Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW Washington, DC 20005

- 4070 USA Telephone: 202

- 682

- 8 319 Fax: 202

- 682

- 8031 Email: ToddM@api.org www.api.org

Ms. Penny Lassiter US EPA Office of Air Quality Planning and Standards Sector Policies and Programs Division (E143

– 01) Research Triangle Park, NC 27711 Lassiter.Penny@epamail.epa.gov

Dear Penny

,

We are generally aware from our previous discussions that the A gency is considering adding requirements for flares, delayed cok ing, and fenceline monitoring in the upcoming Refinery Sector Rule, along with amendments to many existing provisio ns of part 63 subparts CC and UUU and part 60 subpart Ja. We would like to offer our views

on some issues of particular concern to us to assure they are fully vetted during the comment period.

Flares
1) Part 63 subpart CC addresses refinery process operatio ns and associated tankfield and loading rack operations as well as certain marine loading and fuels loading facilities co

- located with refinery operations. The new Refining Sector Rule flare requirements should only apply to flares that receive gases from refinery process units, because flares associated with marine and fuels terminal operations are different than refinery flares

, and because of the many issues raised if flares at co

- located marine loading and terminal operations have different requirements than flares located at non

- co

- located facilities

.
2) Our analysis of available data suggests that a reasonable assurance of VOC and HAP destruction can be obtained by establishing a combustion zone net heating value (CZ

- NHV) of ~200 BTU /scf.Sector Rule Issues

Page 2 a) The response to Question 4 in Attachment A of the flare peer review 1 offers a functional fit to the available combustion efficiency flare data as a function of CZ

- NHV

. That fit indicates that 200 BTU/scf provides reasonable assurance of high combustion efficiency. Furthermore, based on the requirements EPA has set for unassisted flares, this conclusion is consistent with historical EPA conclusions that 200 BTU/scf is adequately supportive of good combustion.

b) Our understanding is that t he Refining Sector Rule will seek to close a gap in previous knowledge with re spect to the deleterious impacts of over

steaming on destruction efficiency

. An unassisted flare provides the limiting case for an assisted flare with zero assist gas. No new data has been presented that supports a change in the previous conclusions
rega rding the required heating value for unassisted flares. Thus, for assisted flares, the change in paradigm to consider the net heating value of the combustion zone rather than of the flare gas should be adequate to close the gap and a change in the BTU content that indicates good destruction efficiency is not supported

.
3) Hydrogen promotes flammability and its presence improves destruction efficiency for low

- BTU gases and that benefit should be recognized, as it has been in variou s Consent Decrees, by assigning hydrogen a heating value of 1212 BTU/scf. Shown below is a plot of combustion efficiency as a function of CZ

NHV , where data have been binned by hydrogen content in the combustion zone (as tabulated in the Master Flare Data base )

. This illustrates the point that hydrogen generally promotes high combustion efficiency at even lower CZ

- NHV s than would be observed for pure hydrocarbon flames. In this case, if hydrogen were assigned a heating value of 1212 BTU/scf, the higher hy drogen points would be shifted to the right, more in line with the no hydrogen data.

1 Memorandum from Carrie Richardson Fry and Jeff Coburn, RTI International , to Andrew Bouchard and Brenda Shine, EPA/OAQPS

, Peer Review of ‘Parameters for Properly Designed and Operated Flares”

, July 3, 2012 , Attachment A.Sector Rule Issues

Page 3

4) The costs and environmental impacts of new flare limits must be evaluated considering the compliance margins that will be needed to assure compliance. Because of flare gas variability and instrument and control , flares will need to operate at a CZ

- NHV higher than that limit to assure continuous compliance

. T his will increase natural gas use and combustion byproduct emissions above those that would be predicted bas ed on the limit itself.

5) Changing compliance limits as flare gas composition changes in order to achieve small, questionable destruction efficiency improvements requires additional, costly continuous monitoring and will result in wasteful, large natural gas addition excesses and unnecessary greenhouse gas and combustion byproduct emissions because of the long continuous analyzer response times relative the composition variability of waste gas. Any imposition of differing requirements (e.g., CZ

- NHV limits ) as a function of flare gas properties must be extremely well justified by robust, sound scientific data and must be demonstrated to have a significant impact on destruction efficiencies (i.e., an incremental change in destruction efficiency due to changi ng CZ

- NHV limits must be scientifically proven and that increment justified versus the additional costs, compliance risk and emissions that will result from having differing limits ).

6) Because of continuous composition monitor lag time and the potential for short
term flare gas composition and heating value variability

, significant averaging times (for example, an average over a few hours) are required to make continuous compliance with a set CZ

- NHV value feasible.

0% 20% 40% 60% 80% 100%

0 200 400 600 800 1000 Combustion Efficiency [%]

Combustion Zone Net Heating Value [btu/scf] 

### Combustion Efficiency as a Function of Hydrogen Content in the Combustion Zone

No Hydrogen

0 < H2 in DZ < 1%

1% < H2 in DZ < 2%

2% < H2 in CZ < 5%

5% < H2 in CZ < 10%

10% < H2 in CZ < 20%

H2 in CZ > 20%Sector Rule Issues

Page 4

7) Process data should be allowed as the ba sis for estimating the heating value and hydrogen and olefin contents of flare gas for flaring events. Since short duration flaring events are generally due to a known process occurrence, the composition of the flared material may often be reliably characterized by the known composition of the process stream released.

8) Any change in subcategorization of flares from that in §§60.18 and 63.11 (e.g., by type or flare gas olefin or hydrogen content) should be clearly justified and all of the i mpacts fully vetted. Considerable cost, confusion and compliance risk can occur due to changes in long established requirements that are fully embedded in existing rules, permits , consent decrees, and procedures.

