas wells will cover 10 percent of all natural gas wells and, specifically, 87 percent of coal-bed methane wells.
Notably, the rule also provides that if using REC technology is "infeasible," the operator may use a completion combustion device to control flowback emissions. The rule, however, does not define the term "infeasible" or provide further elaboration on the circumstances that may constitute infeasibility.
New General Duty to Maximize Resource Recovery and Minimize Releases
Although the final rule somewhat relaxes some of the requirements for hydraulically fractured natural gas wells, it also includes a broad and somewhat vague new requirement. For all hydraulically fractured natural gas wells, the final rule imposes a "general duty to safely maximize resource recovery and minimize releases to the atmosphere during flowback and subsequent recovery."
New Definition of REC
The final rule also defines REC differently. In the proposed rule, EPA defined the method in terms of the equipment used, requiring that operators utilize sand traps, surge vessels, separators, and tanks. In the final rule, EPA instead defines REC more generally, requiring that operators route the recovered liquids into one or more storage vessels or re-inject the recovered liquids into the well or another well, and route the recovered gas into a gas flow line or collection system, reinject the recovered gas into the well or another well, use the recovered gas as an on-site fuel source, or use the recovered gas for another useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere.
In making this change the EPA emphasized that it received numerous comments that there are multiple methods for reduced emission completions and decided to set an emission standard for RECs rather than specify a particular practice.
Incentives to Use REC before January 1, 2015
To encourage operators to use REC technology before it is required beginning on January 1, 2015, the final rule will exempt existing wells that are refractured using REC from the definition of "modification." Sources choosing to take advantage of this exemption must still use a combustion completion device and comply with specific reporting requirements. While the requirements under the NSPS are not materially different from refractured wells adopting REC prior to January 1, 2015, the fact that these wells will not trigger a "modification" under the Clean Air Act will allow operators in many states to refracture wells without triggering additional state permitting requirements. EPA believes that this provision, exempting some sources from triggering the definition of modification, will result in an additional 1,000 to 1,500 REC.
Simplified Notification and Reporting Requirements
In the final rule, EPA has simplified the initial notification requirements for hydraulically fractured natural gas wells. Under the proposed rule, operators would have been required to provide EPA with at least 30 days' advance notice before commencing well completion operations. Under the final rule, operators need only provide EPA with two days' advance notice, which may be provided by e-mail. Moreover, if the operator is required under applicable state law to provide advance notice of commencement of well completion operations, compliance with the state notice requirement will satisfy the NSPS's advance notice requirement.
EPA also included in the final rule a simplified option for annual reporting for hydraulically fractured natural gas wells. Under the alternative option, operators may submit only a list, with certain identifying information, of all hydraulically fractured natural gas wells completed during the annual reporting period, along with photographs showing the REC in progress.
Standards for Compressors
Narrower Definitions of Affected Compressors
The proposed rule would have applied broadly to all new centrifugal and reciprocating compressors in natural gas gathering, processing, or transmission operations located anywhere between the wellhead and the point where natural gas is transferred to a local utility, excepting only compressors located at the "well site." Under the final rule, only compressors located between the wellhead and the point where natural gas is transferred to the natural gas transmission and storage segment, excluding compressors at well sites, are subject to the requirements. EPA limited the applicability of the new standards for compressors because it concluded that the VOC content of natural gas by the time it reaches the transmission sector is typically too low for controls to be cost effective.
EPA also clarified that, although a compressor is considered to have commenced construction when it is installed, this does not include relocation. Therefore, merely relocating an existing compressor will not cause it to become subject to the rule.
The proposed rule would have established a performance standard requiring that all new centrifugal compressors use dry gas seals. However, under the final rule, the EPA determined that such measures were not necessary and instead finalized performance standards for wet-seal centrifugal compressors. Centrifugal compressors with wet-seals must utilize a control system that captures emissions from the wet seal fluid degassing system and routes them to a control device in order to reduce VOC emissions by at least 95 percent. The control device used will be subject to performance testing and extensive recordkeeping and reporting obligations, consistent with other NSPS standards. New compressors that use dry gas seals will not be affected facilities under the rule.
Simplified Compliance Option for Reciprocating Compressors
For reciprocating compressors, the proposed rule would have required operators to change rod packings after 26,000 hours of operation and to track and record hours of operation for each compressor. Under the final rule, operators may choose to track and record hours of operation and change rod packings after 26,000 hours, but alternatively may choose to change rod packings every 36 months and track and record only the dates when the rod packings are changed.
