### Date: January 11, 2010
To: Docket ID No. EPA-HQ-OAR-2007-0011

From: Kristin Parrish Sroka
Subject: NSPS Subpart J Review: Meeting Minutes for July 16, 2009, Conference Call Between the U.S. EPA and Representatives of Lion Oil

Introduction

On June 30, 2009, representatives of the U.S. Environmental Protection Agency (EPA) and their contractor (RTI International) participated in a stakeholder conference call with representatives of Lion Oil Company (Lion Oil). The names and affiliations of the participants are included in Attachment 1. Attachment 2 contains the background information provided by the Lion Oil representatives prior to the conference call. Attachment 3 contains more detailed information regarding flare sampling provided byLion Oil in response to the EPA’s request during the call. The purpose of the conference call was to discuss the requirements for monitoring flares in NSPS subpart Ja, particularlyfor flares with flare gas recovery systems.

Discussion

The Lion Oil representatives noted that they have safety concerns with testing and Relative Accuracy Test Audit (RATA) requirements that would require operators to be close to a flare. They noted that, for safety reasons, personnel must stay a certain distance from the flare at all times and must wear protective clothing before they can approach any closer. No one is allowed to climb up to the flare tip because flarescannot be isolated and there is no way to be sure that no gas will be flared while a worker is close to the flare. They noted that to comply with safety requirements, a monitor would have to be located at least 125 feetfrom base of flare, and depending on the height of the flare, that could be 200 feet from the flare tip.

In addition, the Lion Oil representatives notedthat the sulfur c oncentration can range from less than 10 ppmv up to 50,000 ppmv. They statedthat it is difficult to span a monitor to accurately measure that range of concentrations. For the above reasons, the Lion Oil representatives asserted that for flares that rarely experience flaring events, there are better ways to quantify emissions than monitoring.

The Lion Oil representatives stated that the fl ares at their refinery are used mostly as control devices, and they usually collect more than 99 percent of the gas sent to the flare. Although they try to use excess fuelgas in the hydrogen plant as much as possible, the refinery

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occasionally has more fuel gas than needed for current operations ( i.e. , is long on fuel gas) and must flare the excess.

The Lion Oil representative s then described their fl are gas recovery system configurations and their emissions estimation procedures. Both the high pressure flare and low pressure flare at the refinery have flare gas recovery systems with a knockout drum and water seal. Each system has staged compressors, one of which is always running. The pressure is monitored so that additional compressors can start up when needed. Regarding the location of the water seal (see diagram in Attachment 2) , the Lion Oil representatives noted that their configuration was designed by John Zink Company and they are not sure how many other flare gas recovery systems in the petroleum refining industry might be designed with the water seal in the same location.

The differential pressure is monitored at the water seal, and a pressure exceedance that breaks the water seal is considered a flaring event. Lion Oil calculates flaring event emissions using the monitoring results for pressure, flow rate, and composition of the flare gas. The flow rate is monitored by a Panametrics flow meter between the knockout drum and flare. During a flaring event, a sample of the flare gas is collected and analyzed using gas chromatography (GC). The GC analysis is typically measuring hydrogen sulfide (H 2 

### S) and organic compounds; the Lion Oil representatives noted that it may be possible to measure total reduced sulfur if necessary.

The Lion Oil representatives then identified specific issues with the EPA’s proposed monitoring provisions for subpart Ja . First, although the compressors in their flare gas recovery system are closely calibrated, the second and third compressor cannot start up instantaneously without burning out the motor. Instead, it takes about 1 to 5 minutes for the additional compressor to be fully operational. Lion Oil is reporting all of thes e “burps” because the H 2 

### S concentration is above 160 ppmv. The Lion Oil representatives noted that these “burps” are likely exempt from the 160 ppmv H 2 

### S limit because they are proce ss upsets, but they choose to report all of them as emissions exceedances rather than having to prove that each exceedance is caused by an upset. However, the Lion Oil repres entatives did note that this practice increases the amount of time needed to prepare semiannual reports. In addition, they are worried that this practice, although environmentally conservative, opens them up to accusations of violations.

