On September 29, 2015, the U.S. Environmental Protection Agency (“EPA” or the “Agency”) promulgated its final Petroleum Refinery Sector Risk and Technology Review (“RTR”) and New Source Performance Standards (“NSPS”) rule[1] (“final rule” or “rule”) for petroleum refineries that qualify as major sources.  This rule fulfills EPA’s obligations to evaluate residual risks and technological developments under sections 112(f) and 112(d)(6) of the Clean Air Act (“CAA”), respectively, for the petroleum refinery National Emission Standards for Hazardous Air Pollutants (“NESHAP”) from Petroleum Refineries, 40 C.F.R. Part 63, Subparts CC and UUU (2015) (the latter of which applies to Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units).  Affected existing sources will be required to comply with the new requirements no later than 2018.  However, some existing sources must comply with certain provisions earlier than 2018, depending on the provision and the date the refinery was constructed.  New sources have 60 days from the rule’s publication in the Federal Register to comply with all provisions. 

The main components of this rule include:

  • New monitoring, reporting, preventative, and corrective measures for releases from pressure relief devices to the atmosphere;
  • New monitoring and operating requirements for flares used as air pollution control devices and flares on combustion zone properties;
  • Continuous benzene monitoring at the fenceline, with the potential for reductions in monitoring frequency for facilities demonstrating consistently low levels of benzene;
  • Removing the exemption from emission standards for releases during start-up, shut-down, and malfunctions;
  • Implementing a 20% opacity operating limit for fluidized catalytic cracking units and requiring periodic performance testing; and
  • New emission requirements for delayed coker units, storage vessels, marine vessels, and climate research units.

We discuss each of these major rule elements below.

Work Practice Standards for Pressure Relief Devices

The final rule establishes work practice standards for releases from pressure relief devices (“PRDs”) to the atmosphere under CAA section 112(h).  For new sources, the rule requires all PRD in hazardous air pollutant (“HAP”) service to be vented through a closed vent system to a control device.  Existing sources are not required to vent through a closed system but must apply the source’s choice of a minimum of three redundant prevention measures to each PRD to limit the possibility of a release.  Examples of such measures include: flow, temperature, level and pressure indicators; documented routine inspection and maintenance programs; “inherently safer designs” or safety instrumentation systems; deluge systems; and staged relief systems where an initial pressure relief valve discharges to a flare or other closed vent system and control device.  All PRDs are also required to be equipped with a monitoring device (such as, for example, a rupture disk indicator, magnetic sensor, motion detector on the PRD valve stem, flow monitor, or pressure monitor) that identifies a pressure release, records the time and duration, and notifies operators immediately that a release is occurring. 

In the event of a release, refinery owners or operators are required to perform a root cause analysis to determine the cause of the PRD release event and to quantify and report the amount of the release.  Following a release, sources must implement corrective action, including additional prevention measures.  A second release in a three-year period due to the same root cause for the same equipment would be considered a deviation from the work practice standard, and a third release in the same time period would be considered a deviation from the standard regardless of the root cause.  Releases caused by operator error or negligence are also considered a deviation from the work practice standard.  Operators are required to report deviations, along with specific information concerning the deviation/s, in semiannual compliance reports.

Certain PRDs are excluded from the rule’s requirements.  The following devices in both new and existing sources are not subject to the new work practice standards: heavy liquid service PRDs; thermal expansion valves; liquid PRDs that are hard-piped to controlled drains; PRD with release pressure of less than 2.5 pounds per square inch (“psig”); PRD with emission potential of less than 72 lbs./day, and PRD on mobile equipment. 

EPA’s approach in the final rule differs from the proposed rule, which had flatly prohibited PRD releases to the atmosphere.  In the final rule, EPA states that the requirement for new sources to vent PRD releases through a closed vent system to a control device is “essentially equivalent” to the proposed requirement of no atmospheric releases.  For existing sources, EPA assessed the feasibility of requiring sources to vent to either add-on or existing control devices, including flares.  EPA concluded that it “may not” be feasible to vent to existing flares if the flares are near load capacity for existing processes, and therefore EPA estimated that a prohibition on venting to the atmosphere would require installing approximately one new flare per refinery, with a capital cost of more than $300 million and an annual operating cost of approximately $12 million. EPA also noted that flares have negative secondary emission impacts when primarily operated at idle conditions, as would be the case for flares dedicated to PRD release service.  Consequently, EPA concluded that controlling all atmospheric PRD releases is not a cost-effective option when compared to the significantly lower cost associated with implementing work practice standards.

Revised Operating and Monitoring Requirements for Flaring

The rule establishes new monitoring and operating requirements for flares used as air pollution control devices.  Under the new rule, flares must operate 1) with a continuously lit pilot flame at all times, and 2) with no visible emissions when flare vent gas is below the smokeless capacity of the flare (additional requirements on flare tip velocity also apply in this situation).  The rule also establishes work practice standards for visible emissions and velocity emissions for times when the flare gas is above the smokeless capacity of the flare.  

