From: "Ron Chittim" <Chittim@api.org> 

To: Ken Hustvedt/RTP/USEPA/US@EPA, Brenda Shine/RTP/USEPA/US@EPA, Bob 

Lucas/RTP/USEPA/US@EPA 

Date: 07/22/2009 08:11 AM 

Subject: API-NPRA-WPSA Comments on Three NSPS Ja Issues

K.C.: 

Attached are comments from API, NPRA & WSPA on three issues we have been discussing lately with 

EPA: process heater turndown; temporary flare situations; and flare H2S mass limit alternate. We will be 

contacting you soon to talk about follow-up discussions on these comments. We thank you in advance 

for your consideration of these comments. Please feel free to contact me if you have any questions.

Ron Chittim

API

1220 L Street, NW

Washington, D.C. 20005

202/682-8176

chittim@api.org

(See attached file: API-NPRA-WPSA Comments on Three NSPS Ja Issues.doc)
Comments on Three Subpart Ja Issues from the American Petroleum Institute (API), the 

National Petrochemical and Refiners Association (NPRA) and the Western States 

Petroleum Association (WSPA)

July 21, 2009

Process Heater Turndown

For process heaters in the 40-100 MMBTU/hour range, Subpart Ja relies on oxygen monitoring 

to demonstrate continuous compliance with the NOx emissions limitation demonstrated during 

the biennial performance test. That is, the stack oxygen level must be maintained at or below the 

level at which the performance test showed that the required NOx emission level is achieved. 

As we have discussed, the proposed NOx emission levels (concentration or emission factor), 

calculated at 0% excess air, are not achievable as process heaters turndown. This is because 

NOx concentrations and emission factors increase, primarily due to the fact that as process 

heaters equipped with low NOx and ultra-low NOx burners turndown below 50% of design 

firing, the percent of excess air in the stack increases. Excess air increases because process heater

draft must be maintained to keep firebox pressures positive for safety reasons and because burner 

operation and burner air rates must be maintained to assure proper mixing for NOx control and 

proper and safe flame patterns and firebox heat transfer. Because of this excess air, NOx 

concentrations adjusted to 0% O2 increases as firing is reduced. We believe that, on a mass 

emitted basis, the increase in NOx concentration is offset by the reduced firing down to at least

20% of firing and therefore have suggested a mass emission limit be allowed below 50% firing

as an alternate to the concentration or emission rate limit. Every process heater is different, 

however, and in some cases the NOx mass emissions at a firing rate below 50% will be 

somewhat higher than the NOx mass emitted at 50%, though certainly less than the NOx mass 

emitted at design firing. Therefore, we believe sources need to be allowed to establish the mass 

limit, at whatever level of firing has the highest controlled NOx mass emission level below 50% 

firing.

Our experts do not believe there is any parameter other than oxygen that is a reasonable 

operating parameter for demonstrating ongoing compliance during turndown operation. 

However, as discussed above, the oxygen level associated with low NOx operation at 50% of 

firing cannot be maintained as the process heater turns down further and thus the operating limit 

should not be set based on a test at the 50% firing point. We believe sources should be allowed 

to establish the O2 operating limit at any firing rate below 50%. Sources should also be allowed, 

at their discretion to test at additional points to establish an O2 operating limit curve. 

Company experts indicate that below approximately 20% of design firing oxygen levels are often 

uncontrollable and often will be in the 10+% range. In fact, at very low firing rates (e.g., <5%) 

process heater excess air may approach ambient air levels. Firing at <20% of design is not 

normal operation (i.e., only occurs during SS&M) for most process heaters, but does represent 

normal operation for certain process heater services, and therefore, needs to be addressed in the 
API/NPRA/WSPA Comments on Three Subpart Ja Issues July 21, 2009

Page 2

Subpart Ja rule. We therefore suggest that the O2 operating limit not apply below 20% of design 

firing. We note that 20% of 40-100MMBTU/hour is 8-20 MMBTU/hour and under this proposal 

the NOx provisions do not even apply to process heaters with design rates below 40 

MMBTU/hour. Thus, it is entirely consistent with the BDT analysis to remove the operating 

limit at such low firing and NOx emission levels. 

While we believe a NOx mass limit established at a firing rate above 20% of design would not be 

exceeded at firing rates below 20%, as we discuss above, sources have little control at such very 

low firing rates and the Agency should consider not imposing a NOx limit at all during such 

operations. 

In our discussions on this issue, we also discovered that proposed §60.107a(c)(6), the paragraph 

that establishes the O2 operating limit, has a problem, in that it does not establish an averaging 

time for the oxygen level. An instantaneous oxygen level is certainly not an appropriate 

parameter for demonstrating compliance with a 365-day average NOx limit or a daily mass limit. 

Thus, we request this proposed language be clarified to make clear that the averaging periods for 

the O2 operating limit are the same as for the NOx limit (i.e., 365-day rolling average or daily 

average). 

Temporary Flare Situations

Expanding on Comment 4.5.2 of our original comments on the proposed amendments to Subpart 

Ja1, there are two significant categories of temporary flare use – To control SS&M emissions 

during infrequent and/or remote outage occurrences and as backup for other control devices. It is 

worth noting that even if temporary flares are exempted from Subpart Ja requirements, they may

be subject to State requirements and §60.18 and/or §63.11 requirements.