Going forward, the Lion Oil representatives noted that they would continue to quantify emissions for compressor staging “burps,” but they would like to avoid having to do a root cause analysis for each exceedance, particularly becausethere is not much they can do to prevent the “burps.” They requested that the EPA add a provision to subpart Ja that states if the water seal breaks but emissions are below 500 pounds of sulfur dioxide (SO 2

### ) per day, a root cause analysis is not needed. They also noted that it would help if the EPA could clarify whether the “burps” are really violations.

Another issue the Lion Oil repres entatives noted with the subpart Ja standard as it applies to flares with flare gas recovery systems isthe format of the concentration limit and how averages are calculated. Even one minute of flare gas with a concentration of 50,000 ppmv (5 percent) H 2 

### S causes the flare to exceed the 3-hour 160 ppmv concentration limit. However, because their recovery system is state-of-the-art and highly efficient, the Lion Oil representatives

### 3

feel they would be better able to meet a percent reduction target. The Lion Oil representatives suggested that the EPA should provide an option toconsider a flare witha flare gas recovery system to be a control device required to meet a percent reduction emission limit. They also noted that a de minimisbright line would help define gray areas. The Lion Oil representatives noted that they would be happy to meet with the EPA again to further discuss their recovery system and their specific requests.

The EPA representatives agreed that it would beideal for the provision s of subpart Ja to be written such that installation of flare gas recovery systems is encouraged. They noted that the monitoring systems on the flare gas recovery system at the Lion Oil refinery seem to be good for quantifying emissions, and they noted that sampling during a flaring event is a good compromise between continuously monitoring the sulfur content of flare gas and no monitoring at all. Regarding root cause analyses, the EPA repres entatives noted they w ould consider allowing facility to explain upfront that “burps” are the result of compressor staging. Regarding the de minimisbright line, the EPA representatives noted that it is difficult to draw a bright line because other recovery systems are not as good as the one at Lion Oil, particularly regarding the quantification of SO 2

### emissions. The EPA representative s requested a description of the monitoring system for the record, including cost estimates for sampling and laboratory labor. (The information provided by Lion Oil followingthe call is included in Attachment 3.)

Finally, the EPA representatives and Lion Oil representatives discussed the answers to the questions posed in Attachment 2. For Item 1, the EPA representatives noted that if the H 2 

### S concentration of a gas stream is being continuously monitored to ensure compliance with the 160 ppmv concentration limit, the facility could use the H 2 

### S-to-sulfur ratio option to determine the total reduced sulfur concentration in that stream. The Lion Oil representatives then noted that they have one fuel gas sy stem providing fuel gas to the fl ares as well as other combustion devices. They asked, assuming that all the gas being flared is from the fuel gas system, whether they would be permitted to use the information obtained from a boiler’s SO 2

### continuous emissions monitoring system (CEMS) to estimate SO 2

### emissions from the flare (rather than determining the H 2 

### S-to-sulfur ratio). The EPA representatives noted they would consider whether to provide that option.

The EPA representatives agreed with Items 2 and 6. They also agreed with Item 3, with the caveat that their response to Item 1 would have to be taken into account. For Item 5, they agreed that continuous monitoring is meaningless when there is no flow, but they noted they had not yet decided how to handle that issue. According to 40 CFR part 60, a source is required to have valid data for four quadrants of an hour, but they recognize that isnot always likely to happen.

### Attachment 1 Participants in July 16, 2009, Conference Call

Industry Representatives Ray Callahan, Ergon George Garten, Lion Oil Company Chuck Hammock, Lion Oil Company

U.S. EPA Representatives Bob Lucas Brenda Shine

RTI International (EPA contractor) Jeff Coburn Kristin Parrish

### Attachment 2

Background Information

Flare Monitoring Questions

### Conference Call to Discuss Questions a bout Flare Monitoring under proposed 40 CFR 60, Subpart Ja

Thu 07/16/200910:00 AM - 12:00 PM

Chair: George.Garten@lionoil.com Location: Conference Call Required: Bob Lucas/RTP/USEPA/US, Chuck. Hammock@lionoil.com, Paul.Young@ergon.com Time zones: This entry was created in a different timezone. The time in that time zone is: Thu 07/16/2009 9:00 AM CDT11:00 AM CDT

Mr. Lucas

Please find the call in information below. I have also attached a copy of the questions we submitted for those on the meeting invitation who may not have a copy.

