4 The record articles

U.S. EPA Interpretations on Refinery Rule Alternative Monitoring Plans- Helping Pave a Path to Facilitate Your Facility’s Compliance

Posted: December 7th, 2017

Authors: All4 Staff 

Regardless of the political climate, it seems that regulations related to air quality are in a constant state of flux.  There are multiple “tools” available to regulated facilities to keep track of evolving regulations, guidance, and policy.  One such tool is the Applicability Determination Index (ADI), a database compiled by the U.S. Environmental Protection Agency (U.S. EPA) that provides U.S. EPA responses to questions posed by regulated facilities regarding rule applicability, including the use of alternative methods of compliance.  The questions generally relate to Standards of Performance for New Stationary Sources (NSPS) and the National Emission Standards for Hazardous Air Pollutants (NESHAP).  This database is used to ensure national consistency by providing all issued letters and memoranda in one location.  Decisions made by U.S. EPA in response to specific applicability questions, proposed Alternative Monitoring Plans (AMP), and related interpretations are posted on the ADI as an aid to other facilities that may have the same or similar regulatory based questions.  The ADI is continuously updated and periodically a summary of recent determinations is released via a Federal Register notice.  A recent summary dated August 4, 2017 is available here.

Refinery Sector Rule Regulatory Background

The U.S. EPA is required to periodically perform a risk and technology review (RTR) of 40 CFR Part 63 NESHAP standards, to re-evaluate the maximum achievable technology standard (MACT) floor, as applicable, and to determine if human health risks remain after the application of the MACT standards.  Pending the outcome of the RTR, the MACT standards may be updated to reflect current technology and to mitigate residual risk.

In September of 2012, several environmental groups filed lawsuits alleging that U.S. EPA missed the mandatory deadline to review the refinery MACT rules, specifically 40 CFR Part 63, Subpart CC (NESHAP from Petroleum Refineries) and 40 CFR Part 63, Subpart UUU (NESHAP for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units).  These NESHAPs are also referred to as Refinery MACT 1 and MACT 2.  In response to the litigation, U.S. EPA and litigants entered a consent decree that ultimately required the promulgation of updated standards by September 30, 2015 to meet the Clean Air Act (CAA) residual risk requirements.  Following the RTR analysis, Subparts CC and UUU were revised.  The final Petroleum Refinery Sector RTR was published in the Federal Register December 2015 with an effective date of February 1, 2016.  The publication of the RTR included amendments to 40 CFR Part 60, Subpart J (Standards of Performance for Petroleum Refineries) and 40 CFR Part 60, Subpart Ja (Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After October 14, 2011).  The December 2015 rule amendments for the refining industry are collectively referred to as the Refinery Sector Rule (RSR).

The RSR included broad new requirements for refiners including:

  • New flare compliance requirements
  • New emissions controls for storage tanks
  • New emissions controls for delayed coking units (DCUs) and catalytic reformer units (CRUs)
  • Benzene fenceline monitoring requirements
  • New pressure relief device compliance requirements
  • Removal of startup, shutdown and malfunction (SSM) emissions limits exemptions

Recent ADIs Relevant to the Refining Industry

The RSR included significant new monitoring requirements for compliance demonstration.  While implementing the new and expanded monitoring provisions, refiners have sought clarification of requirements and have proposed AMPs to the U.S. EPA.  Key U.S. EPA determinations and trends for RSR compliance from recent ADI determinations are provided below.

