Date: October 11, 2012 

To: Brenda Shine, EPA/OAQPS/SPPD 

From: Jeff Coburn 

Subject: Meeting Minutes for October 11, 2012, Meeting Between the U.S. EPA and 

Representatives of the Petroleum Refining Industry 

On October 11, 2012, representatives of the U.S. Environmental Protection Agency 

(EPA) and their contractor (RTI International) participated in a meeting with representatives of 

the American Petroleum Institute (API), the American Fuel & Petrochemical Manufacturers 

(AFPM), and the petroleum refining industry. The names and affiliations of the participants are 

included in Attachment 1. The major discussion points are provided below. 

Sector Rule Package 

Industry representatives asked about the status of the Sector Rule package. The EPA 

stated that the Sector Rule package was currently at the Office of Management and Budget 

(OMB) and that it was anticipated that OMB would take the full 90 days to review, so the rule is 

likely to be released near the end of December. 

Industry asked specifically about the current provisions for delayed coking units (DCU). 

The EPA indicated that the rule currently at OMB included a venting pressure limit for the coke 

drum as well as an alternative temperature limit based on the saturated steam temperature at the 

pressure limit; the facility can chose the parameter it would prefer to monitor. The EPA noted 

that there were still uncertainties with the analysis of the source test data and were unsure if these 

data can be used to support the position that there is not an emissions reduction when reducing 

the allowable drum venting pressure from 5 pounds per square inch (psig) to 2 psig. If draining is 

initiated shortly after venting, the emissions from the drum vent would be lower, but the 

emissions from the drain pit area likely to be higher. The higher the drum pressure/temperature 

when venting is initiated, the higher the greater the expected emissions, but these emissions may 

be released mostly from the vent (if draining is not initiated quickly) or from the drain and pit 

area (if draining is initiated quickly). If the drum is vented to the closed blowdown system 

longer, these emissions would be captured rather than emitted. Industry representatives stated 

that they would arrange a meeting with coker experts to help the EPA better understand the 

operations of the units tested. In response to industry questions, the EPA provided a brief 

description of the impact modeling assumptions used to determine the incremental costeffectiveness of the DCU control options. The industry representatives requested a copy of the 

impacts documentation so they could provide comments on the costs assumptions prior to 

proposal. 
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Industry representatives then asked about the provisions for startup and shutdown 

included in Sector Rule package. The EPA stated that the Sector Rule package included 

provisions for shutdown of a sulfur recovery plant; during shutdown of a sulfur recovery unit the 

tail gas could be sent to a thermal oxidizer operated at a minimum specified temperature or to a 

flare. For fluid catalytic cracking units (FCCU), an alternative limit to the 1-hour CO emissions 

limit was being provided for startup; the alternative limit was a minimum oxygen content in the 

exhaust gas (as an indicator of complete combustion). The industry representatives asked about 

maintenance allowances or alternative limits for periods when FCCU feed hydrotreater was 

down for maintenance [requested as one of the 40 CFR Part 60 Subpart Ja (Refinery NSPS) 

reconsideration issues]. The EPA indicated that there were no provisions for alternative emission 

limits during these types of maintenance periods. 

Flare Combustion Efficiency 

Industry representatives provided a presentation on the concept of allowing refineries to 

develop flare-specific plans to ensure adequate combustion efficiency is maintained for each 

flare. Details of this discussion are included in a separate memorandum that summarizes all of 

the industry meetings regarding flare combustion efficiency. See memorandum from Jeff 

Coburn, RTI International, to Andrew Bouchard and Brenda Shine, EPA/OAQPS/SPPD, 

Meeting Minutes for Meetings Between the U.S. EPA and Petroleum Refinery Industry 

Representatives regarding Potential Flare Performance Standards: December 8, 2011; March 

21, 2012; October 11, 2012; February 19, 2013; and March 19, 2013, dated March 28, 2013. 

Subpart Ja 

Industry representatives indicated that they have several issues with the final Subpart Ja 

rule that was recently published. First, there are issues related to the inclusion of interconnected 

flares within the definition of flares and how this impacts the monitoring requirements (e.g., total 

flow to the flare when there are multiple flare tips in the affected flare facility). Industry 

representatives also noted that there were issues with “temporary” interconnections or 

connections to temporary flares. EPA indicated that it may be possible to address many of these 

issues through guidance. For example, guidance could be given with respect to acceptable 

monitoring locations, the distinction between interconnected flares and cascaded flare systems, 

etc., and that such guidance can be provided more quickly than technical corrections. The EPA 

noted that real life scenarios of interconnected flare systems, like those provided regarding flare 

combustion efficiency, would be useful to better understand the issues and to determine the 

appropriate path forward; the industry representatives agreed to prepare case study examples. 

