WASHINGTON–The latest version of the U.S. Environmental Protection Agency’s methane regulation sends Lee Fuller back to a theme he has voiced about the agency’s initial proposal.

“The devil is in the details,” reflects Fuller, officer of environment and general strategy for the Independent Petroleum Association of America. “We did not have many details last year. Now we have more details, but a lot of questions.”

In November 2021, when EPA unveiled its proposed rulemaking to revise the Quad Oa Clean Air Act (CAA) new source performance standard for air quality regarding methane and volatile organic compound emissions at oil and gas sites, the proposal lacked customary elements of a formal proposal (AOGR, December 2021, pg. 33). After collecting feedback in the form of 470,000 public comments, public hearings and consultations with tribal councils, the agency has updated its proposal with a supplemental draft that fills in some blanks and makes minor changes, but still appears to ignore considerations important to many oil and gas industry representatives.

“For existing sources, which predominantly will be small ones, the rulemaking’s impact hinges on the nature of the relationship between these guidelines and state programs,” Fuller assesses. “Will EPA delegate much of the implementation to states, or will it become a real battle between the states and EPA over how to regulate? States all have their own ways of writing rules that are embedded in their state rulemaking processes. I do not expect they will adopt whatever EPA tells them to.”

Agency Overview

When EPA unveiled its proposal on Nov. 11, it noted that oil and gas operations constituted the country’s largest industrial source of methane, which the agency describes as a greenhouse gas that traps about 80 times as much heat as carbon dioxide during its first 20 years in the atmosphere. EPA estimates that methane is responsible for a third of the globe’s GHG-associated warming. The agency adds that oil and gas operations are also significant sources of smog-forming volatile organic compounds and toxic air pollutants such as benzene.

“The updates would provide more comprehensive requirements to reduce climate and health-harming air pollution, including from hundreds of thousands of existing oil and gas sources nationwide,” EPA maintains. “It would promote the use of innovative methane detection technologies and other cutting-edge solutions, many of which are being developed and deployed by small businesses providing good-paying jobs across the United States.”

EPA also touts the proposal’s “Super-Emitter Response Program,” which seeks to require operators to respond to credible third-party reports of high-volume methane leaks. Ultimately, the agency predicts that in 2030 the proposal will cut methane emissions from covered sources by 87% below 2005 levels.

EPA says the supplemental proposal’s CAA standards complement HR 5376, “The Inflation Reduction Act” reconciliation package President Biden signed in the summer. The agency explains that the law allocates resources to provide financial and technical assistance to reduce emissions, and creates waste emissions charge for applicable oil and gas facilities that exceed statutorily specified waste emissions thresholds. The law includes incentives for early implementation of methane reduction technologies and supports methane mitigation and monitoring activities, EPA continues.

“Taking into account both the supplemental proposal and other measures in the November 2021 proposal, EPA projects that the proposed standards would reduce an estimated 36 million tons of methane emissions from 2023 to 2035, the equivalent of 810 million metric tons of CO2. That’s nearly the same as all GHGs emitted from coal-fired electricity generation in the United States in 2020,” the agency calculates. “EPA’s estimates also show the updated proposal would reduce VOC emissions by 9.7 million tons from 2023 to 2035, and air toxics emissions, including chemicals such as benzene and toluene, by 390,000 tons.”

According to EPA, key features of the supplemental proposal will:

• Ensure all well sites are routinely monitored for leaks until they are properly plugged;
• Provide industry flexibility to use innovative and cost-effective methane detection technologies, and a streamlined process for approving new detection methods as they debut;
• Leverage data from remote sensing technology to quickly identify and fix large methane leaks;
• Require that flares are properly operated to reduce emissions and tighten the criteria that must be met to flare associated gas;
• Establish emission standards for dry seal compressors;
• Set a zero-emissions standard for pneumatic controllers and pneumatic pumps at affected facilities throughout all industry segments; and
• Increase recovery of natural gas that otherwise would go to waste in volumes that, from 2023 to 2035, are sufficient to heat an estimated 3.5 million homes during the winter.