9) Particular care is needed in applying req uirements derived primarily from the study of steam assisted flares to air assisted flares, since air assisted flares typically are smaller, have different design and operating characteristics, different control and monitoring capabilities

, and are often l ocated remotely

, where support facilities and equipment are not readily available. In fact, given the limited number of air assisted flares in refineries , it is questionable that there is adequate data or any need to address them in this rulemaking.

10) Sinc e unassisted flares are very un common in refineries, there is no need for addressing them in this rulemaking. I ncluding new, precedent setting unassisted (and to some extent air assisted) flare requirements in these rules will prejudice the rights of other , more directly impacted industries to participate in the proposal and promulgation of requirements that ultimately will be applied to their flares

.
11) Significant new requirement s have recently been imposed for refinery flares through part 60 subpart J a and through a number of Consent Decrees entered into between EPA and refiners. Similarly, refinery flares typically are

, and will continue to be subject to §§60.18 and 63.11 and their State equivalents because of the applicability of various other NESHA PS, NSPS rules, Consent Decrees and permits . It is therefore critical that EPA understand all of these currently applicable requirements and address any conflicts, overlaps and timing issues between those requirements and the new or revised requirements i mposed through the Refining Sector rulemaking. Even minor deviations from §60.18 and 63.11 requirements can require significant compliance time and impose tremendous burdens on refiners and permitting authorities.Sector Rule Issues

Page 5

Delayed Coking
1) Differences in size, cl ass and design of cokers warrants subcategorization. Capacity, type of coke produced, design differences, including blowdown system configuration

, and year of construction are potential bases for subcategorizing.

2) A ny 2 psig limit imposed on the depressurization of coke drums should be an average for the following reasons:

a) Available data are not adequate ly resolved to demonstrate a discernible difference in emissions over the range of several psig, so it is not clear that a coker venting at 3 psi g, for example, has higher emissions than a similar coker venting at 2 psig. Thus, there does not appear to be any emissions basis for not allowing occasional venting at somewhat higher pressures than 2 psig.

For example, one coker vent test sampled num erous vent pressures between 1 and 3.5 psig

. As shown in the following graph, v ent emission reductions as a function of reducing vent pressure in this range are not discernible. In fact, from this data set, which is unique in its numerous data points, an average overhead pressure limit of 2 psig is not justified as compared to a limit of 3.5 psig, let alone a 2 psig do

- not

- exceed limit.

0.0 10.0 20.0 30.0 40.0 50.0 60.0

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 NMNE VOC [tpy[

Overhead Vent Pressure [psig]Sector Rule Issues

Page 6 b) There is approximately 0.5 psig error expected in pressure transducer
measurements at such low pressure s and this introduces significant variability in a 2 psig measurement. This error band cannot be lessened by requiring use of narrow span instruments, since, for safety and operability reasons, the pressure instruments must be able to span the entire press ure range encountered during coke drum operation (typically 0

- >50 psig)

.

Fenceline monitoring
1) We are particularly concerned with the current draft fenceline monitoring method ology, in that 1) it could require an extremely large number of monitors, far more than are necessary to reasonably evaluate fenceline concentrations

, and 2) because results will be particularly sensitive to the methodologies for handling non

- detects and correcting for background and outside confounders.

2) Placement of monitors is another concern. The “fenceline” should be defined in such a way that it is clear it is the outer perimeter of all property owned by the refinery. Clarity is also needed relative to data handling as to how to handle mobile source s near the fenceline and non

- refining operations and operations owned by others that are wholly located within the refinery perimeter and which adjoin the refinery.

3) Establishment of the fenceline monitoring action level needs to account for the shortcomin gs in diffusion models, such as A ERMOD , particularly for sources near to the ground and the modeling source recepto r

. The action level should be set high enough to prevent false positives by account ing for the error bands associated with such modeling and with the inherent variability in field results.

4) After a period of time of sustained monitoring consistently below the action level, we believe that the fenceline monitoring program should terminate.

5) Provisions for streamlined procedures for allowing the use of alternative monitoring approaches are needed, since some refineries have or will have various forms of fenceline monitoring due to local, permit, or consent decree requirements.Sector Rule Issues

Page 7

Other

1) With the extension of emission limitations which were dev eloped for normal operations to startup, shutdown and malfunction events, special provisions will be required for those situations where the normal emission limitation cannot be
met and to clarify when an emission limitation or other requirement is no long er applicable (e.g., when gas

- freeing equipment at what point do control requirements no longer apply). We discussed such situations with you in April 2012 and have included as Attachment 1 the items pertinent to RMACT 1 and 2

, but we anticipate additional such situations will be identified once a specific proposal is issued.

2) If requirements that were proposed as part of the Uniform Standard s are included in the Refining Sector rule proposal (e.g., continuous monitoring of atmospheri c pressure relief devices (PRDs) ) , we would have the same concerns we expressed in our comments on the Uniform Standards proposal ( e.g., see Attachment 2 for our comments on the proposed Uniform Standards PRD monitoring requirements ).

3) Because the part 63 Refinery NESHAP rules apply broadly there is extensive overlap between these regulations

, other Federal rules

, and State rule and permit requirements. Currently, s ubparts CC and UUU address these overlaps extensively and thus provide clarity as to the app licability of overlapping requirements. Wherever changes to these rules or overlapping rules (such as part 60 subpart Ja) are made as part of the Refining Sector rulemaking there is the potential that the existing provisions for handling overlaps will no longer be adequate. All such conflicts or unclear situations need to be identified and addressed.

Again, we appreciate the dialogue that we continue to have with you on this and other refinery sector issues. Please c ontact me if you would like to disc uss any of these issues further.

Sincerely,

/s/

Matthew ToddApril 10, 2012 Page 1 Attachment 1



### RMACT 1 and 2 Startup and Shutdown and Special Operating Scenarios

The following is a preliminary tabulation of startup and shutdown and other separate operating scenarios where the normal RMACT 1 and 2 requirements cannot be met. Inability to comply with normal requirements associated with other regulations, preventive maintenance, and with malfunctions is not included in this tabulation.

