Date: April 13, 2009 

To: Docket ID No. EPA-HQ-OAR-2007-0011 

From: Kristin Parrish 

Subject: NSPS Subpart J Review: Meeting Minutes for March 2, 2009, Meeting Between 

the U.S. EPA and Representatives of the Petroleum Refining Industry 

Introduction

On March 2, 2009, representatives of the U.S. Environmental Protection Agency (EPA) 

and their contractor (RTI International) participated in a stakeholder meeting with 

representatives of the American Petroleum Institute (API), National Petrochemical & Refiners 

Association (NPRA), Western States Petroleum Association (WSPA), and the petroleum refining 

industry. The names and affiliations of the participants are included in Attachment 1. The 

purpose of the meeting was to discuss various issues regarding the EPA’s reconsideration of 

NSPS subpart Ja. 

The industry representatives noted that while they are members of unifying trade 

organizations, they do represent individual companies that compete against one another. 

Therefore, company representatives may not be able to supply detailed answers to the EPA’s 

questions at a general meeting, especially if the questions relate to projects that have not yet been 

publicly announced. However, they did note that individual representatives may choose to reply 

to questions outside of the general meeting. 

The industry representatives noted that only about 1 percent of greenhouse gas (GHG) 

emissions from a petroleum refinery come from flaring (not including emissions from 

combustion of products not at the refinery (e.g., gasoline in a car)). The EPA representatives 

requested supporting data and as well as any ideas on cost effective means for reducing GHG 

from other heaters and boilers. The EPA representatives noted the Agency is waiting to ascertain 

the Administration’s direction on GHG before moving forward with addressing the petition on 

regulating GHG. They also noted that the Agency would like to address the stayed provisions of 

subpart Ja as soon as possible. 
 

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Discussion

Process Upset Gas 

The industry representatives supported the changes to the definition of process upset gas 

to include startups and shutdowns. They noted that they see the flare management plan (FMP) 

and root cause analysis (RCA) for conditions over 500 pounds per day (lb/day) sulfur dioxide 

(SO2) as an emission limit and actions that must be taken when that limit is exceeded; therefore, 

although startup and shutdown are proposed to be exempted from the hydrogen sulfide (H2S) 

limits, those gases are still covered by a standard. They noted that startup and shutdown 

conditions often include nitrogen purges, and the heat content is too low for any combustion 

device other than a flare. The industry representatives also requested the use of other monitoring 

options, such as grab samples for flares that only handle startup, shutdown, and process upsets. 

They clarified that the problem is mainly with the H2S continuous monitoring system (CMS) and 

not as much with a flow monitor. 

Flow Limit for Flares 

The industry representatives stated that the EPA did not properly show that triggering 

RCA for a flare at 500,000 standard cubic feet per day (scfd) is best demonstrated technology 

(BDT). The industry representatives noted that for some flares, the combination of purge, 

sweep, and other routine gases is already above 500,000 scfd, so that level becomes a flow rate 

limit and is not cost effective. The industry representatives stated that the trigger for RCA based 

on flow should be a certain amount of flow above routine operation. They noted that it is not 

logical to perform multiple RCA for routine startups and shutdowns already covered in the FMP, 

and the large number of RCA would make it difficult for enforcement to determine when there 

really are operation issues with a flare. 

The EPA representatives stated that they understand the need to have constant flow to the 

flare to ensure proper operation, but it was their understanding that the flow required would be 

below the limit. They requested information on the magnitude of these constant flows and asked 

why purge gas cannot be recovered. The industry representatives responded that the purge gas 

helps raise the heat content of the gas being flared and so must go to the flare header. It may be 

possible to recover the gas and recycle it, but since the purge gas has been mixed with other 

gases by then, it cannot be used again as purge gas. The industry representatives further noted 

that there are a large number of variables in a flare system, and even allowing each refinery to 

develop a site-specific RCA trigger will not be flexible enough. The industry representatives 

suggested that there may be several ways to cover leakage, such as defining leakage as a certain 

percentage of flow above baseline. The EPA representatives noted that they would need a 

mechanism in subpart Ja to address flare management plans that show a high-magnitude baseline 

flow with high enough heat content to recover and a high percentage of VOC. 

Applicability Date / Timing of Compliance 

The industry representatives stated that redefining the applicability date for process 

heaters and flares is a high priority for them. The EPA representatives noted that they had not 
 

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discussed the issue with their Office of General Counsel, so they could not comment on the 

status of that request. The industry representatives noted that the process heater limits would be 

less of a concern if the applicability date for process heaters was moved. The industry 

representatives also noted that a related issue is timing of compliance for owners and operators 

installing flare gas recovery on a modified flare. They stated that for projects begun between 

June and December 2008, owners and operators did not know what the requirements would be 

once the stay was lifted. They also noted that there is some question as to when the clock starts 

regarding construction and modification. If an owner or operator made a contractual obligation 

in December 2007 to tie a new process unit into an existing flare but the new unit is not tied into 

the existing flare until July 2008, is the flare considered modified based on the date of the tie-in, 

or does it continue to be considered an existing flare because the project began prior to June 

2008? One company has an actual example of this concern; a reactor was ordered in the middle 

of 2007, but the tie-in to the existing flare will not be completed until 2009 or 2010. The EPA 

representatives acknowledged that was a question that needed to be addressed based on the 

definition of “commence” in the 40 CFR part 60 general provisions. 