According to S&P Global Market Intelligence Senior Reporter Tom DiChristopher, a production site’s equipment type and extent will determine leak monitoring requirements instead of the original proposal’s use of estimated emissions. “The requirements will differ for small well sites, wellhead-only sites, sites with major production and processing equipment, and sites on Alaska’s North Slope,” he comments. “The new proposal also dropped exemptions for well sites with lower emissions, meaning sites of all sizes would be subject to the rule.”

Fugitive Emissions

Fuller says many elements of the proposal seem poorly matched and suggests that small producers may be particularly vexed by the fugitive emissions program, which has troubled IPAA since the 2021 proposal. “That remains the principal issue, because the mechanics of that program relate to operating cost,” he evaluates.

Fuller acknowledges that EPA’s latest proposal exhibits some strides in accepting IPAA’s comments in favor of using an auditory/visual/olfactory (AVO) approach as a primary leak detection method on smaller facilities. “Expensive forward-looking infrared (FLIR) cameras are not necessary to figure out what is going on at a small facility,” he reasons. “A U.S. Department of Energy study shows that most emissions originate not from process equipment, but from tanks because of factors such as open thief hatches or separators with failing pneumatic controllers. Those can be identified in routine equipment reviews.”

Industry representatives such as the Kansas Independent Oil & Gas Association have faulted EPA’s proposal for giving short shrift to the DOE study, a concern Fuller shares. “EPA does not seem to have used the DOE study information as well as it could have,” he assesses. “We are analyzing that and will try to address it in comments.”

Fuller notes EPA’s matrix for optical gas imaging (OGI) requirements according to facility size accounts for sites with an individual well, a two-well site, a small site well with equipment, and finally, larger wells. “The OGI dynamic is different for each of those, and the larger it is, the more frequent it becomes,” he outlines. “DOE’s study shows that wells producing fewer than six barrels a day are not responsible for significant emissions, but EPA is not relying on production rates. It is sticking with equipment counts.”

The proposal does take an aggressive approach to creating pathways for deploying new technologies, Fuller credits. “EPA is trying to avoid issues so that, once a technology is certified, it can be utilized by anyone, anywhere,” he explains. “The prior approach relied on an extraordinarily time-consuming and difficult site-by-site process. This streamlined mechanism will bring in new technologies.”

The OGI change also could complicate the proposal’s low-production well fugitive emissions process, Fuller continues. “The agency’s references to OGI and the matrix for the fugitive program are confusing at best,” he describes. “For a wellhead-only site with two or more wells, the operator has to perform AVO on a quarterly basis, as well as a semiannual OGI requirement. Is EPA basically saying ‘FLIR camera’ when it says ‘OGI?’ Then, the second process can create an alternative, but that carries with it the frequency from that process instead of the fugitive matrix process.

“That seems convoluted, which is a concern,” he continues. “How do these things fit together for smaller wells? The OGI alternative is worth a look for larger wells because new technologies are considered more cost-effective, but not at a frequency that it offsets the benefits. For smaller wells, the categorization breaks out according to pieces of equipment on site and number of wells, but it is unclear whether that reflects the reality on the ground.”

Controllers And Tanks

Although zero-emission pneumatic controllers figure prominently in EPA’s package, Fuller says, the proposal leaves the 2021 version of that section largely unchanged. He says the text tends not to distinguish between larger, new operations and small, existing ones.

“It may be a challenge to apply new source requirements for existing pneumatic controllers, pumps and tanks if we consider the collective amount of equipment that small operations may need to replace,” he considers.

Fuller points out that storage tanks have their own rules. EPA proposes to change the definition of pneumatic-controller-affected-facility to include all—not each of—the site’s controllers, he notes, which means the proposal addresses one set of activities associated with controllers and another set associated with tanks, as well as the generic fugitive emissions program.

“How does that fit in with the requirements of the general fugitive program?” he poses. “What are you looking for and what does that mean in terms of, for smaller wells, making sure your thief hatches are closed and the pneumatic controllers on your separator are operating properly? How much are you really gaining out of OGI if you have a routine AVO program?”

Then comes the proposal’s provisions for continuous monitoring of wells until they are plugged. “That area is also new to this process and somewhat beyond where the CAA has gone in the past,” Fuller remarks. “It also may compete with states’ bonding requirements for the same operation. How does that fit together?”