  • Two refiners1 subject to Subpart Ja were successful in receiving AMP approval to avoid installing hydrogen sulfide (H2S) continuous emissions monitoring systems (CEMS) for fuel gas combustion devices as required by 40 CFR §60.107a(a)(2) for temporary and portable thermal oxidizer(s).  U.S. EPA recognized the impractical nature of installing an H2S CEMS on thermal oxidizers used for intermittent operations (e.g., tank degassing).
  • A refiner2 subject to Subpart J, whom had a previously approved AMP to assert a low-sulfur fuel gas stream in accordance with 40 CFR §60.105(a)(4)(iv)(D) was required to gain approval to revise the parameter monitoring to continue to assert the low-sulfur fuel gas stream.  The refiner will now monitor the naphtha hydrotreater feed surge drum for total sulfur and temperature to maintain the low-sulfur fuel gas stream assertion.
  • A refiner3 subject to UUU, successfully received approval for the use of parametric monitoring of opacity for a fluid catalytic cracker unit (FCCU) equipped with a wet gas scrubber (WGS) control device in lieu of the Subpart UUU required continuous opacity monitoring system (COMS).  The AMP was approved after receipt of test data from the refiner demonstrating that proposed operating parameter limits (OPLs) ensured compliance with metal and organic hazardous air pollutants (HAPs) requirements.  Of note in this specific AMP approval was that the refiner was required to incorporate the OPLs into facility permits to ensure Federal enforceability.  While not universally required, incorporation of AMP monitoring requirements is viewed as sound practice to assure compliance with AMP provisions in annual Title V operating permit (TVOP) compliance certifications.
  • Several refiners4 subject to Subpart Ja received AMP approval for Quality Assurance/Quality Control (QA/QC) requirements to eliminate the daily use of high sulfur containing calibration gases for flares because of safety concerns.  The approved AMPs include the use of the following:
    • A refiner5 requested to eliminate the use of high concentration calibration gases for completing calibrations on their H2S CEMS.  U.S. EPA approved eliminating the daily calibration for the high range H2S CEMS and emphasized that compliance demonstration for the Subpart Ja 3-hour 162 ppm limit and the 365-day 60 ppm limit are demonstrated with the low range analyzer.
    • A refiner6 proposed to eliminate the use of high concentration calibration gases for the total reduced sulfur (TRS) CEMS. The facility uses the monitor on the refinery flare with a TRS range of 0-150,000 ppm.  U.S. EPA approved the AMP eliminating the completion of daily calibration for the high range portion of the TRS CEMS provided the refiner complete a linearity analysis every three years., The refiner was required to incorporate the AMP requirements into facility permits to ensure Federal enforceability.
    • A refiner7 requested to eliminate the use of high concentration calibration gases containing sulfur for completing daily calibrations on the total sulfur (TS) CEMS.   U.S. EPA again approved eliminating the daily calibration for the high range CEMS and emphasized that compliance demonstration for the Subpart Ja 3-hour 162 ppm limit and the 365-day 60 ppm limit are demonstrated with the low range analyzer.  The high range analyzer is used to determine the need to conduct a root cause and corrective action analysis for flaring events that exceed 500 pounds in a 24-hour period.  The high range analyzer will still require completion of the quarterly calibration gas audit (CGA) for QA/QC purposes.
    • A refiner8 requested to eliminate the use of high sulfur concentration calibration gases for completing daily calibrations on the TS CEMS. U.S. EPA approved eliminating the completion of daily calibration for the high range (10,000 to 300,000 ppm).  The refiner is still required to conduct a two-point daily calibration and a quarterly CGA for the low range (0 to 10,000 ppm) TS CEMS.  The high range (10,000 to 300,000 ppm) TS CEMS will undergo a single point calibration at 50-60% of span (150,000 to 180,000 ppm) quarterly for QA/QC purposes.
    • A refiner9 with three flares subject to Subpart Ja, submitted multiple AMP request options in a single submittal and obtained approval, for all but one, to eliminate the use of high sulfur containing calibration gases.  The AMP request included:
      • A request to use a surrogate calibration gas (carbon dioxide, argon, or nitrogen) for the TRS monitors subject to Subpart Ja.  U.S. EPA denied the request and noted that there are other feasible options to eliminate the use of high sulfur containing daily calibration gases.
      • A request to use the low concentration H2S monitor calibration to validate the TRS analyzer high range.  U.S. EPA noted this option is approvable upon demonstration that the analyzer operates linearly across the range of pollutant concentrations. This option will require the refiner to complete daily low range calibrations and quarterly high range calibrations.
      • A request to use a sample dilution system at the ratio of 1,000:1 for monitoring TRS concentration in the flare gas.  This would result in the calibration gases needed for analyzer verification to contain a lower amount of sulfur.  U.S. EPA approved this option because the method will provide actual readings of the target compound without relying on extrapolations or linearity to determine the TRS concentration value.  However, this approval is dependent upon the refiner’s ability to certify and challenge the dilution system at the ratio it intends to use (1,000:1) and the capability of the analyzer to detect the lowest expected concentrations of the target(s) compounds during typical operating conditions.
      • A request to use single point daily calibrations for each of the TRS analyzers associated with the three flares to comply with the QA/QC requirements.  U.S. EPA approved the single point daily calibration at a zero and one other target compound concentration within the analyzer span and conducting a multi-point calibration on each TRS analyzer quarterly.  If the daily calibrations indicate excessive drift then the refiner must revert to daily multi-point calibrations until the issue is resolved.
      • Further, this refiner requested reducing the TRS analyzer span for a specific flare, the aromatics flare, to 1,000 ppm from 5,000 ppm because the exhaust gas to this specific flare has inherently lower sulfur concentrations.  U.S. EPA approved the change to the analyzer span based on the process information provided by the refiner for the specific flare operation.

Take Aways

Recent refining industry determinations in the ADI indicate U.S. EPA’s willingness to approve AMP requests for refiners to comply with RSR monitoring requirements.  While U.S. EPA approved the bulk of the AMP requests, U.S. EPA denied a request to use a surrogate gas to calibrate CEMS.  ALL4 expects that U.S. EPA will not likely allow the use of surrogate gases for calibration of CEMS.  Refiners’ AMP requests for safety concerns were generally recognized and accepted by U.S. EPA to eliminate the daily use of high sulfur concentration calibration gases when approving AMPs.  The requests addressing safety concerns resulted in U.S. EPA allowing refiners to rely upon quarterly CGAs as opposed to daily calibrations for the purposes of QA/QC for high ranged H2S, TS, or TRS CEMS.  Further, the approved elimination of daily calibration of high range sulfur CEMS was reliant upon the linearity of the analyzers and the fact that the high range CEMS information is used for the determination to conduct a root cause and corrective action analysis if flare combustion results in greater than 500 pounds of SO2 in a 24-hour period.  Whereas the low range CEMS information is used to demonstrate on-going compliance to not burn fuel gas that contains more than 162 ppm H2S.

Several of the determinations included requirements to include AMP provisions within facility permits to ensure enforceability.  In general, inclusion of AMP provisions in facility permits ensures that such provisions are not overlooked in required reports and certifications.

In conclusion, regular review of U.S. EPA’s ADI will keep facilities informed of potentially beneficial regulatory determinations that affect your industry and facility.  ALL4 personnel associated with continuous monitoring systems (CMS) routinely review the ADI to stay current with U.S. EPA determinations and can provide valuable insights into your specific facility CMS concerns.  If you have any questions, feel free to reach out to ALL4 Staff.


1 ADI Control Numbers 1600012 and 1600013
2 ADI Control Number 1600028
3 ADI Control Number M160019
4 ADI Control Numbers 1600009, 1600027, 1600032, and 1600033
5 ADI Control Number 1600009
6 ADI Control Number 1600027
7 ADI Control Number 1600032
8 ADI Control Number 1600033
9 ADI Control Number 1600038


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