ConocoPhillips says EPA’s methane rule has elements that are “unworkable”

HOUSTON — The EPA’s methane rule has elements that are “unworkable,” the head of oil giant ConocoPhillips said Tuesday.

The EPA rule is meant to crack down on leaks of methane, a potent greenhouse gas that is also one of the main products of the oil industry.

ConocoPhillips Chief Executive Officer Ryan Lance said EPA’s attempt to charge companies for the methane that leaks from their oil wells, pipelines, storage tanks and other infrastructure would run into problems with how to accurately measure the emissions.

On December 2, 2023, the U.S. Environmental Protection Agency (EPA) announced a Final Rule under the Clean Air Act that will sharply reduce methane emissions from the oil and gas sector. The rule applies to sources involved in crude oil production (which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other form of transportation) and natural gas production, processing, transmission and storage (which includes the well and extends to, but does not include, the local gas distribution company custody transfer station (up to the “city-gate”)).

“New” and “Existing” Sources

Building on the scaffolding of two existing rules (i.e., the 2012 new source performance standards (NSPS) for volatile organic compounds (VOCs) and the 2016 NSPS for methane and VOCs), the Final Rule consists of (1) 2023 NSPS for methane and VOCs emissions from new, modified and reconstructed sources and (2) emissions guidelines for states to follow in developing implementation plans that will cover existing sources.

Any “new” sources, i.e., those constructed, modified or reconstructed after December 6, 2022, will need to comply with the 2023 NSPS.

Any “existing” sources, i.e., those constructed before December 6, 2022, will be subject to standards promulgated pursuant to the state implementation plans. The EPA’s guidelines for existing sources serve as a model for states to implement. States may either adopt standards set forth in the guidelines or develop their own standards that are at least as strict as the new NSPS.

States have two years from the rule’s effective date (60 days after the Final Rule is published in the Federal Register) to submit implementation plans to the EPA, and companies have three years from this submission date to comply (i.e., up to five years for existing sources to achieve compliance). That said, states may craft plans that have shorter compliance timelines.

Covered Sources

The Final Rule, for the first time, extends the categories of sources covered by methane and VOC emission standards to flaring (identified as “associated gas” in the rule), compressors at centralized tank batteries, liquids unloading and process pumps (at both natural gas processing segments and natural gas gathering and boosting compressor stations).^[1]

Requirements of the Final Rule

As part of President Biden’s agenda to tackle climate change, the Final Rule announcement came after two years of revising and updating previous proposals. Some of the more salient requirements of the Final Rule include the following:^[2]

1) Flaring

The Final Rule phases out most routine flaring of natural gas from oil wells. The rule establishes five categories of wells:

New wells where construction is commenced 790 days after the Final Rule is published in the Federal Register;
New wells where construction is commenced between 60 days after publication and 790 days after publication;
New wells where construction is commenced between December 6, 2022, and 60 days after publication;
Existing wells with associated gas emissions greater than 40 tons per year (tpy) of methane; and
Existing wells with associated gas emissions less than 40 tpy of methane.

For the first category, routine flaring is prohibited.

For the second category, third category and fourth category, routine flaring is prohibited unless it is documented annually that alternatives to flaring are not technically feasible, in which case the associated gas can be routed to a flare or other control device that achieves at least a 95% reduction in greenhouse gas (methane) and VOC emissions. For the second category, a second infeasibility determination may not extend beyond 24 months from the effective date.

For the fifth category, routine flaring is not prohibited.

Alternatives to routine flaring (when it is prohibited) include routing associated gas to a sales line; using the gas for another useful purpose that a purchased fuel, chemical feedstock or raw material would serve; or recovering the gas from the separator and reinjecting it into the well or injecting it into another well.