Super Emitters

EPA notes that its supplemental proposal also seeks to establish a super-emitter response program that will leverage data from approved third parties with expertise in certain remote methane detection technology to quickly identify large-scale emissions for prompt control. “Studies show that large leaks from a small number of sources are responsible for as much as half of the methane emissions from the oil and natural gas industry, along with significant amounts of smog-forming VOCs,” EPA states.

According to Fuller, the super emitter threshold is 100 kg an hour, or about 130 Mcf a day. Since the average U.S. low-output gas well produces about 22 Mcf/d, it is arguably impossible for those wells to leak 130 Mcf/d. “The super-emitter program is going to be a larger well issue,” he maintains.

The proposal’s authorized third-party detectors will require government certification, Fuller says, likening them to people who assist meteorologists during severe weather alerts. “Think of tornado chasers: people who are certified to use certain technologies,” he compares. “In this case, they are limited to technologies such as aircraft, satellites and drive-by monitoring. If they detect a leak remotely and notify the operator and regulators that they have found super emitters, the rule triggers response activities with specific time frames.”

Although Fuller says EPA’s proposal appears to be crafted to prevent third-party detectors from trespassing to obtain their readings, he suggests that such risks may remain. “There are also concerns about harassing operators with false claims,” he observes. “The rule includes language to revoke the certification of people who provide false information.”

Nevertheless, Fuller warns, the sort of sampling collected in such short-term, “drive-by” remote monitoring can be less than representative. “Past studies show some of those mobile tests may only have 10 minutes worth of data,” he details. “There is a need to consider the time window so an anomalous spike does not skew the data.”

Associated Gas

According to Fuller, the proposal’s section on associated gas management prioritizes directing it to sales outlets, or secondarily, utilizing the gas on site or injecting it. “Alaska has injected gas for many years,” he observes. “If you do that, the gas may be available for sales in the future.”

Absent all those options, he continues, operators may flare gas through closed systems. “There are other parts of the rule that increase the stringency of managing flares or combustion devices to make sure they function continuously and oxidize the methane to carbon dioxide,” Fuller notes. “Making sure it combusts properly always has been a challenge that depends on the consistency of the volume and its heating value.

“Technical minds will have to examine it closely, but the idea is that even sites that use natural gas as a supplemental fuel source must keep the flare continuously operational,” he assesses.

Along with processing and transmission, other aspects of the rule deal with the liquids unloading process, Fuller mentions, with the goal of minimizing the need to vent gas and stipulating best management practices when venting must occur. Another section focuses on storage vessels and has seen considerable changes since the 2021 version. The new supplement seeks to clarify definitions for storage vessels and what constitutes modifications to them, Fuller details.

“EPA is trying to move away from grappling with vapor space connections as a criteria,” he reports. “Now the agency is focusing on liquid links.”

State Authority

The new proposal raises compatibility questions with the process outlined in CAA Section 111(d) through which states can become the primary authorities for implementing and enforcing the proposed requirements, Fuller warns. He says this section was designed to deal with the rare instance of a pollutant that was neither a criteria pollutant, such as VOCs and sulfur oxides, or a hazardous air pollutant, such as benzene.

In the structures for both VOCs and HAPs, he explains, a state’s failure to attain ambient air quality standards is the regulatory driver that forces states to craft regulatory plans for areas of nonattainment. Historically, Fuller says, the CAA regulatory structure guides states’ actions regarding reasonably available control technologies for existing sources. Congress created Section 111(d) for a small universe of pollutants, allowing for nationwide control of existing sources with the advent of a new source standard.

“Section 111(d)’s significance changed when EPA classified GHGs as pollutants,” he recounts. “GHGs are pervasive. Under the prior 111(d), it may have covered 25 operations across the country. Even when EPA was looking at existing utility electric generators, that still would apply to maybe 150 coal-fired boilers. This proposal is looking at a million oil and gas wells.

“It’s a totally different framework under a program that never really envisioned such a large scope,” he continues. “EPA has come up with a structure that is somewhat modeled after a state implementation plan (SIP) for ozone nonattainment, in which a state has a certain amount of time to develop new regulations and a certain amount of time to implement them.”

