This article appears in the Autumn 2024 issue of Tanks and Terminals magazine, a copyrighted publication of Palladian Publications.
On May 8, 2024, the U.S. Environmental Protection Agency (EPA) finalized proposed revisions to emission standards for the gasoline distribution industry.[1] The final rules become effective on July 8, 2024². These standards affect storage tanks, loading racks, and equipment components in gasoline service at thousands of gasoline distribution terminals, bulk plants, pipelines, and refinery logistics assets.[2] The revisions include several important increases in stringency, such as lower numeric emission limits, additional monitoring, and shorter averaging periods.
Most standards and requirements of the final rules follow the rules proposed on June 10, 2022. Compared with the proposed rules, the final rules provided additional flexibility on certain matters. The EPA provided alternative, flare-like monitoring provisions for Vapor Combustion Units (VCUs) in each rule;[3] inspection schedule flexibility for internal floating roof (IFR) tank lower explosive limit (LEL) enhanced monitoring;[4] and provided a continuous emission monitoring system (CEMS) downtime option for Vapor Recovery Units (VRUs).[5] The EPA clarified that methane may be excluded when measuring emissions to compare with the standards for loading racks.[6] The EPA also separated the applicability of equipment leak detection and repair (LDAR) standards from applicability of standards for loading operations.[7] Under the final rule, projects that increase fugitive emissions from rack equipment (pumps, valves, etc.) without increasing emissions from loading operations would not subject those loading operations to new standards.[8]
On the other hand, the EPA markedly increased monitoring stringency for VCUs, for open flares, and thus also for VCUs that choose to rely on the final rules’ open flare monitoring parameters. To comply with the final rule, operators must know the prior loads of each loaded cargo compartment: an unworkable requirement for many terminals. If unworkable, the terminal must treat vapors from every loaded compartment as though they are gasoline. If the terminal controls vapors with a VCU, the terminal must maintain high temperature or vapor Net Heating Value (NHV) through addition of substantial volumes of assist gas.[10] Increased emissions of combustion pollutants and substantially increased operational costs are likely outcomes of the final rule.
Background
The EPA has regulated Volatile Organic Compound (VOC) emissions from the gasoline distribution sector under its New Source Performance Standards (NSPS) regulatory program (40 CFR Part 60) since the 1983 promulgation of “Standards of Performance for Bulk Gasoline Terminals,” 40 CFR Part 60, Subpart XX.[11] The NSPS required most gasoline truck loading racks built or modified between December 17, 1980 and June 10, 2022 to meet an emission standard of 35 milligrams of Total Organic Compounds (TOC) per liter of gasoline loaded (mg/L TOC).[12] The NSPS required monthly monitoring of loading rack equipment for leaks, by Audio, Visual, and Olfactory (AVO), or “sight/sound/smell” means.[13] NSPS XX also introduced vapor tightness requirements for gasoline tank trucks.[14]
In 1994, the EPA promulgated an emission standard regulating Hazardous Air Pollutant (HAP) emissions from HAP major source gasoline terminals and pipeline breakout stations: “National Emission Standards for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations),” 40 CFR Part 63, Subpart R (Subpart R).[15] This subpart required gasoline truck and rail loading racks to meet 10 mg/L TOC.[16] Subpart R required gasoline storage vessels (storage tanks) to install an IFR meeting most requirements of 40 CFR Part 60, Subpart Kb,[17] and to retrofit certain deck fittings on existing gasoline storage vessels with External Floating Roofs (EFRs). Subpart R required monthly AVO leak inspections, but the scope included all gasoline-service equipment at the terminal or breakout station.
Subpart R only affected larger terminals and breakout stations, those that met the EPA’s HAP major source threshold. By 1999, the EPA had indicated its intent to regulate gasoline distribution facilities that did not rise to the HAP major source threshold – such sources are known as “area sources” of HAP.[19] In 2008, the EPA promulgated “National Emission Standards for Hazardous Air Pollutants for Source Category: Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities,” 40 CFR Part 63, Subpart BBBBBB (Subpart 6B).[20] Subpart 6B contained different sets of requirements for four source categories: bulk gasoline terminals, bulk gasoline plants (a throughput of less than 20,000 gallons per day), pipeline pump stations, and pipeline breakout stations.