Second, industry representatives expressed concern regarding the definition of DCU 

because the inclusion of piping and other specific equipment suggests that any addition of a 

sampling line, instrumentation, or safety valve would be an increase in emissions (from fugitive 

components covered by 40 CFR Part 60, Subpart GGG/GGGa) and would trigger a modification 

under Subpart Ja. According to the industry representatives, this has the effect of creating a 

“quick trigger” for DCU. 

Third, industry representatives requested clarification regarding the different compliant 

dates based on the different definitions for DCU. Based on preamble discussion, the newest 
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definition is characterized as providing detail to the unit definition, not necessarily changing 

what was considered to be part of the unit. Industry representatives asked if the fugitive 

components that they are concerned about would be considered part of the DCU only under the 

most recent (newly published) definition of DCU. The EPA indicated that was their 

understanding/intent. 

Fourth, industry representatives expressed concern regarding the requirements for the 

oxygen (O2) monitor specifications for smaller process heaters when a NOx continuous emission 

monitoring system (CEMS) is not present. Typically, process O2 monitors are not the same as 

CEMS O2 monitors. The rule refers to these monitors as simply O2 monitors (not CEMS), but 

cross-references O2 CEMS requirements for performance specifications and relative accuracy 

tests. Industry representatives stated that existing process O2 monitors may need to be replaced 

with CEMS-caliber O2 monitors (or new monitors added) to meet the cross-referenced CEMS 

requirements. EPA indicated that this was not the intent and that the O2 monitor was expected to 

be a continuous parameter monitoring system (CPMS) rather than a CEMS. 

Heat Exchange System Amendments 

Industry representatives asked about the status of the heat exchange system (HES) 

amendments. The EPA noted that the package was nearing completion, but was still a month or 

two from going to OMB. In any event, the final amendments would not be completed prior to the 

October 29, 2012, compliance date. The EPA stated that some of the issues, such as sampling in 

a representative riser, were minor and that the existing rule can be interpreted to allow this. The 

EPA also noted that sample coolers were never considered HES and that these systems would 

not need to be monitored. The proposed amendments provided an alternative quarterly 

monitoring frequency at a lower detection level; this provision did not receive any adverse 

comments and will be included in the final HES amendments. The proposed rule also included 

water methods as an alternative to the El Paso stripping column method. Currently, the EPA does 

not expect to finalize the water method alternatives based on the comments concerning the 

difficulty with full characterization of all compounds potentially present in the cooling water. 

The EPA noted that suggestions to limit the target analyte list were not acceptable. API/AFPM 

indicated that they may provide feedback regarding the need (or lack of need) for water methods. 

Follow-up Items 

 EPA. Provide documentation of DCU impacts. 

 API/AFPM. Arrange meeting with delayed coking unit experts to discuss source test data 

anomalies and potential reasons for the anomalies. 

 EPA. Review flare combustion efficiency plan information and provide comments/ 

questions to API/AFPM in approximately 2-3 weeks (one week prior to next flare 

combustion efficiency working group meeting). 

 API/AFPM. Develop specific interconnected flare case study examples to focus a 

discussion of issues concerning the Subpart Ja requirements for interconnected flares. 

 API/AFPM. Provide feedback regarding not including water method alternatives in the 

heat exchange system package. 
Attachment 1 

Participants in October 11, 2012 EPA/Refining Industry Meeting 

Industry Representatives 

Matt Todd, API 

John Wagner, API 

Bob Hermanson, BP 

Clay Freeberg, Chevron 

George Graham, ExxonMobil 

Charlie Bennett, Marathon Petroleum 

Erin Tullos, Phillips66 

Frank Tracy, Phillips66 

John Askounis, Phillips66 

Shari Keller, Shell 

Norm Morrow, Fresh Air Consulting 

U.S. EPA Representatives 

Andrew Bouchard 

Brenda Shine 

Penny Lassiter 

Peter Tsirigotis (for portions) 

Sue Stahle 

Jan Tierney 

RTI International (EPA contractor) 

Jeff Coburn