Emissions from the tank battery and downstream flares and combustors are significant contributors to an upstream production site’s environmental footprint. As a result, reducing emissions and eliminating the practice of routine flaring of tank vapor is coming under increasing pressure, and critical to the long-term sustainability of the upstream oil and gas industry.
Understanding how different strategies for reducing emissions and flaring impact regulatory compliance, economic returns and operational efficiency is important to achieving both environmental and financial performance goals.
The regulatory environment concerning air emissions across oil and gas producing areas of the United States is complex and rapidly changing. It affects how operators plan for and mitigate production-related emissions at both existing and future operations.
In this first article on the subject, our focus is on emission permits requirements in different oil producing states, including Colorado, New Mexico, North Dakota and Texas. Additionally, we cover the important distinction between emission reduction measures achieved with process equipment versus control equipment.
Going forward, we plan to publish regulatory updates on a quarterly basis to help those with an interest in this critical aspect of oil and gas production operations stay up to speed. There are rulemakings in process in several states that will be in place and impactful later this year and early next.
EPA Proposes Increased Regulation of Methane and Emissions
The EPA recently issued a proposed rule outlining amendments to current Clean Air Act regulations intended to reduce further emissions of methane and other substances. and has indicated their intent to expand similar rules to sites not previously regulated by the EPA (“existing sites”, or those previously grandfathered under OOOO and OOOOa). The proposed rule does not contain any specific regulatory language and, as a result, EPA has signaled their direction but not indicated the precise nature of the changes.
The Department of the Interior is expected to release their own set of air regulations affecting federal lands in the next few months. We will cover federal air emission rules in detail in an upcoming article.
Disclaimer: EcoVapor is providing this information for educational purposes only and should not be relied on for obtaining permits. This material is based on current public information that we consider reliable, but we do not represent it as accurate or complete, and it should not be relied on as such. This information may be incomplete or become out of date. EcoVapor makes no commitment to update this information. We encourage you to seek professional counsel before making any business decisions affected by federal, state, or local regulations.
Three Types of Air Permits
Apart from Texas, to which we will return in a moment, states typically issue three types of air permits, determined by the anticipated level of emissions at a site and whether its location is designated an Attainment Area or Nonattainment Area.
The Environmental Protection Agency (EPA) is responsible for setting and implementing the National Ambient Air Quality Standard (NAAQS), and the Clean Air Act requires EPA to determine if a given area of the country meets the standard. Typically, ozone is the NAAQS of concern, and rules are made to reduce emissions of Volatile Organic Compounds (VOCs) or Oxides of Nitrogen (NOx) in those areas.
States and tribes submit recommendations to the EPA as to whether an area is attaining the standard, based on air quality data collected from ambient air monitoring stations.
If the reported air quality meets or exceeds the national standard, it is designated an Attainment Area. Locations failing to meet the national standard are called Non-Attainment Areas.
VOC Potential to Emit (PTE) emissions are calculated for both controlled and uncontrolled emissions and compared to threshold levels set by the region’s attainment status.
Commonly issued permit types are:
- True Minor – where both uncontrolled and controlled PTE levels are less than the Major Source threshold for that area.
- Synthetic Minor – where uncontrolled PTE is above the major source threshold (25-250 tons/year, depending on attainment status) but controlled PTE is below the threshold.
Additionally, if a site’s emissions exceed a major source threshold, a Title V air permit is required before a site can operate. Title V Operating permits codify all applicable requirements for a source, such as enforceable emission limits, compliance schedules, monitoring, reporting, and record-keeping requirement into one permit.
As you might expect, the higher the emissions at a site, the more onerous the permitting, record keeping, and reporting burden becomes.
The table below summarizes the air permit types and their differences on key factors.
Focus | True Minor | Synthetic Minor | Title V |
Permit(s) Obtained | Via General Permits and Permits by Rule | Via General Permits and Permits by Rule | On site-by-site basis, slow, requires EPA approval |
Permit Focus | Emission limits, not equipment | Emissions and equipment | Monitoring and compliance |
Records and Reporting | Minimal | Significant | Onerous |
A General Permit is issued prior to construction and may be applied to a number of similar sites or emission sources, to help streamline the application process.
A Permit by Rule is written to cover any site or source falling within a designated category, removing the need for an individual permit. Instead, the applicant submits a Notification of Coverage to the reviewing authority declaring that the site to be constructed meets the applicable category definition.
Potential Emissions – The Importance of Process versus Control
When determining Potential to Emit (PTE) levels, the regulations distinguish between emission reductions achieved using process equipment from those achieved downstream using control equipment.
Only PTE levels achieved via process equipment (Uncontrolled PTE) can qualify the site for a True Minor air permit.
Controls implemented downstream of process equipment to further reduce the potential for emissions affect the Controlled PTE level, which can allow a site that would otherwise be classified as a Major Source Emitter (Title V Permit) to qualify for a Synthetic Minor air permit instead.