RMACT 1

Process Vents
Requirement: Control Group 1 vents at all times.

Situation: During shutdown of equipment, process vents generally can continue to be controlled until the control is no longer effective. For most types of controls a point is reached where the vent no longer has adequate pressure to reach the control. For combust ion controls, a point can be reached where the inert content of the process vent is so high that sending it to combustion can be unsafe and/or upset the operation of the combustion device. For other types of controls, control efficiency can fall below req uired levels at very low vent stream flows.

Recommendation: As has been done in the Polymer and Resins 1 NESHAP for flares (see §63.485(w)), provide an exception from the control requirements for situations, during shutdown periods, where the
process ven t has inadequate pressure to reach the control device or is no longer a process vent (i.e., contains <50 PPM HAP). Expand this exception to include all types of control devices, when that emission limit cannot be achieved due to the process vent flow, pre ssure, or composition.

RMACT 2 Fluid Catalytic Cracking (FCC) Each FCCU features its own unique configuration and operating envelope that impacts emissions. Partial burn and full burn refer to the combustion mode of the regenerator of an FCCU. A partial burn unit operates with limited oxygen in the regenerator and has CO levels of 3% to 6% out of the regenerator. Partial burn units complete the combustion of the flue gas (including CO) downstream in a CO boiler. Because of these high levels of CO when the CO boiler is not available (versus the 500 ppmAPI Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 2

normal operation limit), averaging is not an effective way of addressing startup and shutdown emissions for partial burn CO emission limits. A full burn unit operates with excess oxygen to ensure complete combustion and has CO levels of about 10

- 100 ppm out of the regenerator during normal operation. Full burn units are generally not equipped with CO boilers.

1. FCC Regenerator Vent

- General Startup and Shutdown
Requirement: 500 ppm CO (hourly avg.)

Situation: High temperature is required to fully combust CO into CO 2 . In normal operation, the required heat is derived from the combustion of coke. From a cold startup, FCC’s use a natural gas fired heater to heat the regenerator to about 600

– 800 °F . We discuss the fired heater operation separately in the next item. These auxiliary burners and regenerator internals are not designed to heat the regenerator to temperatures required to start the FCC unit cracking reactions (>1000F). Torch oil 2 is nee ded to heat the regenerator beyond the capacity of the auxiliary burner. Thus, during a typical start

- up, and during some shutdowns and standby operations of an FCC unit, there is a period of time when torch oil is added to the regenerator to facilitate t he unit heat

- up to operating temperature. Upon the addition of feed to the unit, catalytic coke will start to burn in the regenerator along with the torch oil. Feed ramp up is fairly quick, during which time the torch oil is backed out during normal star tups, but can be longer if refractory repairs were made because of the need to raise temperatures slowly so as not to damage the new refractory. The period of torch oil addition (i.e. the period when the bed temperature is relatively low) results in incre ased CO during the start

up period.

Recommendations: 1. CO limits should not apply when torch oil is being combusted during startup or shutdown.

2 “Torch oil” is a term which is usually applied to gas oil that is burned in FCC regenerators, to supply necessary heat requirements during startup, shutdown, or feed

- outage conditions, when coke is not being produced in the reactor. Typically, it is injected through dedicated nozzles which discharge into the dense catalyst bed of a regenerator.API Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 3

2. If there must be a limit, follow the Consent Decree (CD) model and make the 500 ppm limit a short

- ter m limit that excludes periods of SU/SD and add a long

- term limit that includes periods of SU/SD (i.e., 365

- day average).
Requirement: Opacity (6 minute rolling avg.), PM emissions, 500 ppm CO (hourly avg.)

Situation: Prior to introducing feed into an FCC unit hot air is used initially to heat up the regenerator. The hot air is typically supplied from a natural gas fired air

- preheater that is only used for start

- up. If refractory repairs were made a refractory dry

- o ut is required and the regenerator temperature must be raised slowly (e.g., at a rate of 50

– 100 ° F/hr) to prevent water from damaging the refractory. Emissions from the regenerator vent during this time are from the air heater.

Recommendation: Clarify that the FCC regenerator emission limits are only applicable when hydrocarbon is being fed to the unit and that combustion exhaust used to heat an FCC during start

- up are subject to combustion source limits, not FCC regenerator limits.

2. FCC Regenerator Vent

- General Startup and Shutdown

– Full Burn Units
Requirement: 500 ppm CO (hourly avg.)

Situation: For full burn FCC units, there is a relatively short period of time during startup when the unit operates in partial burn mode resulting in an additional period of higher CO. This partial burn period can result from heat imbalances during this transition state or may be required for safety because operation at regenerator temperatures high enough for complete combustion while establishing ca talyst circulation or introducing feed can result in exceeding metallurgical temperature limits.
The unit is inherently unstable as feed is being put into the unit. It is a balancing act that requires operators to manually balance heat consumed to vapor ize the feed and sustain the cracking reaction as additional feed is being put on the unit with the heat being brought into the reactor from the regenerator via catalyst circulation, which is a function of regenerator operating conditions. This is an extr emely complex operation with numerous variables that operations must manage until the unit can be lined out.API Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 4

Recommendation: For full burn FCC’s CO limits should not apply until feed and full burn operation is stable and normal heat balance can be main tained.

3. FCC Regenerator Vent

- General Startup and Shutdown

– Partial Burn Units
Requirement: 500 ppm CO (hourly avg.)