Flare Minimization 

The EPA representatives noted that the public comments included an alternative to the 

EPA’s proposal to eliminate routine flaring from fuel gas producing units that become subject to 

subpart Ja and asked the industry representatives to describe their alternative. The industry 

representatives noted they agree that reducing flaring is a good idea for many reasons, but the 

EPA’s proposal may not be feasible for all facilities. The industry representatives stated that the 

affected source should be the flare itself, not a process unit that produces gas that may be flared. 

The industry’s alternative includes a flare management plan (FMP) to address procedures during 

startups, shutdowns, and upsets, as well as a requirement to perform a root cause analysis (RCA) 

if releases of SO2 from a flaring device exceed 500 pounds in a 24-hour period, which is 

included in a number of the consent decrees. In addition, the industry representatives suggested 

an alternate compliance option of 500 pounds of SO2 per day per flare as an alternative to 

complying with the fuel gas standards. If a facility elected to comply with the alternate 

compliance option for a flare not already subject to subpart Ja, a FMP would be required for all 

the refinery’s flares, and a RCA would be required if the SO2 limit was exceeded. The industry 

representatives noted that for the purposes of their alternative proposal, the 500 pounds of SO2 is 

an absolute value rather than an increment above a permitted limit. 

The EPA representatives asked for more specifics regarding the FMP, in particular what 

they would include, how they would be enforceable, and how they would demonstrate 

continuous compliance (e.g., continuously monitoring flow and sulfur content). The industry 

representatives responded that the details surrounding the FMP have not been completely 

developed, and they would like to work with the EPA to establish FMP that are workable for 

both sides. They noted that an FMP would need to address all streams, regardless of sulfur 

content. The EPA representatives noted that information on any options considered by the 

industry would be helpful, and they also noted that the FMP should be publicly available in some 

form, so the level of detail required will need to be considered carefully. The EPA 

representatives also requested any available data comparing the SO2 emissions resulting from the 

limits of 500 pounds of SO2 per day per flare and 160 ppm H2S in fuel gas. 
 

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Other Issues 

During the course of the discussion, several additional topics were raised, including: 

(1) NOX levels for process heaters that can be achieved solely by combustion modifications; 

(2) levels of reduced sulfur compounds other than H2S in coker fuel gas; and (3) the need for 

condensable PM testing for fluid catalytic cracking units (FCCU) using EPA’s newly developed 

condensable PM test method. The industry representatives were not prepared to discuss these 

issues at that time but offered to follow up on these items. Finally, the industry representatives 

asked if the EPA could provide any updates on the issue of regulating climate change pollutants. 

The EPA representatives responded that the Administrator has not yet made a decision on the 

best procedure for regulating those pollutants. 

Industry Follow-Up Actions

• Provide additional data on what NOX levels can be achieved in process heaters using only 

combustion modifications and optimization. 

• Describe preventative maintenance actions for sulfur pits and specify reasonable periods 

during which sulfur pits could be vented during that preventative maintenance. Quantify 

SO2 emissions that would be expected from venting to the atmosphere during those times 

as well as emissions expected from shutting down the process. 

• Provide additional data on the issue of reduced sulfur compounds from coking units. 

Evaluate the feasibility of meeting the reduced sulfur limit on fuel gas by mixing fuel gas 

that has been treated to a level well below the H2S fuel gas limit with the fuel gas from a 

coking unit that includes reduced sulfur compounds. Quantify SO2 emissions resulting 

from the combustion of non-H2S sulfur compounds in fuel gas produced by a coking unit. 

• Provide any ideas on how the FMP would demonstrate, on a continuous basis, that a flare 

will not exceed 500 pounds of SO2 per day. Provide any available data comparing the 

SO2 emissions resulting from the limits of 500 pounds of SO2 per day per flare and 160 

ppm H2S in fuel gas. 

• Provide any suggestions for establishing a cooperative testing program to provide the 

EPA with test data on condensable PM from FCCU. 
Attachment 1 

Participants in March 2, 2009, Meeting 

Industry Representatives

Charlie Bennett, Marathon Petroleum 

Dennis Bolt, WSPA 

Ron Chittim, API 

Chris Colman, HOVENSA 

Luis Comas, Sunoco Inc. 

Chuck Ferrick, Exxon Mobil 

David Friedman, NPRA 

Clay Freeburg, Chevron 

Matt Hodges, Valero Energy Corp. 

Jan Laughlin, ConocoPhillips 

Jack McClure, Shell 

Norman Morrow, Fresh Air Consulting 

John Wagner, API 

Bill Wehrum, Hunton & Williams 

U.S. EPA Representatives

KC Hustvedt 

Bob Lucas 

Brenda Shine 

Susan Stahle 

Peter Tsirigotis 

RTI International (EPA contractor)

Jeff Coburn 

Kristin Parrish