Proposed EPA methane regulations will add costly requirements to upstream operations

Feb. 1, 2016
The US Environmental Protection Agency (EPA) has proposed regulations for methane and volatile organic compound (VOC) emissions from the oil and gas industry that would place a number of new requirements on upstream operations, including capturing or combusting emissions during well completions, monitoring for fugitive emissions from equipment leaks, and making needed repairs.

Larry Nettles
Vinson & Elkins LLP
Houston

Corrine Snow
Vinson & Elkins LLP
New York

The US Environmental Protection Agency (EPA) has proposed regulations for methane and volatile organic compound (VOC) emissions from the oil and gas industry that would place a number of new requirements on upstream operations, including capturing or combusting emissions during well completions, monitoring for fugitive emissions from equipment leaks, and making needed repairs. EPA also proposes to change how an oil and gas source is defined in ways that could put additional permitting burdens on upstream operations. Collectively, these regulations and changes could have widespread, costly, and time-consuming effects on upstream oil and gas operations.

On Sept. 18, 2015, EPA published its proposed new source performance standards for methane and VOC emissions for the oil and gas sector in the US Federal Register, alongside a proposal to redefine an oil and gas source. The proposed rules expand VOC air regulations to cover methane emissions from both oil and gas well completions, and would require owners and operators to install new control equipment, conduct fugitive emissions tests, and replace leaking equipment at certain hydraulically fractured oil and gas wells. Once adopted, these changes will apply to any covered source built or modified retroactive to Sept. 18, 2015, regardless of when the rule is finalized.

While these standards technically only apply to new or modified sources, EPA is using a provision of the Clean Air Act that would also give it the ability to extend them to existing oil and gas sources in the future. The agency already regulates VOC emissions from certain oil and gas operations through its Subpart OOOO Clean Air Act rules. Now it's proposing expansion of these rules to cover additional oil and gas operations and create new methane standards for that expanded list of operations.

EPA explained that it proposed the expansion because it determined methane is a greenhouse gas, and the oil and natural gas industry is one of largest US methane emitters.

The controls required by Subpart OOOO already indirectly resulted in a large reduction of methane emissions, casting doubts on whether a separate methane rule is even necessary.

Well-completion regulations

Natural gas wells completed with hydraulical fracturing already are subject to the Subpart OOOO VOC regulations, and also would have to meet the new methane requirements. Gas wells that already are in compliance with the VOC regulations, however, should be able to meet the new methane rules without additional upgrades or controls. Oil wells having a gas-to-oil ratio of more than 300 scf/bbl will be covered under both the VOC and newly added methane requirements. Coverage includes equipment such as pneumatic controllers, pumps, and storage tanks at oil and gas wellsites.

Well completions done as part of a refracturing operation are not subject to this portion of the proposed rule as long as they meet Subpart OOOO regulations, but may still be subject to the new fugitive-emissions requirements.

As with Subpart OOOO regulations, the EPA proposal divides wells into two subcategories. Subcategory 2 applies to wildcat and delineation wells, and Subcategory 1 to all other wells. Wildcat wells are defined as wells drilled outside known fields or as the first wells drilled in an oil or gas field where no other production exists. Delineation wells are wells drilled to determine the boundary of a field or producing reservoir.

The proposal would require owners and operators of Subcategory 1 wells to use reduced-emissions completions (RECs) to limit methane and VOC emissions and maximize natural gas recovery from hydraulically fractured oil wells.

RECs use a separator to remove gas and liquid hydrocarbons from the flowback for treatment and use or sale. EPA's proposal would require RECs be used in combination with a completion combustion device, such as a flare. The proposal does not require RECs where use of a separator is "technically infeasible."

For Subcategory 2, the proposal does not require owners or operators to use RECs, but would require them to use a completion combustion device.

Under the proposal, the initial flowback stage for Subcategory 1 wells begins with the onset of flowback and ends when the flow is routed to a separator.