If the combination of process and control technologies is unable to reduce potential emissions below the major source threshold, the site may only operate under a Title V permit – for example, at a refinery or a production site in a Nonattainment Area.
The key takeaway here is that potential emission reductions achieved using process equipment are more impactful (and more valuable) than those achieved with control equipment later in the process.
So, how does the EPA decide what equipment is considered ‘process’ and what is considered ‘control’?
The verdict is based on three questions:
- Is the primary purpose of the equipment to control air pollution? If yes, it is designated as control equipment.
- If the equipment recovers product, does the revenue (or savings) generated exceed the cost of operating the equipment? If yes, it is designated as process equipment.
- Would the equipment be installed even if no air quality regulations were in place? If yes, it is designated as process equipment.
The key criterion is therefore profitability. If the recovery process pays for itself or makes a profit, it’s considered process equipment and can help qualify the site for a True Minor permit.
What About Vapor Recovery Units? (VRU)
As the leading supplier of complete tank vapor recovery systems, EcoVapor is especially interested in how states interpret these EPA guidelines when it comes to vapor recovery towers (VRT) and vapor recovery units (VRU).
Except for Texas, states generally consider VRT/VRU systems as process equipment, while tank vapor recovery systems are initially considered control equipment.
However, New Mexico uses an Air Emission Calculation Tool (AECT) to determine on a site-specific basis whether a tank-based system is process or control, and each of Wyoming, North Dakota, and Federal/Indian Lands defaults to control but agree that the economics can be considered to reclassify tank-based systems as process equipment.
The Texas Commission on Environmental Quality allows for up to 100% PTE reduction using a vapor recovery unit, but as control equipment. The 100% PTE reduction includes oxygen control and other requirements (see TCEQ’s “Vapor Recovery Unit Capture/Control Guidance”).
At the State Level
Colorado
Air quality regulations in Colorado are primarily set by the Colorado Department of Health and Environment’s (CDPHE) Air Pollution Control Division (APCD). The Colorado Oil and Gas Conservation Commission (COGCC) has separate but parallel responsibilities to reduce waste and protect the environment.
Recent developments of particular interest:
- The COGCC recently approved a 2,000-ft setback for all new oil and gas sites, measured from the edge of the proposed location to the nearest occupied structure. This effectively requires a one square mile site for each oil and gas location.
- COGCC rules allow tank vapors to be treated differently from other gas generated at an oil and gas site, and the flaring of tank vapors is not considered “waste”. Consequently, COGCC has pushed authority over tank venting/flaring to the CDPHE (Colorado Department of Public Health and Environment).
- The Denver Metro area and Front Range (DMFR) Non-Attainment area is expected to be downgraded in 2022 from “serious” to “severe.” This will reduce the Major Source Threshold for VOCs and NOx from 50 tons/year to 25 tons/year.
- In a “double-whammy” for the affected areas, the EPA announced on November 17, 2021 that they were expanding the Non-Attainment area to include northern Weld County. This will require some locations to reduce emission levels from 100 tons/year to less than 25 tons/year to avoid a Title V permit requirement.
- Tank truck loading alone is estimated to generate 10 tons/year of VOC at a typical production location. A new section (II.C.5.a) requires operators to control emissions from the loadout of hydrocarbon liquids from controlled storage tanks to transport vehicles, either by capturing emissions through vapor collection and return to the storage tank or by routing the vapors to air pollution control equipment.
- As mentioned earlier, Colorado has ‘hard-wired’ its interpretation of tank-connected vapor recovery units as control equipment, at least for now.
New Mexico
Regulations in New Mexico stem from two agencies: the New Mexico Oil Conservation Division (NMOCD) within the Energy, Minerals, and Natural Resources Department (EMNRD), and the Air Quality Bureau (AQB) within the New Mexico Environmental Department (NMED).
Rules written by NMOCD are finalized and in effect starting April 1, 2022, while rules by the AQB have been drafted and filed but not yet implemented.
Key implications of the NMOCD rules are:
- A target of 98 total gas capture by year-end 2026, including low-pressure gas such as tank vapors (https://www.srca.nm.gov/parts/title19/19.015.0027.html).
- All new sites must have a Gas Capture Plan.
- Operators can earn emission credits by using ALARM technologies (Advanced Leak And Repair Monitoring), for which EcoVapor systems may qualify (the state allows site-by-site determination of whether a VRU system is considered process or control equipment).
- Venting and flaring reports are mandatory, including the cause (e.g., oxygen contamination).
NMED is focused on VOC and NOx emission reductions, trying to avoid any areas of non-attainment. Several counties are currently within 95% of the 70 parts per billion Federal ozone standard (or exceed it), including Eddy and Lea counties in Southeast New Mexico.