Situation: For a partial burn unit, the required CO boilers add an additional step to unit start

- up. Additional time is required from the point that the regenerator enters partial burn until the time the flue gas is all routed through the CO boiler(s). The CO boiler(s) must be brought up separately from the regenerator to protect them from swings of the regenerator flue gas quality during the start

- up process, which can result in temperature excursions, damage to CO boiler internals and/or trip of the CO boiler(s). A CO boiler trip must be avoided because it could ultimately lead to a refinery shutdown due to a drastic decrease in steam production (a very large proportion of the refinery’s steam supply is typically provided by the CO Boilers), resulting in excess emissions at other units, significant flaring, production loss, and potentially equipment damage. Since the regenerator f lue gas initially bypasses the CO boiler, the CO is not further combusted. Once the regenerator is stable, the flue gas is added to the CO boilers and CO emissions drop to normal levels. Prior to lining up the regenerator flue gas to the CO boiler, the u nit is operating in a mode with higher CO emissions for a short period of time.

Recommendation: For partial burn FCC units, CO limits should not apply until the CO boiler(s) operation is stable and all regenerator gas is routed to the boiler(s).

4. FC C Regenerator Vent

- Hot Standby
Requirement: Opacity (6 minute rolling avg.), PM emissions, 500 ppm CO (hourly avg.)

Situation: There are operational situations where it is necessary to remove feed from an FCC unit to accommodate unit repairs, respond to an upstream or downstream malfunction or maintenance outage, and/ or to delay full startup due to downstream issues. Although processing isAPI Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 5

stopped, the FCCU maintains temperature by burning torch oil, which can result in higher CO and NOx emissions duri ng this period of operation. PM/Opacity will also be higher for FCC units with ESP PM controls since, as discussed below, it is unsafe to operate the ESP during torch oil firing. A standby mode of up to 7

– 10 days presents fewer safety risks and total environmental emissions than a complete FCCU shutdown and minimizes production losses. The ability to operate in hot standby mode allows the FCC to stay ready for startup when otherwise it would have to go through a full cold shutdown with catalyst removal, which adds days to the dow ntime, operationally intense startup/shutdown activities, potential unit damage due to thermal cycles, and potential for increased emissions. This is an extremely important operation that is routinely employed, and the impact should not be underestimated. In addition to minimizing overall emissions, this operation minimizes the time to get products (e.g. gasoline) to the public. Further, it doesn’t introduce reliability issues inherent with cold shutdowns that could result in even further delays in retur ning to production. One refinery reports that during a recent hurricane the refinery experienced numerous unit shutdowns associated with lost utilities and hurricane related damage. The refinery was able to recover the FCC unit and establish stable operat ions in hot standby ready for startup. However, downstream units were not prepared for startup. Consequently, the FCCs idled in this condition until downstream facilities were brought back on line. Being able to stay in hot standby meant the FCC did not have to go through a cold shutdown while refinery resources were dedicated to recovering other units. Other refineries report similar situations, riding out hurricanes with the FCC unit in hot standby, thereby allowing the refineries to get gasoline back to the public faster than if the FCC units had to go through a cold shutdown and restart.

Recommendation: Exclude the “hot standby” operating mode from the regenerator emission limits.

5. FCC Regenerator Vent

- CO Boiler Shutdown
Requirement: 500 ppm CO (hourly avg.)

Situation: For FCC units with a single CO boiler, it is sometimes necessary to operate partial burn FCC units when the CO boiler is down for inspection or, in particular, for repair. During such times the CO limitAPI Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 6

cannot be met . We discuss the reasons why the FCC unit needs to continue to operate during these times in the previous item.

Recommendation: For partial burn FCC units do not apply the CO emission limit when the CO boiler is out of service for inspection or maintenan ce.

6 . FCC Regenerator Vent

- Electrostatic Precipitator (ESP) Control
Requirement: Opacity (6 minute rolling avg.), PM emissions, 500 ppm CO (hourly avg.)

Situation: On FCC units equipped with an ESP, the ESP must be powered off or bypassed, during an FCCU and/or CO Boiler startup and shutdown. In fact, many FCC units have critical safety instrumentation which automatically shuts down the ESP in case of unusual operations or equipment malfunctions, such as loss of circulation differential pressure, ai r blower trip, high ESP inlet temperatures, and other similar types of issues. During startup and shutdown operations of the FCC unit, the regenerator flue gas may become combustible from either direct torch oil firing, from high levels of CO and/or with the unintentional introduction of hydrocarbon into the regenerator. For this reason and, at a minimum, the ESP should be OFF/Bypassed for the steps of torch oil firing and feed introduction/removal, as well as transitory operations (e.g. CO Boiler malfun ction or shutdown, other FCCU process upsets or equipment failures). There is a similar point in the SD process where fresh feed rates are unstable and/or torch oil is fired where similar precautions must be taken. Because the ESP must be operating in ord er to meet PM and opacity limits, but for safety reasons, the ESP should be powered off or bypassed during FCC startup and shutdown operations, imposing a PM or opacity limit during such periods forces owners and operators to choose between compliance and safety to employees and equipment. In all cases, safety concerns are paramount and following proper safety procedures should not result in a potential non

- compliance of an emission limit.

Recommendation: PM and opacity limits cannot apply during periods when regenerator offgas cannot be safely routed to the ESP.API Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 7 7 . FCC Regenerator Vent

- Cyclone Controls
Requirement: Opacity (6 minute rolling avg.), PM emissions

Situation: During startup and shutdown of FCC units, gas flows are not always adequate f or cyclones to work properly and thus opacity and PM limits can be exceeded. Startup operations require passing through transient operations that are not ideal for cyclone performance. This will impact opacity. This is especially apparent during catalys t addition. There is also a fair amount of unit variability as air and catalyst levels are varied during startup operations.

Recommendation: PM and opacity limits cannot apply during periods when regenerator offgas flow is below cyclone minimum design fl ow.

Sulfur Plants
1. Catalyst sulfidation
Requirement: 250ppm SO 2 (12

- hr avg.) at the incinerator outlet or 300 ppm TRS (12

- hr avg.) and 10 ppm H 2 S (12

- hr avg.)