The new rules for flare combustion efficiency reflect key changes from the proposal. The flare’s net heating value of the combustion zone gas (“NHVcz”) must meet a single minimum operating limit of 270 British thermal units (“BTU”) per standard cubic footon a 15-minute average instead of complying with one of two limits based on the presence of olefins and hydrogen in the waste gas, as was proposed.  To demonstrate compliance with this limit, refineries can also use a corrected heat content of 1,212 BTU per standard cubic foot.  The rule also allows for an alternative means of meeting the emission limitation—refineries can prove either 96.5% combustion efficiency (“CE”) or 98% destruction removal efficiency (“DRE”).  

The rule allows refineries to grab samples every eight hours instead of continuously monitoring vent gas composition or heat content.  Refineries can also conduct limited initial sampling to characterize flare gas compositions for flares in dedicated service instead of continuously collecting samples during each flaring event.  Additionally, refineries must report visible emissions observations on a daily basis, but, unlike in the proposal, owners and operators can use surveillance cameras to demonstrate compliance with the visible emissions limit in lieu of direct observations.  

The revised flaring rules allow for more flexibility than originally proposed, but usher in a significant new set of monitoring provisions intended to ensure that flares operate at 96.5% CE/98% DRE at all times.  The complex new monitoring requirements likely set a new baseline for all flares and may ultimately be incorporated into the NSPS General Provisions and Maximum Achievable Control Technology (“MACT”) General Provisions.  Significantly, these provisions depart from recent consent decree requirements that have focused on steam to vent gas ratios and may influence enforcement negotiations the Agency is currently having under its Flaring Initiative.

Enhanced Monitoring at Refinery Perimeters

Based on its technology review, the final rule establishes a monitoring work practice standard that EPA claims will improve the management of fugitive emissions from sources such as leaking equipment and wastewater treatment.  Significantly, the rule requires continuous but not real-time monitoring of benzene concentrations at the refinery fenceline.  Refineries must install technology capable of detecting benzene at very low levels (as low as 0.9 µg/m3), with as few as 12 and as many as 24 monitors, depending on the size of the refinery, encircling each covered refinery.  Facilities must submit monitoring data reports on a quarterly basis, rather than on a semi-annual basis, as proposed. 

The rule requires that all refineries use diffusive passive sampling to monitor benzene levels at the fenceline, collecting samples at least once every 14 days.  Facilities that demonstrate benzene levels consistently at or below 0.9 µg/m3 may monitor fenceline emissions less frequently, with monitoring burdens decreasing from every other two weeks to annually, depending on how long low benzene levels persist.  If levels begin to increase, the more stringent monitoring requirements will be re-imposed.

If fenceline emissions exceed the 0.9 µg/mthreshold, however, the rule requires that refineries take corrective action.  Unlike the proposed rule, the final rule does not require that refineries obtain EPA approval of corrective action plans.  Refineries must fully implement the new fenceline monitoring provisions within 2 years after the effective date of the final rule (the rule becomes effective 60 days after the date of publication in the Federal Register), rather than the proposed deadline of 3 years.  

Startup, Shutdown, and Malfunction Provisions

The final rule eliminates the exception for uncontrolled pollutant releases during refinery startup, shutdown, and malfunction (“SSM”) events.  In its place, the rule establishes emissions standards or work practice standards for certain emissions sources, including PRDs, emergency flaring, fluidized catalytic cracking units (“FCCU”), and sulfur recovery plants during these previously excluded events.

As discussed above, the final rule establishes work practice standards for releases from PRDs (which apply at all times) and emergency flaring during SSM events.  The rule requires refineries to perform a root cause analysis and implement corrective action following direct releases from PRDs and certain emergency flaring events during SSM periods, limits the number of such events that can occur over a three-year period before being considered a deviation from the standard, and requires that refineries develop prevention measures for each type of release, such as a flare management plan.  

Additionally, the rule promulgates standards for fluidized catalytic cracking units (“FCCU”) during SSM events, with carbon dioxide (“CO2”) and particulate matter (“PM”) limits as surrogates for organic and metal HAP, respectively.  During startup, shutdown, and hot standby of FCCUs, refineries can choose to comply with one of two metal HAP emissions standards and one of two organic HAP emissions standards.  Specifically, for metal HAP emissions, refineries can either comply with 1) NSPS requirements, PM emission limits, and nickel emission limits, or 2) they can elect to maintain the inlet velocity to the primary internal cyclones of the FCCU catalyst regenerator at or above 20 feet per second.  For organic HAP emissions, refineries can either comply with 1) specified operating limitations, NSPS requirements, or CO emission limits, or 2) they can maintain the oxygen concentration in the exhaust gas from the catalyst regenerator at or above 1% volume.

Sulfur recovery plants must meet one of three sets of standards during startup and shutdown periods: 1) elect to send any startup or shutdown gases to a flare; 2) send gases to a thermal oxidizer or incinerator; or 3) meet NSPS requirements or the total reduced sulfur emission limitations set forth in the rule. 