Summary of Revisions and Applicability
The EPA is required to review NSPS, such as 40 CFR Part 60, Subpart XX, and National Emission Standards for Hazardous Air Pollutants (NESHAP), such as 40 CFR Part 63, Subparts R and 6B, at least every eight years.[21] If needed, the EPA must revise the subparts to reflect the best demonstrated system of emission reduction (for NSPS) or to take developments in control technology into account (for NESHAP, a “technology review”). Table 1 presents the EPA’s key revisions of the three subparts as they apply to bulk terminals. The EPA adopted new or more stringent requirements for gasoline storage tanks, gasoline loading racks, and gasoline-service equipment. Also, the testing thresholds to determine whether a gasoline cargo tank is vapor-tight are revised.
[Table 1]
The Clean Air Act specifies a three-year time frame to reach compliance with revised Part 63 rules, so existing terminals must comply with the Subparts R and 6B changes before May 8, 2027.Performance tests for VCUs and initial performance evaluations for VRUs must be complete before that date. New terminals must comply upon startup. By contrast, when Part 60 (NSPS) rules are revised, existing facilities come into compliance with the new rule only after the first time they are modified, or reconstructed, after the date on which the rule is proposed. As a summary, most changes to a facility that cause emissions to increase are “modification,” and most changes that cost more than 50% of the cost of an equivalent new facility are “reconstruction.”[23] There may therefore be some loading racks that are already subject to Subpart XXa, either to the loading rack standards or to the LDAR standards, due to having “modified” or “reconstructed” the loading rack or the gasoline-service equipment since June 10, 2022. Going forward, terminal operators should carefully consider the effects and schedules of capital projects affecting their loading racks, to assess if those projects will cause the racks to be subject to Subpart XXa’s stringent new standards.
Certain aspects of the revisions to 40 CFR Part 60, Subpart XX and 40 CFR Part 63, Subpart 6B merit further discussion.
Instrument LDAR
Each of the final rules includes an LDAR instrument monitoring program to detect leaks from equipment in gasoline service. None of the current rules for gasoline distribution facilities require instrument monitoring. An LDAR program may apply already if an existing terminal’s project added equipment in gasoline service since June 10, 2022. At present, it is possible to interpret the rule to mean that it applies after addition of any de minimis number of valves or flanges to an existing gasoline terminal.[24] Apart from “modifying” or “reconstructing” the collection of gasoline-service equipment under Subpart XXa, LDAR will apply to the equipment from May 8, 2027 under the other two subparts. The three subparts only differ in frequency of monitoring, as shown in Table 1.
The required program includes two options. One option is to use EPA Method 21 to detect leaks, as is common at petroleum refineries or chemical plants. The other option is to use Optical Gas Imaging (OGI) to detect leaks. OGI technology creates images of hydrocarbon gases, such as gasoline vapors. Both programs require specialized equipment, as well as a detailed inventory of components in gasoline service.
First-time implementation of an instrument monitoring LDAR program requires advance consideration of several factors, especially for terminals in remote locations. Inspection logs required under current rules must be replaced with detailed, individually identified components. A compliance tool must be developed or purchased to record component identifiers and monitoring results. A decision must also be made between selecting a contractor or training a terminal’s staff to provide routine monitoring. This decision would consider the availability of contractors and of monitoring equipment.
Loading Rack Emission Control Standard Changes
The final rules make substantial revisions to emission standards for loading racks and associated vapor control systems at gasoline distribution facilities, as Table 1 illustrates. Key changes include:
- Lower Standards for Many VCUs, Regulated as “Thermal Oxidation Systems”: Emission standards for VCUs decrease under Subpart XXa and Subpart 6B. The current Subpart 6B specifies that bulk gasoline terminal loading racks with gasoline throughput of 250,000 gallons per day or greater must reduce the emissions of TOC to less than or equal to 80 mg/L TOC.[25] This standard will be reduced to 35 mg/L TOC. VCUs at loading racks under the new Subpart XXa must meet emission standards of 1 mg/L TOC (new loading rack) or 10 mg/L TOC (modified or reconstructed loading rack), compared with a prior Subpart XX standard of 35 mg/L TOC. The Subpart R standard of 10 mg/L TOC is unchanged.
- More Stringent Monitoring Requirements for VCUs: In the section to follow, details of new VCU monitoring requirements are explained.