Situation: During startup, the Claus System (and “SCOT” unit, if present) must be warmed up and the tail gas catalyst must be activated (i.e., sulfided) before full H 2 S removal can occur. Sulfiding must be done at low temperatures to avoid catalyst damage. During these low temperature periods there can be incremental slip of reduced sulfur from the unit or to the tail gas incinerator, resulting in high SO 2 or TRS until the reactors are activated and on temperature.

Recommendations: 1. Follow the NSR CD model of having a short

- term limit that excludes SU/SD emissions and a long

- term limit that includes SU/SD (e.g., 365

- day average).

2. Establish an allowable mass of SO 2 from each SRU for SD

– justified by the unit’s design.API Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 8 2. Sulfur flashing
Requirement: 250ppm SO 2 (12

- hr avg.) at the incinerator outlet or 300 ppm TRS (12

- hr avg.) and 10 ppm H 2 S (12

- hr avg.)

Situation: In some SRP configurations, during startup, the gas from the Claus System must bypass the tail gas unit and vent directly to the inciner ator. The sulfur in the line can solidify and cause a high temperature flash which can send excess sulfur to the incinerator and cause the SO2 limit to be exceeded.

Recommendations: 1. Follow the NSR CD model of having a short

- term limit that excludes S U/SD emissions and a long

- term limit that includes SU/SD (e.g., 365

- day average).

2. Establish an allowable mass of SO 2 from each SRU for SD

– justified by the unit’s design.

3. Hot sweep
Requirement: 250ppm SO 2 (12

- hr avg.) at the incinerator outlet o r 300 ppm TRS (12

- hr avg.) and 10 ppm H 2 S (12

- hr avg.)

Situation: During some shutdowns, high temperature natural gas and air or oxygen must be added to the Claus System during hot sweep to ensure sulfur stays in liquid form. Measurement of O 2 in the convert outlets becomes unreliable under these conditions and can result in is too much O 2 . If there is too much O 2 , there is a potential for burn off of sulfur in the catalyst bed creating excess sulfur to the incinerator.
Similarly, if the shu tdown is not for total catalyst replacement, the unit must be operated as close to stoichiometric as possible because excess air will result in the combustion of sulfur within the reactors that could lead to an Incinerator excursion or excessive temperatur es within the catalyst bed that could result in catalyst and/or equipment damage. Due to system and control variability this operation can result in running air deficient. An air deficient operation can result in soot formation (i.e. incomplete combustio n) that will result in reactor plugging thereby reducing unit capacity or in the reduction (i.e. deactivation) of the Tail Gas Catalyst which can substantially impact sulfur recovery efficiency.API Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 9

Recommendations: 1. Follow the NSR CD model of having a short

- term limit that excludes SU/SD emissions and a long

- term limit that includes SU/SD (e.g., 365

- day average).

2. Establish an allowable mass of SO 2 from each SRU for SD

– justified by the unit’s design.

4. Hot strip prior to shutdown
Requirement: 250ppm SO 2 (12

- hr avg.) at the incinerator outlet or 300 ppm TRS (12

- hr avg.) and 10 ppm H 2 S (12

- hr avg.)

Situation: During shutdown, there is holdup of sulfur in catalyst, vessels, piping

, and ductwork that needs to be removed for inspection and maintena nce. A portion of this sulfur can be transferred to sulfur pits, but additional sulfur can only be removed by combusting (“burning”) it following shutdown of tail gas units (because excess oxygen can damage the tail gas units). The amount of sulfur held up depends in part on the configuration of the Claus unit, with some units having lesser ability to route sulfur to pits. These incidents have been reported to EPA in Acid Gas/Tail Gas incident reports required under refiner’s NSR consent decrees.

Recom mendations: 1. Follow the NSR CD model of having a short

- term limit that excludes SU/SD emissions and a long

- term limit that includes SU/SD (e.g., 365

- day average).

2. Establish an allowable mass of SO 2 from each SRU for SD

– justified by the unit’s des ign.

5. Single train refinery shutdown
Requirement: 250ppm SO 2 (12

- hr avg.) at the incinerator outlet or 300 ppm TRS (12

- hr avg.) and 10 ppm H 2 S (12

- hr avg.)

Situation: Single train refineries are required to have total refinery shutdowns on occasion. For these facilities, all acid gas sources are taken out of service, and, in turn, all Claus trains have to be taken out of service (i.e., no acid gas feed available). I n these instances, the Claus unit(s) are shutdown in conjunction with the shutdown of acid gas producing units. During the Claus unit shutdown, the tail gas unit remains in service prior to introducing oxygen to the Claus reactor. By design, theAPI Comments on RMACT 1 and 2 Startup and Shutdown a nd Special Operating Scenarios

April 10, 2012 Page 10

tail gas unit generates acid gas, which is normally routed back to the front of the Claus reactor. When the first of multiple Claus units is shutdown, this tail gas (acid gas) can be routed to another operating Claus unit. Eventually, however, the final Claus un it is being shutdown, with no Claus unit to receive the acid gas and the gas must be purged to the atmosphere. These incidents have been reported to EPA in NSR CD Acid Gas/Tail Gas incident reports.

Recommendations: 1. Follow the NSR CD model of having a short

- term limit that excludes SU/SD emissions and a long

- term limit that includes SU/SD (e.g., 365

- day average).

2. Establish an allowable mass of SO 2 from each SRU for SD

– justified by the unit’s design.

6. H ot nitrogen sweep
Requirement: 250ppm SO 2 (12

- hr avg.) at the incinerator outlet or 300 ppm TRS (12

- hr avg.) and 10 ppm H 2 S (12

- hr avg.)

Situation: When the sulfur plant is not operating (no feed), a hot nitrogen sweep is maintained. The CEMS can regist er > 250 ppm during this situation, due to residual sulfur in the unit or interference from the hot nitrogen.