The final rule reflects EPA’s recent position that the SSM exemption is no longer legal following the D.C. Circuit’s 2008 decision in Sierra Club v. EPA, 551 F.3d 1019, 1027–28 (D.C. Cir. 2008) (“Sierra Club”) (vacating the SSM exemption on the grounds that the Clean Air Act requires continuous compliance with section 112 standards).  EPA has previously interpreted theSierra Club case as mandating that the same standards must apply at all times, including SSM periods.  Industry has pushed back, arguing that theSierra Club case stands only for the proposition that standards must be continuous, and that different continuous standards or work practice standards could apply during SSM periods.  EPA appears to moving toward the industry position in the RTR rule.  Industry and several states have challenged EPA’s more aggressive interpretation in several cases discussed below.

In May of 2015, EPA called on all states to revise their State Implementation Plans (“SIPs”) to remove SSM exemptions.  40 C.F.R. § 52 (2015).  In the months following, several subsidiaries of Energy Future Holdings Corp. and the state of Texas, along with 17 other states, challenged EPA’s decision to eliminate the SSM exemption in three cases: State of Florida, et al., v. EPA, Case No. 15-1267 (D.C. Cir. Aug. 11, 2015); State of Texas v. EPA, Case No. 15-1308 (5th Cir. July 8, 2015); and Luminant Generation Company LLC, et al., v. EPA, Case No. 15-1301 (D.C. Cir. Aug. 31, 2015).  The D.C. Circuit recently consolidated ten petitions challenging EPA’s SIP call, including the Texas and Energy Future Holdings petitions.  In brief, these states and industry groups have claimed that existing SIPs adequately address emissions during SSM events.  Furthermore, they argue that EPA’s decision to remove the exemption will ultimately penalize even the most careful of actors for events out of their control.  Industry is also challenging EPA’s more aggressive interpretation of Sierra Club in the boiler MACT/CISWI cases in the D.C. Circuit, which are fully briefed and awaiting oral argument in December.

New Requirements for Fluidized Catalytic Cracking Units

The final rule includes new requirements for fluidized catalytic cracking units (“FCCU”) subject to refinery NSPS Subpart J, as EPA’s technology review revealed developments in FCCU process and control technologies.  The final rule removes the incremental PM limit for burning liquid or solid fuels, implements a 20% opacity operating limit evaluated on a 3-hour average, and adds bag leak detectors as an option for continuous opacity monitoring systems.

Additionally, the final rule replaces the existing requirement of one-time initial FCCU performance testing with performance testing once every five years.  For refineries complying with Subpart J, if the PM emissions are within 80% of the PM limit during any performance test,, facilities must subsequently conduct performance tests annually.  Refineries have 18 months after the effective date of the final rule to comply with the new FCCU performance testing requirements.  

New Emissions Limits for Delayed Coker Units, Storage Vessels, Marine Vessels, and Climate Research Units  

The final rule expands the types of storage vessels subject to emission reductions requirements, requires certain marine vessel loading operations to use submerged filling, and establishes new standards for climate research units and decoking operations.

Under the new rule, storage vessels with smaller capacities and lower vapor pressure must implement certain requirements to maintain air emission standards previously applicable only to larger and higher-pressure storage vessels.  Marine vessels with emissions equal to or greater than 10 tons per year (“tpy”) of a single HAP pollutant or 25 tpy of cumulative pollutants will also be subject to controls.  Mainly, such marine vessels will now be required to use submerged filling.  Additionally, emissions from the active purging or depressuring of climate research units must now meet new HAP emission limitations. 

Delayed coking units (“decoking units”) will now be required to depressure each coke drum to a closed blowdown system until the coke drum pressure equals 2 psig.  Under the final rule, decoking units must comply with the 2 psig limit when averaged over 60 cycles, as opposed to the requirement in the proposed rule to meet the 2 lb. limit on a per-venting basis.  The rule also establishes new provisions for decoking operations with water overflow design and double quenching.

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The final rule reflects certain key changes from the proposed rule that are favorable to industry, in particular the change from prohibiting PRD releases to the atmosphere to requiring the use of work practice standards.  Nonetheless, the rule has important new features that will be costly to implement (in the range of a billion dollars), may pose operational challenges, and will have legal implications that reach well beyond the scope of the rule.  For example, fenceline monitoring requirements raise a host of technical, reliability, and enforcement issues.  The science around flaring is evolving quickly and the flaring provisions may become outdated, as new technologies are developed and flare science is improved.  Based on the changes required by the final rule, emissions estimates could change for some facilities, with potential implications for New Source Review and Title V permitting, as well as SIP compliance issues. 

The final rule is also important because it will likely provide a blueprint for the Agency’s overarching approach to RTR rules going forward.  Other standards that the Agency is currently developing, for example the Ethylene MACT, will not likely depart significantly from this new suite of standards.