- Open Flare Standards: Achieve at least 98% reduction in emissions of TOC by weight, and demonstrate this reduction using rules pulled from the refinery flare rules to Subpart XXa.[26]
- Vapor Recovery System: When complying with any subpart using a VRU, emission standards are now expressed as parts per million by volume (ppmv) as propane, determined on a 3-hour rolling average. Since prior subparts relied on a 6-hour averaging period for performance testing, existing units should be assessed for suitability under a 3-hour rolling average standard.
VCU Monitoring Changes
Monitoring a VCU for compliance with the new rules is perhaps their most challenging compliance aspect. While some VCUs were required to monitor firebox temperature under the pre-2024 Subpart R rule, most VCUs were regulated under the pre-2024 subpart 6B rule. This rule provided monitoring the presence of a pilot flame as an alternative to measuring the firebox temperature.[27] Gasoline vapors readily combust in the presence of a flame.
Under the final rules, monitoring requirements for VCUs become much more restrictive. New loading racks built since June 10, 2022 will be subject to Part 60, Subpart XXa and must continuously monitor temperature. Loading racks subject to Subpart XXa due to modification or reconstruction after that date, as well as racks subject to Part 63, Subpart 6B and complying by 2027, have an additional option to monitor the NHV of the gases fed to the VCU.[29] Such racks would follow rules for open flares at petroleum refineries in several respects.[30]
These monitoring options are challenging because each option is likely to result in substantial use of assist gas. For the temperature monitoring method, the final rules require determining a VCU temperature set point at the lowest 3-hour average temperature during the emission performance test of the unit.[31] By rule, the performance test involves a minimum amount of gasoline loaded.[32] As gasoline vapors release heat when combusted, the performance test time period naturally has bias toward higher temperature than time periods when gasoline and non-gasoline load rates vary with demand. In supporting documents to the final rule, the EPA asserts that during periods of lower temperature, the VCU may be operating in an overdilute manner, reducing its emission control effectiveness.[33] In comments on the 2022 rule proposal, industry trade associations asserted that in fact, VCUs maintain high effectiveness at lower temperatures than would be expected during the emission performance test.[34] In the final rule, the EPA retained the requirement to set a 3-hour average temperature during the test. Therefore, terminals are obliged to maintain this temperature whenever gasoline is loaded. In that many terminals are not able to certify the prior load contents of a given truck’s cargo compartments, this requirement will apply de facto to diesel loading. Accordingly, compliance will require substantial auxiliary fuel.
Some facilities use a VCU as a backup vapor control system to their primary vapor recovery system for when the primary vapor control system is down. If the backup VCU is required to combust additional auxiliary fuel to maintain the firebox temperature, operation of the backup vapor control system may become cost-prohibitive.
The EPA believes that small terminals, for which this requirement is cost-prohibitive, will elect the alternative option, to monitor the NHV and “dilution parameter” (NHVdil) of the VCU. The rules require continuous compliance demonstration, either through continuous online assessment of waste vapor composition or NHV, or through continuously tracking the loading rack’s gasoline loading rate and gasoline-to-non-gasoline loading ratio.[36] The EPA thereby requires terminals to demonstrate that waste vapors to the VCU maintain an NHV of 270 British thermal units (Btu) per standard cubic foot (scf), and NHVdil of 22 Btu per square foot (ft2). Similar to the temperature option, these requirements require substantial use of assist gas if non-gasoline loading operations must be treated as gasoline loading due to unavailable information on prior truck loads.
Facility operators should begin to develop their compliance approaches for VCUs, whether serving as primary or backup controls. From the more limited options available in the rules, facilities should select a vapor control and compliance demonstration approach that achieves compliance in a cost-effective manner.
Averaging Period Changes
The final rules also reduce the duration of averaging periods for loading rack emission control devices, creating another potential challenge for facilities subject to the revised rules. For a thermal oxidation system other than a flare, the EPA requires that combustion zone temperature be maintained at or above the level determined during the performance test on a 3-hour rolling average basis.[37] Similarly, the EPA is finalizing a 3-hour rolling average monitoring period for the ppmv emission standards for vapor recovery systems. Prior to this rulemaking, the averaging period for performance testing for either type of control device was 6 hours.[38] Changing from a 6-hour to a 3-hour rolling average impacts the perceived effectiveness of control devices.