<<Lion Oil Company Subpart Ja Flare Monitoring Questions.pdf>>

Call in Information Below: (888) 472-4293; 7994380

# Flare Monitoring Questions

Background Information

Lion Oil Company ("Lion Oil") installed flare gas recovery units ("FGRU's") on the two flare systems at its refinery in EI Dorado, Arkansas. The FGRU's at Lion Oil are adequately sized and have not one but
two back up compressors in parallel for each flare. The FGRU withdraws gas from the flare header upstream of the liquid seal drum and recovers gas that would normally be burned in the flare. The recovery system operates to maintain a slight positive pressure on the flare header upstream of the liquid seal drum, which ensures that air is not drawn into the flare system or the FGRU. When gas is relieved to the flare system, the compressors automatically stage up to handle the increase in volume to the flare system. This
process is not instantaneous and Lion Oil often experiences very small flaring releases, even though the cono'ol system is a state-of-the-art design.

When the refinery is fuel rich excess sweet or NSPS fuel gas is introduced into the flare above the water seal as shown in the attached diagram. This excess fuel gas is monitored by the refinery fuel gas H2S monitor as required by Subpart J-Ja. The additional natural gas purge streams indicated on the drawing are used for flare safety purposes and are exempt from monitoring under the inherently low sulfur exemption.



## Discussion

40 CFR 60.1 07a, Monitoring of emissions and operations for fuel gas combustion devices, states in 60.107a (d) that the owner or operator of an affected flare subject to §60.1 03a (b) shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur in flare gas. The owner or operator of a modified flare shall install this instrument by no later than 1 year after the flare becomes an affected flare subject to this subpart.

(I) The owner or operator shall install, operate, and maintain each reduced sulfur CEMS according to Performance Specification 5 of appendix B to part 60.

(2) The owner or operator shall conduct performance evaluations of each reduced sulfur monitor according
to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSlIASME PTC 19.10-1981, "Flue and Exhaust Gas Analyses," (incorporated by reference-see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

(3) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60 for each reduced sulfur monitor.

Based on the required monitoring in 60.107a (d) Lion Oil Company has several questions and areas of

concern.


## Safety Issues

Thermal radiation exposure during a flaring event is a concern for Lion Company. Locating a probelsample line system in the flare stack and a CEMS building in close proximity presents an opportunity for thermal
exposure for refinery and testing personnel. ANSlIAPl Standard 521 recommends that flare system design and plant equipment layout should minimize the need for operator exposure when at all possible. Conducting routine maintenance, RAT As would require personnel to be in danger of thermal exposure.

### Flare Monitoring

I. The attached diagram shows the relative location of each gas stream entering into the flare. The drawing shows that when the refinery is fuel rich, which is defined as having excess refinery fuel gas, this gas is introduced into the flare above the water seal in a separate line. This excess fuel gas is part of the refinery

common fuel gas system and is less than 160 ppm H2S and is monitored by the refinery fuel H2S gas analyzers.

a) Lion Oil Company's interpretation is that since the excess refinery fuel gas meets all of the Subpart J fuel gas requirements and has previously been monitored it would not have to be monitored for TRS. Does EPA agree?



### 2. Also you will notice on the diagram some natural gas streams that are introduced to the flare for safety
purposes.

b) Based on Lion Oil Company's interpretation these streams are exempt from TRS monitoring based on the fact that purchased Natural Gas is inherently low sulfur

.. Does EPA agree?



### 3. Based on the fact that Lion Oil Company has interpreted that both the natural gas and the excess refinery fuel gas is exempt from TRS monitoring that would leave monitoring just the sour gas for TRS during the times when the water seal is broken during a flaring event.

c) Does EPA agree?



### 4. Assuming that the sour gas line is the only line that needs to be monitored for TRS then a better approach from a safety standpoint would be to monitor the horizontal line coming to the flare. This approach would limit the likelihood of thermal exposure by refinery personnel. Monitoring in the horizontal will also reduce the CEMS sample system length allowing for a more reliable system.

d) Does EPA agree with the monitoring approach in the horizontal?