Recommendation: Be clear that SO 2 limit only applies when the SRP is operating with acid gas feed to the unit and not when it is in hot standby

mo de.Attachment 2



### Comments on Proposed Uniform Standards Pressure Relief Device

Monitoring Requirements

(From API and AFPM Detailed Comments on the Content of EPA’s “National Uniform Emission Standards for Storage Vessel and Transfer Operations, Equipment Leaks, and Closed Vent Systems and Control Dev ices; and Revisions to the National Uniform Emission Standards General Provisions” March 26, 2012 at 77 Fed. Reg. 17898, September 24, 2012, Attachment 2.)



### 4.10 Comments on “What are the standards and compliance requirements for pressure relief devices ( PRDs)?” (§65.424)

The proposed PRD requirements go beyond the requirements in any of the existing petroleum industry rules that the US are intended to simplify and streamline. The provision that any reading of 500 ppm or greater above background would be considered a deviation is one critical new provision that does not allow a reasonable possibility of operating in compliance. The requirement for pressure release management systems with continuous monitoring equipment goes well beyond any existing regul ation or CAA authority and would involve significant costs with no reduction in emissions. Relief events are not equipment leaks and not part of an LDAR program. Only PRD leakage that occurs after/outside a relief event should be subject to LDAR regulati on. Relief event management, calculation, and reporting should be handled via other release reporting programs such EPCRA or CERCLA. In addition, there appears to be overlapping coverage between §65.424 of subpart J and §65.340 of subpart I. These and o ther issues are discussed in depth in the following subsections.



### 4.10.1 Comments on the proposed requirement to operate PRDs with less than 500 ppm above background. (§65.424(a))

The language in §65.424(a) requires operation at less than 500 ppm above ba ckground with no exceptions, presumably including during an emergency release to the atmosphere. Existing rules have always included the phrase “Except during pressure releases” to indicate that emissions during emergency releases to protect equipment are not a deviation of LDAR regulations 3 . Encouraging facility operators to try to avoid a PRD release to atmosphere could

3 Such releases may be deviations under other applicable CAA req uirements, but they are not equipment leak deviations, since they are not leaks.result in significant damage to the piping and process vessels that PRDs are intended to protect,

with subsequent emissions much greate r than the release itself, significant costs caused by

over

- pressure damage, and loss of life. The omission of this phrase in §65.424(a) is a significant extension of current PRD compliance requirements that should not be added without full
consideration and justification of the safety risk imposed and cost effectiveness of the new provision. This is especially true since the proposed provisions are in §65.424(a) and thus apply to all PRDs, not in sections 65.424(c) and/or (d) that only apply if PRDs are specifically required by the referencing subpart to have no releases to atmosphere.

In addition, the provision that any reading of 500 ppm or greater above background would be considered a deviation does not allow a reasonable possibility of operating in compliance even outside emergency relief situations. While leakage past the seat after a release is the most common driver for PRD leaks, it is certainly not the only one. PRD monitoring is required by many state rules to cover all potential leak interfa ces, including the bonnet flange, the spring chamber vent, and/or the pilot control unit vent. The bonnet flange is no better seal than any other gasketed flange, and readings over 500 ppm above background would be expected to occur occasionally. The fac ility has no way to predict or prevent a leak at the bonnet flange, the spring chamber vent, or the pilot control unit vent. If a monitoring event indicates a reading of 500 ppm or greater above background, it is immediately a deviation under subpart J. Thus, there is no technically feasible way to comply with this new provision, and therefore, it is not a fair and reasonable requirement, does not comply with the achievability requirements of the CAA and opens operators up to potential civil and criminal liabilities through no fault of their

own.

Another issue in §65.424 is inconsistent use of “500 ppm above background” vs. “500 ppm”. Section 65.424(a) states the operating requirements for a PRD as “Operate each PRD in gas or vapor service with an instru ment reading of less than 500 ppm above background.” This language is not used consistently, however, with §§65,424(b)(1) and 65.424(b)(2) stating “... verify that the PRD is operating with an instrument reading of less than 500 ppm. An instrument reading of 500 ppm or greater is a deviation.” The operational limit must be clear as a 500 ppm above background reading and that language must be used consistently throughout the standards to avoid confusion.

Recommendation: 1. Remove the provisions that any l eak over 500 ppm above background is a deviation, and allow at least the current 5 day period to return the PRD to less than 500 ppm above background.2. Add the phrase “Except during pressure releases” to the language in §65.424(a) or change

the langua ge to read “if specifically required by a referencing subpart to have no releases to the atmosphere.”

3. State the operational limit, where imposed, consistently as “500 ppm above background”.



### 4.10.2 Comments on not allowing PRD releases and on PRD moni toring system requirements.
API/AFPM has the following strenuous objections to the potential requirements banning atmospheric relief and/or for requiring a pressure release management system for PRDs in
refineries:

A. EPA lacks the statutory authority to impose these new requirements;

B. Current systems already identify pressure relief events, and EPA’s proposal could have unintended negative consequences; and

C. EPA has grossly underestimated the cost to implement PRD monitoring systems for
refineries.

A EPA f ails to identify adequate statutory authority for its PRD proposal. EPA cannot impose such requirements without explicit authority as EPA is “a creature of statute,” that has “only those authorities conferred upon it by Congress.” Michigan v. EPA, 268

F. 3d 1075, 1081 (D.C. Cir. 2001). Here, EPA at most references general authority under CAA §112, for these expansive requirements. However, upon closer examination, nothing in Section 112 provides the authority required to justify proposing these PRD requi rements, especially since this is a new requirement (not an adjustment to an existing requirement); is not the product of a review of best performing sources to set performance standards; is not part of residual risk driven standards; and, in fact, cannot claim any emission reductions.