Standards for Pneumatic Controllers
The proposed rule would have applied to all pneumatic controllers installed in any oil or natural gas exploration, production, gathering, processing, or transmission operation. The final rule considerably narrows the definition of affected pneumatic controllers such that the final rule only applies to continuous bleed natural gas-driven pneumatic controllers that commenced construction after August 23, 2011, and that are (1) operating at a natural gas bleed rate greater than six standard cubic feet per hour (scfh) and located between the wellhead and the point at which natural gas is transferred to the natural gas transmission and storage segment, or (2) located at natural gas processing plants. NSPS requirements will thus not apply to pneumatic controllers used in the transmission and storage segment.
EPA's final definitions of affected facilities for pneumatic controllers focus on gas-driven, continuous-bleed devices. The EPA noted that it has carefully circumscribed the definition of affected facility to clarify that the NSPS does not apply to intermittent bleed devices and devices that are designed to be no-bleed. The definitions are designed to exclude pneumatic controllers that meet the NSPS standard, exempting them from the recordkeeping and reporting requirements of the rule. This will encourage operators to install low-bleed, intermittent-bleed, and/or non-gas-driven devices whenever possible in the future to avoid the administrative obligations of the rule.
EPA, however, took the somewhat unusual step of setting the performance standard equivalent to the applicability threshold in the definition of the affected source. As a result, a pneumatic controller that falls within the definition of an affected facility cannot meet the performance standard in most cases without a change in design or operation. Once an affected pneumatic controller has met the performance standard, it is not clear whether it then remains subject to the rule and must continue to comply with the ongoing recordkeeping and reporting requirements. As the rule is currently written, a controller that meets the performance standard falls outside of the definition of an affected pneumatic controller facility.
Standards for Storage Vessels
Revised Definition of Storage Vessel
EPA significantly revised the definition of storage vessel from the proposed rule. The proposed rule defined storage vessel as "a stationary vessel or series of stationary vessels that are either manifolded together or are located at a single well site and that have potential for VOC emissions equal to or greater than 10 [tons per year]." The final rule defines "storage vessel" as "a unit that is constructed primarily of nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) which provides structural support and is designed to contain an accumulation of liquids or other materials." The revised definition also explicitly excludes skid-mounted vessels and mobile vessels attached to vehicles that are intended to remain at a site for less than 180 consecutive days, as well as process vessels, and pressure vessels designed to operate in excess of 204.9 kilopascals with no emissions to the atmosphere.
Six Tons per Year VOC Emissions Threshold for Control Standard Applicability
Under the proposed rule, EPA set throughput thresholds, below which storage vessels would not be subject to control requirements. In the final rule, EPA instead sets a VOC emissions threshold of six tons per year (tpy) as the trigger for control requirements. For storage vessels with VOC emissions above six tpy, operators must reduce VOC emissions by 95 percent, employing means such as a floating roof or a closed vent system and control device.
Clarified Compliance Deadlines and One-Year Phase-in Period
For storage vessels installed at well sites with no wells in production, operators may calculate VOC emissions from the vessel within 30 days after startup of the vessel based on actual operating data and, if controls are required, may take up to another 30 days to install controls to meet the 95 percent control standard. For storage vessels installed at well sites with one or more wells already in production, operators must calculate VOC emissions based on existing information, and if the vessel will emit more than six tpy of VOC, must meet the 95 percent control standard upon startup. The final rule also provides a phase-in period, such that affected storage vessels need not comply with applicable control standard until one year after the date the final rule is published in the Federal Register.
Standard for Equipment Leaks at Onshore Natural Gas Processing Plants
In the final rule, EPA excluded compressors from the leak detection and repair (LDAR) requirements applicable to equipment at onshore natural gas procession plants. The proposal had expressly designated compressors as subject to the LDAR requirements. EPA explained that compressors should be excluded from the LDAR requirements because the rule already imposes control requirements on compressors.
Startup, Shutdown, and Malfunction Provisions
Consistent with the proposed rule, the final rule provides that the general exemption from compliance with emission standards during periods of startup, shutdown, and malfunction found in the NSPS general provisions in 40 C.F.R. Part 60, Subpart A, will not be available for the facilities subject to this rule. The final rule also retains the affirmative defense to civil penalties for periods of non-compliance with emissions standards during malfunctions, as in the proposed rule. EPA provided some relief to operators in the final rule by making it slightly easier for them to claim the affirmative defense, although the requirements remain arduous.
Under the proposed rule, operators would have been required to notify EPA within two days of any non-compliance for which it sought to claim the malfunction affirmative defense, and submit a written report to EPA within 45 days demonstrating that all elements of the affirmative defense were satisfied, including the requirement to prepare a detailed root cause failure analysis. Under the final rule, an operator must still prepare documentation, including a root cause failure analysis, showing that it meets all the criteria of the affirmative defense. However, the operator need not submit the documentation to EPA or otherwise provide notice to EPA until the first periodic compliance report, deviation report, or excess emission report that is due more than 45 days after the malfunction event occurs.