Control of SS&M Emissions

Most temporary flares are used in remote locations in a refinery (e.g., in a tank farm) to handle 

temporary needs associated with startups and shutdowns (e.g., tank gas freeing on shutdown and 

air or inert gas freeing on startup) which happen infrequently. For instance, typical tank outage 

frequency is once in every ten years. It is much more cost effective in these situations to use a 

temporary flare than to route the gases to a central flare, because the investment in compression, 

piping and liquid knockout facilities cannot be justified for the relatively small amounts of gas 

generated infrequently and for short durations. Another example of such a situation would be 

gas-freeing a long pipeline, where one end of the pipeline is outside the refinery and one end is at 

the refinery fenceline.

Occasionally, a temporary flare might also be used to control an emission resulting from a 

malfunction until a permanent fix or control can be put into place. For instance, a low pressure 

equipment leak might need to be flared temporarily until the leak could be fixed or compression 

facilities could be installed to safely route the stream to an existing flare.

 

1

EPA-HQ-OAR-2007-0011-0311.1
API/NPRA/WSPA Comments on Three Subpart Ja Issues July 21, 2009

Page 3

Backup for Other Control Devices

In limited cases (where adequate installed spare flare capacity is not present), a temporary flare 

must be used during flare or other control device maintenance in order to maintain compliance. 

If the temporary flare is being used to replace a flare system or combustion device that is not yet 

subject to Subpart Ja, installing the temporary flare should not be considered a modification 

because, at the conclusion of the maintenance project, no permanent physical change will have 

been made to the affected source. Similarly, the temporary flare should not be subject to Subpart 

Ja because use of the temporary flare does not constitute construction of an affected source. 

Subjecting such temporary flare installations to all of the Subpart Ja requirements adds a 

significant disincentive to assuring flares and control devices are maintained. 

Flare H2S Mass Limit Alternate

We proposed earlier that 300 lb/day of SO2 emissions (based on monitoring the H2S in the fuel 

gas) be established as an alternate to the 162 ppm H2S limit for flares where H2S removal is cost 

ineffective. We now believe that previous analyses show that a 500 lb/day of SO2 alternate limit 

is the appropriate alternate where a 162 ppm H2S limit is not cost effective.

The Agency has accepted that there are such situations for a limited number of flares in the 

Refinery Consent Decrees and, in fact, agreed to a 500 lb/day SO2 limit as the allowable in these 

cases. In these situations the H2S is typically derived from a collection of various streams whose 

inherent H2S contents are above 162 ppm, but generally not excessively so. In these cases, the 

costs for collecting, compressing and treating the streams greatly outweighs the small amount of 

SO2 emissions that might be prevented. The Agency recognized this situation in the Consent 

Decrees and in good faith agreed to this alternative limit for a limited subset of flares.

EPA has asked if there is some unique parameter associated with this subset of flares that could 

be used as a means of identifying flares for which the 162 ppm H2S limit would be expected to 

be cost ineffective. In response to EPA’s request, we have tried to identify a specific and 

common parameter that could be used to limit the applicability of a mass-based alternate. 

Unfortunately, we were unable to identify a common parameter. The cost to reduce flare gas 

H2S to less than 162 ppm and the resulting reduction in SO2 emissions turns out to require a 

totally flare-specific evaluation. The cost-effectiveness is highly dependent on the amount of 

piping required to collect the various streams, the extent to which the volume of flow varies (i.e. 

the need to design for the recovery of maximum flow rates), and the degree to which additional 

amine treating facilities is required. The potential SO2 reduction is a direct function of the H2S 

concentrations and flow rates of the streams normally reaching the flare and thus is also specific 

to each individual flare.

Since EPA has already agreed to a 500 lb/day SO2 limit (based on monitoring the H2S in the flare 

gas) for certain flares under the Consent Decrees, it is clear that, for at least those flares, a 500 

lb/day SO2 limit and not 162 ppm H2S flare gas limit is the appropriate emission limitation for 

incorporation into Subpart Ja. Since CAA 111(a)(1) requires the Agency to take into account the 
API/NPRA/WSPA Comments on Three Subpart Ja Issues July 21, 2009

Page 4

cost of achieving reductions, we believe Subpart Ja must recognize the Agency’s previous 

conclusions in this case and make available the 500 lb/day alternative limit for those particular 

flares In addition, we believe the Agency should make available to all sites, on a case-by-case 

basis, the ability to request approval to use this alternative limit where it can be demonstrated 

that compliance with the 162 ppm H2S standard is not cost-effective. We do not know if there is 

a basis upon which EPA could develop a process for approving such requests, but we offer our 

assistance in this regard. 

Our original proposal of a 300 lb/day limit would certainly be even less cost effective than a 500 

lb/day limit and would not reflect the accepted cost analyses for those particular flares 

established on a case-by-case basis under the Consent Decrees. Thus, we withdraw our 300 

lb/day proposal and urge the Agency to accept the conclusions it previously reached in the 

Consent Decrees that allow a 500 lb/day SO2 emissions alternate, based on the measured H2S in 

the flare gas, in place of the 162 H2S limitation for those flares identified as such in the Consent 

Decrees. In addition, we request that the Agency make available the ability to request the use of 

this alternative standard where meeting a 162 ppm H2S standard can be shown in the future to be 

cost ineffective.