2) Leak Detection and Repair; Innovative Leak Detection Technology

The Final Rule promulgates leak detection and repair requirements that differ based upon whether subject facilities are well sites, centralized production facilities or compressor stations. Well sites are broken into a few categories:

Single wellhead sites (that are not co-located with major production and processing equipment) require quarterly audible, visual and olfactory (AVO) inspections. Owners and operators have 15 days from detecting a leak to initiate repairs and must complete those repairs within 15 days after the first repair attempt.
Multiple wellhead sites (that are not co-located with major production and processing equipment) require semiannual optical gas imaging (OGI) inspections (or EPA Method 21 inspections^[3]) and quarterly AVO inspections. Owners and operators have 30 days from detecting a leak to initiate repairs and must complete those repairs within 30 days after the first repair attempt.
Wellhead sites co-located with major production and processing equipment, including one or more controlled storage vessels or tank batteries, control devices or natural gas-driven process controllers or pumps, and centralized production facilities require quarterly OGI inspections (or EPA Method 21 inspections) and bimonthly AVO inspections. Owners and operators have 30 days from detecting a leak to initiate repairs and must complete those repairs within 30 days after the first repair attempt.

Compressor stations must perform quarterly OGI inspections (or EPA Method 21 inspections) and monthly AVO inspections. With respect to leaks detected using AVO inspections, owners and operators have 15 days from detecting a leak to initiate repairs and must complete those repairs within 15 days after the first repair attempt. With respect to leaks detected using OGI or EPA Method 21 inspections, owners and operators have 30 days from detecting a leak to initiate repairs and must complete those repairs within 30 days after the first repair attempt.

Under the Final Rule, owners and operators may replace traditional leak detection programs (i.e., using EPA Method 21 inspections or OGI) with advanced measurement technologies such as on-site sensor networks and aerial flyovers using remote-sensing technology. These technologies need to be approved by the EPA in advance when an owner or operator submits a monitoring plan.

3) Super Emitter Program

In response to studies showing that emissions from a small number of sources are responsible for as much as half of the methane emissions from oil and gas operations, the EPA included the “Super Emitter Program” in the Final Rule.

Under the Program, the EPA will certify third parties to monitor for super emitter events (i.e., a release of more than 100 kg (220.5 lbs.) of methane per hour). The third parties will report any super emitter events to the EPA (and not directly to the owner or operator). Upon receipt of a report by a third party, the EPA will first verify the super emitter event and, after verification, notify the owner or operator.

Upon receiving notice from the EPA, the owner or operator will be required to investigate the event within five days of the notice and report the results of the investigation to the EPA within 15 days of the notice. The report must include key information about the super emitter event, including identifying the source of the subject emissions, providing a short narrative on how the owner or operator intends to repair the release and providing a timeline for achieving compliance with the relevant standards.

In response to industry concerns, the Final Rule does not empower third parties to enter an owner or operator’s well site or other facility. Instead, the third parties are limited to EPA-approved remote-sensing technologies, such as those used on satellites or in aerial surveys.

To keep the public informed, the EPA will make the super-emitter data publicly available.

4) Eliminating or Minimizing Emissions from Equipment

The Final Rule includes emission reductions requirements for specific source types and processes, including the following:

Storage Vessels. Under prior rules, emission limits on storage tanks were calculated on an individual tank basis. The Final Rule adds emission limits on “storage tank batter[ies].” A group of storage tanks that, in the aggregate, emits VOCs in excess of six tpy or methane in excess of 20 tpy must reduce emissions of both by 95%.

Owners and operators may use an internal or external floating roof for tanks or tank batteries that are not co-located at a well site or centralized production site (and therefore are presumably without any capacity for flaring emissions). Any such control devices used must be monitored, recorded and reported to ensure that it is continuously achieving the required 95% reduction.

Well Liquids Unloading. With respect to a liquid unloading event, facilities must employ best management practices to minimize or eliminate methane and VOC emissions. Owners and operators may also comply by reducing VOC emissions and methane emissions from each gas well liquids unloading event by 95% by routing emissions to a control device through a closed vent system.

Process Pumps. Pumps must have a VOC and methane emissions rate of zero, except pumps located at sites that do not have access to electricity and have fewer than three diaphragm pumps. For pumps that qualify under the exemption, owners and operators must control emissions by routing emissions to a process if a vapor recovery unit (VRU) is onsite. If a VRU is not onsite, emissions must be reduced by 95%.