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 comm ents 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 comme nts. 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.or g

(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/ h our 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 t he 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 heater s 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 inc reases. 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 s afe flame patterns and firebox heat transfer

. Because of this excess air, NOx concentrations adjusted to 0% O 2 increases as firing is reduced. We believe that, on a mass emitted basis, the increase in NOx concentration is offset by the reduced firing dow n 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% fi r ing point. W e believe sources s hould be allowed

to establish the O 2 operating limit at any firing rate below 50%

. Sources should also be allowed, at their discretion to test at additional points to establish an O 2 operating limit curve.

Company experts indicate that below approximat ely 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 theAPI/NPRA/WSPA Comments on Three Subpart Ja Issues July 21, 2009 Page 2

Subpart Ja rule. We therefore suggest that the O 2 operating limit not apply belo w 20% of design firing. We note that 20% of 40

- 100MMBTU/ h our is 8

- 20 MMBTU/

h our 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 O 2 operating limi t

, 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 O 2 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

Ja 1 , 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

wor th 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 t en 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 amo unts 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 temporar y 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 compres sion facilities could be installed to safely route the stream to an existing flare.

1 EPA

- HQ

- OAR

- 2007

- 0011

- 0311.1API/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 c ontrol 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

be cause, 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 constru ction of an affected source. Subjecting such temporary flare installation s to all of the Subpart Ja requirements adds a significant disincentive to assuring flares and control devices are maintained.

Flare H 2 S Mass Limit Alternate

We proposed earlier that 300 lb/day of SO 2 emissions (based on monitoring the H 2 S in the fuel gas) be established as an alternate to the 162 ppm H 2 S limit for flares where H 2 S removal is cost

ineffective. We now believe that previous analyses show that a 5 00 lb/day of SO 2 al ternate limit

is the appr opriate alternate where a 162 ppm H 2 S 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 SO 2 limi t as the allowable in these

cases. In t hese situations the H 2 S is typically derived from a collection of various streams whose

inherent H 2 S contents are above 162 ppm, but generally not excessively so. In these cases, the costs for collecting , compressin g and treating the streams greatly outweighs the small amount of

SO 2 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 H 2 S limit would be expected to

be cost ineffective. In response to EPA’s request

, we have tried to ide ntify 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

H 2 S to less than 162 ppm and the resulting reduction in SO 2 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 SO 2 reduction is a direct function of the H 2 S concentrations and flow rates of the streams normally reaching the flare and thu s is also specific

to each individual flare.

Since EPA has already agreed to a 500 lb/day SO 2 limit (based on monitoring the H 2 S in the flare gas) for certain flares under the C onsent D ecrees, it i s clear that, for at least those flares, a 500 lb/day SO 2 limit and not 162 ppm H 2 S flare gas limit is the appropriate emission limitation for incorporation into Subpart Ja

. Since CAA 111 (a)(1) requires the Agency to tak e into account theAPI/NPRA/WSPA Comments on Three Subpart Ja Issues July 21, 2009 Page 4

cost of achieving reduction s , we believe Subpart Ja must recognize the Ag ency’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 u se this alternative limit where it can be demonstrated that compliance with the 162 ppm H 2 S 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 C onsent D ecrees. 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 SO 2 emissions alternate, based on the measured H 2 S in the flare gas, in place of the 162 H 2 S 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 H 2 S standard can be shown in the future to be

cost ineffective.