### 5. Based on the above monitoring interpretations the sour gas stream would be exempt from the monitoring requirement in 60.102a (g)(ii) for compliance with the 3-hour rolling average 160 ppm H2S standard. This horizontal line is stagnant except during flaring events that break the water seal. Monitoring for the
purpose of developing a 3-hour rolling average for H2S is meaningless considering the majority of flaring
events are very short in duration and the next flaring event could potentially be several hours, days or weeks later making it impossible to meet the valid data requirements of 40 CFR Part 60 and calculate a valid 3-hour rolling average.

e) Does EPA agree with this approach as well?



### QA/QC

6. The horizontal line to the flare from the FGRU is a stagnant line except during a flaring event. As described above the flaring events are not long in duration or predicable making conducting a RATA on a stagnant line virtually useless as far as 40 CFR Part 60 is concerned. Lion Oil Company proposes to conduct 4 quarters of Cylinder Gas Audits in lieu of conducting an annual RATA.

f) Would EPA agree with this approach?

### Attachment 3

Follow-up Information

Requested Flare Sampling Information

### From: "George Garten" <George.Garten@lionoil.com> To: Bob Lucas/RTP/USEPA/US@EPA Cc: Brenda Shine/RTP/USEPA/ US@EPA, "Chuck Hammock" <C huck.Hammock@lionoil.com>, "Ray Callahan" <Ramon.Callahan@ergon.com> Date: 07/24/2009 12:40 PM Subject: RE: Requested Flare Sampling Information - Lion Oil Company

Mr. Lucas

Please find the attached flare sampling description that was requested during our conference call on July 16, 2009. Please contact me with any questions or addi tional information requests. We are available if you feel an additional conference call would be beneficial. Thanks again for your consideration concerning this matter and we look forward to hearing from you and your staff.

Sincerely,

George Garten Lion Oil Company

mailto:george.garten@lionoil.com 870.864.1453 (voice) 870.864.1165 (fax)

<<Lion Oil Company Flare Gas Sampling Information .pdf>>

### Lion Oil Company ("Lion Oil") has installed flare gas recovery units ("FGRU's") on the two flare systems at its refinery in EI Dorado, Arkansas. The FGRU's at Lion Oil are adequately sized and have not one but two back up compressors in parallel for each flare. The seal for each flare system consists of a 30 inch water seal which is located at the base of each flare stack. (See Figure 1A)

The FGRU withdraws gas from the flare header upstream of the liquid seal drum and recovers gas that would normally be burned in the flare. The recovery system operates to maintain a slight positive pressure on the flare header upstream of the liquid seal drum, which ensures that air is not drawn into the flare system or the FGRU. When gas is relieved to the flare system, the compressors automatically stage up to handle the increase in volume to the flare system. This process is not instantaneous and Lion Oil often experiences small flaring releases, even though the control system is a state-of-art design. There are other process unit startups, shutdowns and malfunctions that also result in these micro flaring events.

The above mentioned water seal is monitored on a continuous basis and when the water seal is broken, which indicates a flaring event is occurring a signal is sent to the sample collection system to begin the sampling sequence. There is a delay in the sample collection in order to make sure the horizontal flare line has been purged, which allows for collection of a representative sample. After completion of the delay a solenoid opens allowing the flare gas sample pump to fill the sample canister with a gas sample from the horizontal flare line.

When the water seal is broken, an automatic email is sent to Lab personnel, Operations personnel and the Environmental department. The lab personnel then collect and analyze the flare gas sample via GC and provide the results to the Environmental Department for emissions quantification. The sample gathering and analysis takes about 1 hour.

The emissions are quantified using the flare gas analysis and the monitored flow during the flaring event. The flow is measured using a Panametrics measurement system that corrects for temperature, pressure and also measures molecular weight.

The flare gas sample collection system consists of a sample pump, heated sample line, in-line filter, solenoids and sample canister. The sample system currently utilized was designed in house at a cost of approximately $5000-10,000 (See Figure 1 B). A similar type system has been developed by Texas Sampling (www.TexasSampling.com) at an approximate cost of $26,000-$30,000. (See Figure 1C)