In a VCU, actual firebox temperature is related to the volume of gasoline vapors combusted at a given time. At most facilities, loading activities do not occur at a uniform rate throughout the day but are, rather, characterized by periods of higher gasoline demand followed by periods of lower gasoline demand. Decreasing the window for a rolling average temperature parameter, from 6 hours to 3 hours, means greater variability in the VCU temperature. Rises and falls in temperature due to varying gasoline vapor generation rates do not correlate with VCU effectiveness. However, operators now have a compliance need to stay above the required temperature minimum. This need might be met by adding assist gas, shortening periods of higher loading rates, or smoothing periods of peak and low demand. This compliance need could result in more waiting time for tank trucks or delays for delivering gasoline to customers.
In vapor recovery systems, a limit expressed as ppmv on a 3-hour basis is more stringent than the same limit expressed on a 6-hour basis. Facilities’ existing vapor recovery systems may need to be redesigned to be able to accommodate the final emission limits on a 3-hour rolling average basis.
VRU CEMS Alternative Monitoring
In the final rule, the EPA provided an alternative monitoring option for VRUs, for up to 240 hours per year in periods when the VRU continuous emission monitoring system (CEMS) is offline for more than 15 minutes.[39] The alternative involves establishing the quantity of liquid loaded, vacuum pressure, purge gas quantity, and duration of vacuum/purge cycle length over the prior 10 regeneration cycles of the VRU, and using these values as monitored operating parameter values during periods of CEMS downtime. In practice, the option is likely not workable for many terminals. The option would limit gasoline loading throughput, while the option is in use, to the minimum throughput in the past 10 regeneration cycles of the VRU. As that minimum throughput may be zero, the option is unpredictably unavailable in practice. The option may also impose unworkable values for the monitored parameters, as VRUs use CEMS data to tailor actual cycle length and operations when CEMS data are available. And, it is not typically necessary for a VRU to measure purge gas quantity for operations, so information on purge gas quantity is likely not available to most terminals. For these reasons, terminals should carefully examine whether the alternative monitoring option for VRUs is workable.
Conclusion
The EPA has finalized key changes to air emission standards for the gasoline distribution industry. The revisions include instrument monitoring LDAR requirements, revised monitoring requirements for storage vessels, and substantial changes to emission standards and compliance demonstration methods for loading racks. The new standards may require affected facilities to undertake capital projects, to implement new compliance demonstration programs, or to conduct internal feasibility studies for compliance planning purposes. Gasoline distribution facilities should begin developing compliance strategies for the revised rules, especially as NSPS Subpart XXa rules apply to facilities modified after June 10, 2022.
[1] 89 Fed. Reg. 39304 (May 8, 2024). Docket number EPA-HQ-OAR-2020-0371 available at https://www.regulations.gov/docket/EPA-HQ-OAR-2020-0371.
[2] The EPA’s cost calculations in the rule docket (EPA-HQ-OAR-2020-0371-0010) include a basis of 210 Hazardous Air Pollutant (HAP) major sources and over 9,250 HAP area sources.
[3] 40 CFR §§ 60.502a(c)(3) and 63.11092(e)(2)(ii).
[4] §63.425(j)(1) and (j)(3)(i).
[5] §60.504a(e).
[6] §60.503a(c)(6)(i) through (v) and (d)(2)(i) through (iv).
[7] §60.500a(a)(1) and (a)(2) definitions of “gasoline loading rack affected facility” and “collection of equipment at a bulk gasoline terminal affected facility.”
[8] 89 Fed. Reg. at 39317 (May 8, 2024). Final rule preamble.
[9] §60.501a: “Gasoline cargo tank means a delivery tank truck or railcar which is loading gasoline or which has loaded gasoline on the immediately previous load.”
[10] For temperature see §60.503a(c)(8) and §60.502a(b)(1)(ii), (c)(1)(ii). For NHV, see §60.502a(c)(3)(viii).
[11] 40 CFR Part 60, Subpart XX, “Subpart XX – Standards of Performance for Bulk Gasoline Terminals,” was first promulgated on August 18, 1983 (48 FR 37590). The subpart is available online from the electronic CFR at https://www.ecfr.gov/current/title-40/chapter-I/subchapter-C/part-60/subpart-XX.
[12] 40 CFR 60.502(b). Paragraph (c) provides an exception for loading racks that had a vapor processing system constructed or refurbished before December 17, 1980, and that could attain 80 mg/L TOC.