No gas controls are required during the initial flowback stage, but operators must route the flowback to a separator unless it is technically infeasible for a separator to function.

The second flowback stage, the separation flowback stage, begins when the separator can function. During this stage, operators must route all salable quality gas from the separator to a flow line or collection system, reinject the gas into the well or another well, use the gas as an on site fuel source, or use the gas for another useful purpose.

If it is technically infeasible to route the gas this way, or if the gas is not of salable quality, operators must combust the gas unless combustion creates fire, safety, or environmental hazards.

The flowback period ends in one of two ways. Either the well is shut in and the flowback equipment is permanently disconnected from the well, or production begins.

Gas cannot be directly vented during separation flowback, and all flowback liquids must be routed to a well-completion vessel, a storage vessel, or a collection system during both flowback periods.

Well completions done as part of a refracturing operation would not be subject to these flowback requirements if they comply with current Subpart OOOO regulations, but may still be subject to new fugitive emissions requirements.

For Subcategory 2 wells, the proposal requires flowback be routed into well-completion vessels and use of a separator unless it is infeasible. Recovered gas must be captured and directed to a completion-combustion unit unless combustion creates hazards.

In addition to these specific requirements, the proposed rule places the onus on operators "to safely maximize resource recovery and minimize releases to the atmosphere during flowback and subsequent recovery." This vague language could create potential compliance risks for operators.

Fugitive emissions

In the proposed regulations, a wellsite is defined as "one or more areas that are directly disturbed during the drilling and subsequent operation of, or affected by, production facilities directly associated with any oil well, gas well, or injection well and its associated well pad." Wellsites include all ancillary equipment in the immediate vicinity of the well necessary for production, such as separators, storage vessels, heaters, and dehydrators.

All new wellsites and wellsites modified after Sept. 18, 2015, are subject to the new regulations. The requirements also might apply to existing sources in the future.

These requirements would not apply to low-production wells where the combined oil and natural gas production is less than 15 boe/d averaged over the first 30 days of production. It also would exclude existing wellsites where additional drilling activities other than fracturing or refracturing (such as well workovers) are conducted on an existing well. Wellsites that only contain wellheads without ancillary equipment are not subject to the fugitive-emissions monitoring requirements.

EPA's proposal would require fugitive-emissions surveys with optical gas imaging (OGI) at new and modified well sites and compressor stations. Operators must conduct an initial survey within 30 days of commencing operation and semi-annual follow-up surveys.

The proposal would require operators to replace or repair the sources of any detected fugitive emissions "as soon as practicable, but no later than 15 days after detection." After the repairs, the equipment must then be resurveyed within 15 days to ensure the repair has been successful. Operators also would be required to develop and implement company-wide monitoring plans to comply with these fugitive-emission requirements.

The initial OGI survey of fugitive emissions components at the wellsite would include valves, connectors, open-ended lines, pressure relief devices, closed vent systems, and thief hatches on tanks.

For new sites, the initial survey would occur within 30 days of the end of the first well completion or upon the date the site begins production, whichever is later. For modified wellsites, the initial survey would be required within 30 days of the modification. A modification occurs whenever a well is added to the site, or anytime an existing well is fractured or refractured.

Under the proposal, survey frequency would decrease from semiannually to annually for sites that find fugitive emissions from less than 1% of their fugitive emission components during two consecutive surveys, but the frequency would increase from semiannually to quarterly for sites that find fugitive emissions from 3% or more of their fugitive emission components during two consecutive surveys. Monitoring frequency would continue to increase and decrease depending on results of subsequent surveys.

EPA also is considering an alternative method of monitoring, known as EPA Method 21 for resurveys after repairs.

OGI uses an imaging device similar to a camera that is pointed at components while the display is monitored to determine if a leak is present. Method 21 can be far more time-consuming than OGI cameras as it requires operators to slowly move a probe from a handheld instrument in close proximity to the portion of a component that may leak. Studies have shown that OGI can monitor 1,875-2,100 components/hr, while Method 21 can only monitor about 700 components/day.