If the area is reclassified as non-attainment due to ozone, Major Source Thresholds to avoid Title V permits will decrease from 250 tons/year to 100 tons/year and larger sites will no longer be able to flare.
The most significant items within the proposed AQB rules are that:
- All equipment must have EMITT tags with operating data and capacity details.
- All new and existing storage tanks with an uncontrolled PTE greater than 2 tons/year of VOCs are subject to regulation requiring 95-98% VOC capture and control, depending on the age and PTE of the tank.
- Owners and operators of existing and new liquid transfer operations shall use vapor balance and recovery to control 98%+ of vapors generated when transferring liquids between tanks and transfer vessels.
A second draft of the AQB rules is awaiting approval by the end of 2021.
North Dakota
Wellsite emissions are regulated by the North Dakota Industrial Commission (NDIC), oil and gas division.
The hot issue in North Dakota is flaring reduction, for which the state has a poor reputation. The current Governor (who has an oil and gas background) is keen to find solutions that do not adversely affect the state’s primary revenue stream.
Key issues in North Dakota are:
- Total gas capture must be 91% or more. Some sites may operate below 91%, provided company-wide performance remains at or above 91%.
- The NDIC reports state-wide gas capture at 94%, although locations in their first 12 months of production/flaring are not included in the calculation.
- The Fort Berthold Indian Reservation (FBIR), home to the Mandan, Hidatsa and Arikara Nation tribes covers a large swath of prime Bakken acreage. The EPA methane rule reversal described earlier will impact FBIR operations.
- SB2328 passed during last year’s legislative session provided a production tax credit of up to $6,000 per well to offset the cost of gas capture systems. The initiative was primarily aimed at unlocking stranded gas but could be renewed and extended to additional gas recovery technologies if the program is effective during its initial two-year life.
Texas
The Texas Commission on Environmental Quality (TCEQ) approaches air quality regulation in a slightly different way.
In general, if PTE is less than 25 tons/year of VOC, the operator can obtain a Permit by Rule – the least restrictive permitting regime – and a dispensation to begin operating without prior permit approval if the site is handling sweet gas.
If the VOC PTE is above 25 tons/year but less than 100 tons/year, a Standard Permit application is required, which must be reviewed and approved before operations commence.
The TCEQ also provides a 95% PTE credit whenever a compressor is used to capture vapor, which can be increased to 100% if additional criteria are met, such as tank pressure monitoring and steps to mitigate oxygen ingress.
Key issues in Texas are:
- Areas around Houston, Dallas-Fort Worth, and San Antonio have been designated as Non-Attainment areas based on eight-hour ozone levels. Even though ozone levels have been improving, they remain above current EPA limits. TCEQ has served notice that all three Non-Attainment areas may be reclassified from “serious” to “severe” if improvements relative to 2019 baseline values are not met in 2021. Since the areas include several key oil and gas producing counties, such an action would require operators to significantly reduce emissions or obtain Title V permits.
- Increasing ESG awareness and activism threatens to impact the export of LNG from Texas, as exemplified by France blocking a deal that would have shipped LNG from NextDecade’s Rio Grande facility to Engie. The move was prompted by concerns over flaring and methane emissions in the Permian Basin, which will provide the feedstock for Rio Grande LNG.
- The Railroad Commission of Texas (RRC) has changed Form R-32 to require operators to more thoroughly document the circumstances creating a need to flare gas. This provides more accurate information for assessing compliance and help shed light on broader needs and reasons for flaring.
Closing Thoughts
Our industry is playing catch-up on flaring and emissions reduction, having operated in a loosely regulated environment for a long time.
Growing stakeholder and public concern, which has now demanded action at state and federal levels, is leading to rapid changes in regulation, enforcement, and overall minimum standards.
As these changes grind their way through various levels of government, operators can – and in some cases must – get ahead of the issue by implementing available and affordable gas capture and vapor recovery solutions.
While near-term changes in administration might delay or reverse some of the current and imminent tightening of standards, it is unlikely to lead to a long-term regression. Operators should, as always, take a long-term view that aligns with the producing life of their assets. This implies improving standard designs and operating practices to include more effective vapor capture and emission reduction approaches.
About EcoVapor
EcoVapor Recovery Systems provides solutions to pressing oil and natural gas production problems. EcoVapor’s technical team has extensive expertise in vapor recovery processes and includes world-class engineers with an innovative approach to industry challenges. In over 120 installations in all major US basins, our patented ZerO2 solution helps oil and gas producers meet their air emissions and regulatory compliance goals. EcoVapor is headquartered in Denver, Colorado and has field locations in Greeley, Colorado and Midland, Texas.
Contact
EcoVapor Recovery Systems
1422 Delgany Street, Suite 100
Denver, CO 80202
Email: Info@EcoVaporRS.com
Phone: 844-NOFLARE (844-663-5273)