In the instance of ozone nonattainment, Fuller details, EPA evaluates and determines whether to accept a SIP, including how it adapts EPA guidelines for reasonably available technology/controls. “In this case, EPA puts out its Quad O(c) Emissions Guidelines for which it basically has a model regulatory structure,” he relates. “If the state adopts them as written, it gets EPA approval.”

However, he notes, states such as Colorado, Pennsylvania and California already have methane regulations, while many others already have VOC rules. “EPA gives them a template, but states have been moving differently on this issue,” Fuller observes. “How do those state regulations mesh with the proposed rule? What does it take for EPA to approve them?”

The rule gives states 18 months to develop the regulatory structure for a complicated web of activities and operations that includes multiple sources of varying types. Then, compliance must be completed within three years.

“But do the state regulatory development requirements work that fast?” Fuller poses. “Before a rule can take effect, states all have their own parallel hearings, drafts, proposed rules, hearings, final rules, reproposed rules and more. Is 18 months enough?”

Further confounding the matter, he considers, is a 111(d) provision that gives states the right to alter the emission guidelines, which are based on the NSPS technology requirement. “It’s not reasonably available control technology, but a best system of emissions reduction, which is a higher standard than is typical for existing sources,” Fuller details. “Section 111(d) has a provision that allows a state to alter the requirements based on a facility’s remaining useful life and other factors.”

EPA offers states a series of considerations for determining whether a site qualifies for looser requirements. However, Fuller points out, the question of remaining useful life for an oil and gas production facility is subject to many unpredictable variables. “That’s a tricky question,” he considers. “A lot of 1 bbl/d wells can run a long time or shut down tomorrow.”

The customary approach requires a state to assess whether EPA’s requirements will affect the remaining useful life of the state’s existing facilities and then allows states to adjust according to how they weigh environmental impacts against the rule’s economic burden, Fuller explains. “EPA turns this on its head in this proposal and says the state will look at a facility and determine its remaining useful life and, if it’s shorter than EPA’s determined payback period, the state can adjust the rule,” he says. “Facilities under that scenario would face less stringent standards during their remaining useful lives, but basically must shut down after that.”

The interpretation of the remaining useful life authority may be very significant for some smaller wells, Fuller comments. How much the interpretation matters will depend on the collective burden imposed by the final fugitive emissions program, pneumatic controller and storage tank requirements, he indicates.

“I assume EPA is looking for a state to come up with a procedure as to how it will make these decisions and EPA will judge if that procedure is consistent with its view of its authority,” he evaluates. “However, reading the proposal explanation suggests that EPA is asking the state to come up with a list of sites to which it will give remaining useful life flexibility. That may prove unfathomably complicated in a state such as Texas, which has more than 200,000 low-production wells.”

IRA Methane Fee

According to Fuller, EPA has attempted to harmonize its proposal with the methane fee provision in the Inflation Reduction Act. The law contains a provision that exempts operators in compliance with EPA’s rules according to a three-tiered assessment:

• The first exempts operators with CO₂-equivalent emissions beneath 25,000 tons a year across a basin.
• The second threshold, for production operations, applies if methane emissions fall below 0.2% of natural gas sales.
• The third threshold specifies that operations above that 0.2% still may be exempt if they comply with standards at least as rigorous as EPA’s 2021 proposal.

“Obviously, the question of whether you have accurately calculated emissions and sales are auditable events, through which EPA can enforce penalties,” Fuller notes. “A producer’s tax is based on the emissions above 0.2%. EPA says if these rules are finalized as proposed and the states adopt them, operators should be able to benefit from that carve-out. But that raises issues going back to Subpart W, which is the basis for calculating those emissions and making those judgements, for which there are numerous accuracy issues.”

Comments And Hearings

EPA indicates it will accept comments on the supplemental proposal until Feb. 13, adding that it will host virtual trainings to help communities, tribes and small businesses understand the supplemental proposal and how to participate in the public comment process. The agency says it will hold a virtual public hearing Jan. 10 and 11. EPA expresses plans to issue a final rule in 2023.

Fuller deems the Feb. 13 comments deadline a welcome choice. “Providing roughly 90 days probably eliminates the recurring problem in which commenters often have to ask for an extension,” he clarifies. “It’s the usual 30 days that prompts us to say we need 90 and EPA gives extensions. The agency has given us three months to hammer through this.”