But Method 21 also detects leaks at a much lower level (500 ppm) than OGI, which may not detect fugitive emissions below 10,000 ppm. Method 21, therefore, is likely to result in additional equipment replacements and repairs.

Figs. 1 and 2 illustrate the difference in compliance costs at wellsites when Method 21 is used to detect emissions at the 500 ppm level with those when OGI is used.

Source definition

EPA's proposal also contains new definitions of source and aggregation, which could subject the upstream industry to costly and time-consuming air permit requirements for construction and operation. The proposal would apply to more than just methane and VOC emissions, and could affect the applicability of major source-permitting programs for upstream activities.

EPA's current permitting rules under the Clean Air Act define a source as all activities under common control, within the same major industrial category, and located on "contiguous or adjacent" properties. The agency is proposing amendments to its Prevention of Significant Deterioration (PSD), Nonattainment New Source Review (NSR), and Title V permitting-program regulations to address its interpretation of adjacency, which courts have invalidated in a sequence of recent appellate decisions.

Under EPA's preferred proposed option, a source would include all emitting activities on a property, and only those sources "contiguous or located within a short distance of one another" would be considered adjacent.

Properties within ¼ mile should be considered a single source. Texas, Pennsylvania, Oklahoma, and Louisiana also use ¼ mile under their single-source state guidance. EPA is, however, looking into whether another distance, such as ½ mile, is more appropriate.

Under EPA's second option, an oil and gas source would again include all the emitting activities on a property, and properties within a proposed distance of ¼ mile, and also sources beyond ¼ mile that are "functionally interrelated" to the source.

EPA has proposed that functional interrelatedness might be shown by a physical connection, such as a pipeline between equipment. Other factors to determine interrelatedness could include the delivery of product from one group of equipment to another, or whether one group of equipment is dependent upon the operation of another.

The agency acknowledged that its source-definition proposal could place additional permitting burdens on operators and regulators by requiring more sources to apply for a PSD air permit, which takes significantly longer to apply for and review than a minor NSR permit.

EPA estimates that a major source permit typically takes at least 1 year to process. This could become even longer if the "functional interrelatedness" definition is adopted, as it would require the agency to make case-by-case determinations for sources separated by more than ¼ mile, and could give advocacy groups an additional opportunity to challenge projects.

EPA estimates the total industrywide capital cost of complying with the proposed rule will be $170-180 million in 2020 and $280-330 million in 2025. EPA estimates the total annualized engineering costs of complying with the proposal will be $180-200 million in 2020 and $370 -500 million in 2025.

Despite these costs, EPA concludes that the proposed rule will have a net economic benefit of $35-42 million in 2020 and $120-150 million in 2025. EPA determined net benefits by considering revenues it expects to be generated from selling the captured methane.

EPA has valued the methane at about $4/Mcf and estimates additional natural gas recovery of 8 bcf in 2020 and 16-19 bcf in 2025 as a result of implementing the proposal. Given the current state of the oil and gas market, these estimates are speculative at best.

The agency's cost analysis is based partially on a model called the Social Cost of Methane, which EPA used to place a present-dollar value on projected future benefits to the climate from reduced methane emissions. Based on this model and a discount rate used in cost-benefit analysis, every ton of methane emissions prevented was worth $1,100 in 2015. EPA estimates climate benefits to be $200-210 million in 2020 and $460-550 million in 2025.

The authors
Larry Nettles ([email protected]) is a partner in Vinson & Elkins' Houston office. He is co-chair of the firm's energy and infrastructure practice group, and chair of its shale and hydraulic fracturing task force. He earned his JD from the University of Texas School of Law in 1981.
Corinne Snow ([email protected]) is an associate in Vinson & Elkins' New York office. She focuses on environmental law, with an emphasis on regulatory compliance, environmental litigation, and enforcement defense. She earned her JD from Harvard Law School in 2012.