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 In ternational) participated in a stakeholder meeting with representatives of the American Petroleum Ins titute (API), National Petrochemical & Refiners Association (NPRA), Western Stat es Petroleum Association (WSPA ), and the petroleum refining industry. The names and affiliations of the part icipants are included in Attachment 1. The purpose of the meeting was to discuss various is sues regarding the EPA’s reconsideration of NSPS subpart Ja.

The industry representatives noted that wh ile they are members of unifying trade organizations, they do represent individual comp anies 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, esp ecially if the questions relate to projects that have not yet been publicly announced. However, they did note that individual representative s may choose to reply to questions outside of the general meeting.

The industry representatives noted that onl y 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 representa tives noted the Agency is waiting to ascertain
the Administration’s direction on GHG before m oving forward with addr essing 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.2

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 (SO 2 ) 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 (H 2 S) limits, those gases are still covered by a sta ndard. They noted that startup and shutdown conditions often include nitrogen purges, and th e heat content is too low for any combustion device other than a flare. The industry representa tives 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 H 2 S 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 pe r day (scfd) is best demonstrated technology (BDT). The industry representa tives 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 repr esentatives 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 start ups and shutdowns already covered in the FMP, and the large number of RCA woul d make it difficult for enforcement to determine when there really are operation issues with a flare.

The EPA representatives stated that they unders tand the need to have constant flow to the flare to ensure proper op eration, but it was their understandin g that the flow required would be below the limit. They requested information on th e magnitude of these constant flows and asked why purge gas cannot be recovere d. The industry representatives responded that the purge gas helps raise the heat content of th e 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 ga s. The industry representatives further noted that there are a large number of variables in a flare system, a nd even allowing each refinery to develop a site-specific RCA trigger will not be flexible enough. The industry representatives suggested that there may be severa l 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 manage ment 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 rede fining the applicability date for process heaters and flares is a high priority for them. The EPA representatives noted that they had not3

discussed the issue with their Office of General Counsel, so they could not comment on the status of that request. The industry representati ves noted that the proce ss heater limits would be
less of a concern if th e applicability date for process heaters was moved. The industry representatives also noted that a related issue is timing of comp liance 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 di d not know what the requirements would be once the stay was lifted. They also noted that th ere is some question as to when the clock starts regarding construction a nd modification. If an owner or ope rator 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 existi ng flare because the project began prior to June 2008? One company has an actual example of this concern; a reactor wa s ordered in the middle of 2007, but the tie-in to the ex isting flare will not be comple ted 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 routin e flaring from fuel gas produci ng units that become subject to subpart Ja and asked the industry representatives to describe thei r alternative. The industry representatives noted they agr ee that reducing flaring is a goo d 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 pr ocess 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 requ irement to perform a root cause analysis (RCA)
if releases of SO 2 from a flaring device exceed 50 0 pounds in a 24-hour period, which is
included in a number of the consen t decrees. In addition, the i ndustry representatives suggested an alternate compliance option of 500 pounds of SO 2 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 SO 2 limit was exceeded. The industry representatives noted that for the purposes of their altern ative proposal, the 500 pounds of SO 2 is
an absolute value rather than an increment above a permitted limit.

The EPA representatives asked for more specifi cs regarding the FMP, in particular what they would include, how they would be enfo rceable, and how they would demonstrate continuous compliance ( e.g. , continuously monitoring flow a nd 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 th at the FMP should be pub licly available in some form, so the level of detail required will need to be considered carefully. The EPA representatives also requested a ny available data comparing the SO 2 emissions resulting from the limits of 500 pounds of SO 2 per day per flare and 160 ppm H 2 S in fuel gas.4

Other Issues

During the course of the discussion, several a dditional topics were raised, including: (1) NO X levels for process heaters that can be achieved solely by combustion modifications; (2) levels of reduced sulf ur compounds other than H 2 S in coker fuel gas; and (3) the need for condensable PM testing for flui d catalytic cracking units (FCCU) using EPA’s newly developed condensable PM test method. The industry repres entatives were not prepared to discuss these issues at that time but offered to follow up on th ese items. Finally, the industry representatives asked if the EPA could provide a ny updates on the issue of regulating climate change pollutants. The EPA representatives responded that the Admi nistrator has not yet made a decision on the best procedure for regu lating those pollutants.

Industry Follow-Up Actions

• Provide additional data on what NO X levels can be achieved in process heaters using only combustion modifications and optimization.

• Describe preventative maintenance actions fo r sulfur pits and speci fy reasonable periods during which sulfur pits could be vented duri ng that preventative ma intenance. Quantify

SO 2 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 re duced sulfur compounds from coking units. Evaluate the feasibility of meeting the redu ced sulfur limit on fuel gas by mixing fuel gas
that has been treated to a level well below the H 2 S fuel gas limit with the fuel gas from a coking unit that includes reduced sulfur compounds. Quantify SO 2 emissions resulting
from the combustion of non-H 2 S sulfur compounds in fuel gas produced by a coking unit.

• Provide any ideas on how the FMP would demons trate, on a continuous basis, that a flare will not exceed 500 pounds of SO 2 per day. Provide any available data comparing the

SO 2 emissions resulting from the limits of 500 pounds of SO 2 per day per flare and 160 ppm H 2 S 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