B. This proposal suggests a lack of understanding of the role of PRDs in refineries and the complexity of the safety issues that are addressed through good engineering practices applied in designing systems that are specific to the processes in which they are employed. PRDs play an essential role in ensuring the safety of a refinery. PRDs are designed and installed to prevent equipment from exceeding maximum allowable working pressures during conditions such as power failur es, fires, process operating upsets, and other situations outside of the operators’ control. PRDs preventcatastrophic breaches of process equipment that would result in equipment damage,

perhaps loss of life and far higher emissions than those resulting from a release from a PRD. PRDs minimize the loss of process materials to the surrounding environment and the operation of a PRD is typically the last line of defense in cases where multiple layers of protection have been executed but have failed to keep an overpressure situation
under control.

The systems that are protected by pressure relief systems vary widely across the petroleum industry due to the demands of the processes which they protect and the hazards posed by the chemicals used in those proces ses. For example, systems can range in operating pressures from slightly above atmospheric to thousands of pounds per square inch. Some systems must manage the potential for explosive decomposition. Some must manage sticky materials such as heavy gas oi ls and asphalt. Some must manage multiphase systems of gas/liquid or even gas/liquid/solid streams. The choice of relief protection is typically made through a systematic evaluation of the risk posed by the system specific situations. A variety of tools such as Hazard and Operability Study (HAZOP), Fault Tree Analysis, or Layers of Protection Analysis (LOPA) are available for identifying the risks. The precise design of the overall system includes not simply the PRD but the overall processes, procedures , monitoring systems and controls which are used to minimize the potential for a release.

Although the Agency may view its proposal as an incentive to preventing releases, it may result in unintended consequences. By establishing that any release is a vi olation of the CAA, EPA is essentially asking plant operators to choose either to allow the release to occur resulting in a violation, or prevent the release thus creating the potential for a catastrophic breach that will endanger both the lives of the pla nt employees and the community neighbors. Any standard prohibiting releases to the atmosphere from PRDs must include appropriate routes to demonstrate the legal status of the vent without prejudging the owner/operator by a presumption of non

compliance.

The EPA also appears to fail to consider that due to the importance of PRDs to process safety these devices are part of the site preventive maintenance program and are routinely tested and inspected in accordance with national and state code requirements. Such testing and maintenance reduce the potential of PRD malfunctions and premature opening.C. EPA has estimated that PRD monitoring system costs could range from $11,000 capital

cost and $1,600 annual costs for a small chemical facility to $130,000 c apital cost and $19,000 annualized cost for a complex refinery. API/AFPM believes that EPA has significantly under estimated actual implementation costs. Cost estimates based on an API/AFPM survey of members and a high quality estimate from one company’s cost estimators indicate total annualized costs for an average refinery of more than $1.5 million for wireless monitors and nearly $7 million for wired monitors. The details and basis of these estimates can be found in Attachment 3 Subpart J Item 5.

One facility with wireless PRD monitoring in place since 2007, reported only 3 relief events detected since installation, and no relief events over the two most recent years. With 30 PRD using the wireless monitoring systems for a period of more than 4 years

, the 3 relief events detected represents one relief per 40 PRDs per year. In another report, South Coast refineries reported a total of 770 atmospheric PRDs (565 in gas/vapor service and 205 in liquid service) to SCAQMD. A total of 42 releases were

repo rted over a 4 year period from these 770 PRDs, or an average of 10.5 releases per year from all atmospheric PRDs. Therefore, just over 1 percent of the PRDs released each year. If one conservatively assumed that every one of these releases occurred on a PRD in gas/vapor service the result would be that each gas/vapor PRD releases, on average, around once every 54 years. This does not seem to support EPA’s statements regarding a “large number of releases.” Of the data reported from these South Coast
refi neries, 62 percent of the releases resulted in emissions of less than 500 lbs. No information was provided related to the duration of each release.

Most PRD relief events are easily detected by sensory means (sound, sight, or smell). In many cases, exi sting instrumentation systems used for operational purposes also provide the information needed to determine when pressure relief events occur and releases are already reported (e.g., Title V deviation reporting, STEERS (TX), immediate reporting to NRC und er EPCRA and CERCLA, various State and local release reporting rules, annual emissions inventory, etc.) The proposed additional monitoring provides no benefits and no emission reductions despite great cost.

Recommendation: 1. Remove the provisions dis allowing atmospheric relief and requiring pressure relief management systems.2. As we discuss in Comment 1.1.6, in order to avoid just the kind of confusion and

misapplication these PRD provisions are engendering, EPA should remove requirements such as these that are not widely applicable in existing potentially referencing subpart s.

3. If these provisions are not removed, EPA should not require them if refinery referencing subparts are modified to use the US.



### 4.10.3 Comments on the requirement to replace a rupture disk within 5 days (§65.424(b)(2))

The proposed standards for PR Ds that consist of or contain a rupture disk require that the rupture disk be replaced within 5 days. This could be a problem for continuous process units. Most continuous processes avoid use of rupture disks for this reason, but if referencing subparts require the pressure release management systems or control by a CVS and control device per §65.424(c) and (d), then more continuous processes may use rupture disks under pressure relief valves. These rupture disk/pressure relief valve systems are usually installed in tandem, so that a spare can be lined up to protect the vessel when the other set needs replacement/resetting. There are, however, situations where a spare set is not available on continuously used equipment. Requiring the rupture disk to be replaced within 5 days could force a process unit shutdown, with potentially a million dollars per day, or more, of lost production.

Recommendation: Where a rupture disk/pressure relief valve combination relieves, allow compliance by either replacement of the rupture disk or monitoring to verify operation at less than 500 ppm above background within 5 days.