[13] 40 CFR 60.502(j).
[14] 40 CFR 60.502(e)(1).
[15] 40 CFR Part 63, Subpart R, “National Emission Standards for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations),” was first promulgated on December 14, 1994 (59 FR 64318). The subpart is available online at the eCFR at https://www.ecfr.gov/current/title-40/chapter-I/subchapter-C/part-63/subpart-R.
[16] 40 CFR 63.422(b).
[17] 40 CFR 63.423(a). Some deck fitting control requirements of 40 CFR Part 60, Subpart Kb were not included in Part 63, Subpart R. Seal requirements were included, as was the requirement that deck fittings have projections below the liquid surface.
[18] 40 CFR 63.423(b)(3).
[19] Table 3 of U.S. EPA, “National Air Toxics Program: The Integrated Urban Strategy,” July 19, 1999 (64 FR 38721), available online at https://www.govinfo.gov/content/pkg/FR-1999-07-19/pdf/99-17774.pdf.
[20] 40 CFR 63 Subpart BBBBBB, “Subpart BBBBBB – National Emission Standards for Hazardous Air Pollutants for Source Category: Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities,” was first promulgated on January 10, 2008 (73 FR 1933). The subpart is available online from the eCFR at https://www.ecfr.gov/current/title-40/chapter-I/subchapter-C/part-63/subpart-BBBBBB.
[21] Clean Air Act, §§ 111(b)(1)(B) and 112(d)(6).
[22] 89 Fed. Reg. 39306 (May 8, 2024).
[23] Details are given at 40 CFR 60.14 and 40 CFR 60.15. Some exceptions apply. For instance, routine repair and maintenance is not “modification.” However, it can be difficult to determine when an exemption applies.
[24] In more detail: comparable LDAR NSPS for other industry sectors, such as petroleum refining and chemical manufacturing, provide a dedicated “capital expenditure” test. For the first several years after such a rule is made, projects that add a de minimis number of valves or connectors can usually demonstrate that they are not “capital expenditures” and thus not “modifications” causing LDAR to apply. Dedicated provisions were included for each industry sector because the EPA’s general language on this matter (40 CFR 60.14(e)(2)) intended to exempt only an “increase in production rate.” It is unclear whether adding valves or connectors to a terminal is considered a “production rate” increase.
[25] Table 2 to Subpart BBBBBB.
[26] Requirements at 40 CFR 60.502a(c)(3) for Subpart XXa open flares lift from requirements at §63.670 for refinery flares.
[27] §63.11092(b)(1)(iii)(B).
[28] §60.502a(b)(1)(ii) (new racks).
[29] §60.502a(c)(1)(ii) (modified or reconstructed racks, temperature monitoring) and (c)(3) (modified or reconstructed racks, monitoring flare parameters using references to §63.670).
[30] §63.11092(e)(2)(ii).
[31] §60.502a(c)(1)(ii).
[32] §60.502a(c)(1).
[33] 89 Fed. Reg. at 39325.
[34] Docket No. EPA-HQ-OAR-2020-0371-0105. Attachment A pp. 35ff.
[35] §60.502a(c)(3)(viii).
[36] §60.502a(c)(3) provides for compliance demonstration options in the petroleum refinery flare rules at §63.670. These rules in turn allow for continuous analysis of gas composition under §63.670(j)(1) or (2), or continuous analysis of NHV by calorimeter under (j)(3) and (4), or the grab sampling alternative under (j)(6). Under the grab sampling alternative, facilities collect 14 days of grab samples and the demonstrate on an ongoing basis that those samples represent actual flared gas situations. When adapting the (j)(6) grab sampling alternative to the §60.502a(c)(3) gasoline distribution rules, the EPA approach was to use the gasoline loading ratio to verify that the flared gases continuously meet the 270 Btu/scf threshold for NHV, and the gasoline loading rate to verify that they meet the 22 Btu/ft2 dilution parameter NHVdil. Strictly, NHVdil and thus the gasoline loading rate monitoring requirement apply only to “air-assisted” units, but in practice the vast majority of VCUs are “air-assisted.”
[37] §60.502a(b)(1)(ii) and (c)(1)(ii).
[38] §60.503(c)(1).
[39] §60.504a(e).