Summary of Changes to NESHAPs
EPA finalized revisions to 40 C.F.R. Subparts HH (covering the oil and natural gas production sector) and HHH (covering the natural gas transmission and storage). While EPA finalized standards that will cover small glycol dehydrators for the first time, EPA has modified the standards that will apply to these sources. These new rules will apply to glycol dehydrators that are located at major sources, which are defined as those sources that have the potential to emit more than 10 tpy of any single HAP or 25 tpy or more of any combination of HAPs. EPA also finalized modifications to the leak detection standards for valves. These standards are unchanged from the proposed rule, and therefore are not discussed further herein.
EPA chose not to finalize two elements of its proposed rule for NESHAPs. The final rule does not contain standards for crude oil and condensate storage tanks. In addition, EPA decided not to eliminate the 0.9 megagrams per year (Mg/yr) compliance option for large glycol dehydrators.
Standards for Glycol Dehydrators
Less Stringent Emission Limits for Small Glycol Dehydrators
As with the proposal, the final rule will require small glycol dehydrators — those with an actual annual average natural gas flow rate of less than 85,000 standard cubic feet per day or actual annual average benzene emissions of less than one tpy — to comply with unit-specific limits on annual emissions of benzene, toluene, ethylene, and xylene (collectively, "BTEX"). The major change since the proposal is that EPA has raised the emission limitations. EPA decided to raise the emission limits in response to comments that it had failed to properly account for variability in setting the MACT floor.
Preservation of 0.9 Mg/yr Compliance Option for Large Glycol Dehydrators
Subparts HH and HHH contain alternative compliance options for large glycol dehydrators that exempt those dehydrators with annual benzene emissions less than 0.9 Mg/yr from meeting the performance levels specified in the regulation. EPA had proposed to eliminate this exemption on the assumption that emissions permitted under this option were the major driver of residual risk from BTEX emissions. However, EPA received comments pointing out shortcomings in the risk assessments for Subparts HH and HHH, which led the Agency to reevaluate its risk assessment. Upon reevaluation, the EPA concluded that fugitive emissions, not emissions from large glycol dehydrators with annual benzene emissions less than 0.9 Mg/year, were the major driver of residual risk. As a result, EPA decided not to eliminate the exemption. EPA further considered adding more robust LDAR requirements, but concluded that the costs of such measures exceed their risk reduction benefits and could not be justified.
Standards for Storage Vessels
EPA proposed revisions to Subpart HH to apply NESHAP emission limitations to all storage tanks, rather than just to those tanks with the potential for flash emissions. EPA decided not to finalize these revisions because it determined that additional data is necessary to establish the MACT standard. The existing standards under Subpart HH for tanks with the potential for flash emissions remain in place, but the EPA chose not to promulgate new standards covering other crude oil and condensate storage tanks.
Standards for Valves
Consistent with the proposed rule, the final rule amends Subparts HH and HHH to establish new leak detection standards for valves. Under these standards, a leak triggering the rule's LDAR requirements is any measurement exceeding 500 ppm of any regulated HAP.
Startup, Shutdown, and Malfunction Provisions
Consistent with the proposed rule, the final rule eliminated the exemption for periods of startup, shutdown, and malfunction in response to the D.C. Circuit's holding in Sierra Club v. EPA. The EPA determined that different standards were not required for periods of startup and shutdown because it concluded based on available data that emissions during periods of startup and shutdown are not different from those under full operating conditions. As with the NSPS, EPA has established an affirmative defense to civil penalties under the Clean Air Act that applies to malfunctions. The elements of the affirmative defense are the same as those provided in the regulations' general provisions, and the affirmative defense report is to be included in the first periodic compliance report, deviation report or excess emission report otherwise required after the initial occurrence of the malfunction.
Footnotes
1 The final rule defines "flowback" as "the process of allowing fluids to flow from a natural gas well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production." According to the rule the flowback begins "when material introduced into the well during the treatment returns to the surface immediately following hydraulic fracturing or refracturing" and the flowback ends "with either well shut in or when the well is producing continuously to the flow line or to a storage vessel for collection."
2 The final rule defines a "completion combustion device" as "any ignition device, installed horizontally or vertically, used in exploration and production operations to combust otherwise vented emissions from completions."
3 Specifically, a "low pressure gas well" is a "well with reservoir pressure and vertical well depth such that 0.445 times the reservoir pressure (in psia) minus 0.038 times the vertical well depth (in feet) minus 67.578 psia is less than the flow line pressure at the sales meter."
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