### 4.10.4 Proposed §65.424 needs to be clarified relative to the use of the term “in regulated material service.”

As we discuss in general in Comment 4.2 .2, the term “in regulated material service” is widely misused to extend requirements well beyond their applicability in a referencing subpart. The use of this term in §65.424 is a prime example, that must be corrected. This section implements a ban on a tmospheric PRDs if a referencing subpart contains such a ban. However, rather than applying the implementing language to just those PRDs identified by the referencing subpart, this section appears to ban atmospheric PRDs for any PRD “in regulated
material service”, which could include liquid in addition to gas/vapor PRDs and PRDs where the particular acute toxic that is the reason for the ban is not present.Recommendation: The language throughout this section must be clarified to limit the impacted

P RDs to just those that a particular referencing subpart identifies as not being allowed to vent to the atmosphere. Revise all references in §65.424 of “Pressure Relief Device in regulated material service” to “Pressure Relief Device which the referencing subpart identifies as not being allowed to relieve to the atmosphere.”



### 4.10.6 Proposed §65.424(b)(1) and (2) deviation definitions must be clarified.

Proposed §65.424(b)(1) and (2) specify monitoring after a pressure release or rupture disc
blow. In both cases, monitoring is required to confirm that emissions have returned to below 500 ppm above background within 5 calendar days after the release. However, both paragraphs specify any measurement above 500 ppm is a deviation, even if that measurement

occu rs within the 5 day window. Since the requirement is to achieve <500 ppm before 5 days has elapsed, there is no legal basis for having a deviation during that 5 day period. While the 500 ppm criterion is often met on the initial check, that is not always the case. Sometimes additional effort is required to completely reseat the valve. As long as that effort is completed within the 5 day period and confirmed within the 5 days, any measurement indicating 500 ppm is being exceeded should not be a deviation

.

Recommendation: Revise the deviation definitions in §65.424(b)(1) and (2) to indicate it is not a deviation if >500 ppm above background is measured within 5 calendar days after the release.



### 4.10.7 Proposed §65.424(c) serves no purpose and should be deleted.

Proposed §65.424(c) imposes requirements for pressure release management, if a referencing subpart specifies that releases to the atmosphere from PRDs in a particular regulated material service are not allowed. In such a case, the PRD must be rou ted to a control device rather than the atmosphere, so §65.424(d) applies and §65.424(c) can never be applicable. EPA’s proposal does not consider that the flow monitor will not provide enough information to estimate the amount of regulated material, if a ny, which could be attributed to the release. A flow indicator at a PRD provides no information as to whether a particular regulated material or any regulated material requiring control is being released.

Furthermore, as discussed in Comment 1.2.4, pro posed §65.424(c)(2) requires emission estimates that are not needed for establishing emission limitations or demonstrating compliance and are duplicative of requirements imposed under laws and regulation that are applicable to release estimating and report ing. Under the mandates of Executive Orders 12866 and 13563 and the PRA, such general information gathering requirements have no place in the

US.Furthermore, as discussed in Comment 1.1.6, it is likely very few referencing rules would ban

atmospheric r eleases during emergencies. Thus, requirements associated with PRDs that are not allowed to be released to the atmosphere should not be included in the US, but rather should remain in the referencing subpart.

Recommendation: 1. Delete §65.424(c).

2. If this paragraph is not deleted, delete paragraph (c)(2) and limit (c) and (c)(1) to only those specific PRDs that a referencing subpart specifies are not allowed to release to the atmosphere
and that are not routed to a control device. Allow for the use of existing monitoring capabilities. We recommend the following revised (c) and (c)(1) language.

(c) Pressure release management. If your referencing subpart specifies that releases to the atmosphere from certain PRD in regulated material service are

no t allowed, you must comply with the requirements specified in paragraph s (c)(1) and (2) of this section for each PRD specified in the referencing subpart that is not routed to a control device or to a process all PRD in regulated material service, and any r elease from a PRD in regulated material service is a deviation

.

(1) You must equip each PRD in regulated material service with a device(s) that is capable of identifying and recording the time and duration of each pressure release and of notifying operators that a pressure release has occurred. If this instrument is capable of measuring the concentration of leaks through the PRD, then you may use this instrument to meet the requirements of paragraph (b) of
this section. (i) Install, calibrate, mainta in, and operate, a continuous monitoring system on the PRD or in the associated process system(s) sufficient to
determine:

(A) the time and duration of each pressure relief event; or

(B) the status of the pressure relief valve as either:

(1) open or clo sed to the atmosphere; or

(2) the percentage the valve is open to the atmosphere; and(ii) Develop, implement, and follow a written monitoring plan to satisfy the

requirements of this subpart. The monitoring plan must include:

(A) specifications for all monitors used to satisfy the requirements of this subsection;

(B) an inspection plan for all PRD and associated monitors to insure proper operation considering the manufacturer's recommendations; and

(C) a list identifying all PRD subject to the requirements of this
subsection.

(iii) Upon written request by the Administrator, the monitoring plan required under paragraph (ii) of this subpart must be submitted within 30 days for review.



### 4.10.8 Proposed §65.424(d) needs to be clarified.

Proposed §65.424(d) specifies that you are not required to comply with §65.424(a), (b) or (c), if all releases and potential leaks from your PRD are routed through a CVS to a control device. This is a sensible and reasonable provision and we fully support the conc ept. However, as drafted the requirement for the exception can never be met and thus this critical paragraph has
no effect.

As we discussed in Comment 4.10.1, in addition to leakage or releases through the valve seat, PRD leakage to the atmosphere can oc cur from bonnet flanges and other PRD interfaces (e.g., the flange connecting the PRD to the inlet piping). Leakage from body interfaces cannot be routed to control devices, as can the PRD outlet itself. Thus, the requirement to route all leakage to a co ntrol device is technically infeasible and cannot be met for any PRD.

Recommendation: Revise §65.424(d) as follows:

PRD routed to a control device. If all releases and potential valve seat leak s age from your PRD are routed through a closed vent system to a control device, you are not required to comply with paragraphs (a), (b) or (c) (if applicable) of this
section. ...