Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

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 Agency is considering

adding requirements for flares, delayed coking, and fenceline monitoring in the 

upcoming Refinery Sector Rule, along with amendments to many existing provisions 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 operations 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 review1

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 the Refining Sector Rule will seek to close a gap 

in previous knowledge with respect to the deleterious impacts of oversteaming 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 

regarding 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 

various Consent Decrees, by assigning hydrogen a heating value of 1212 

BTU/scf. Shown below is a plot of combustion efficiency as a function of CZNHV, where data have been binned by hydrogen content in the combustion zone 

(as tabulated in the Master Flare Database). This illustrates the point that 

hydrogen generally promotes high combustion efficiency at even lower CZ-NHVs 

than would be observed for pure hydrocarbon flames. In this case, if hydrogen 

were assigned a heating value of 1212 BTU/scf, the higher hydrogen 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. 

This will increase natural gas use and combustion byproduct emissions above 

those that would be predicted based 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 changing 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 basis 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 impacts 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 requirements 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 located 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)Since unassisted flares are very uncommon in refineries, there is no need for 

addressing them in this rulemaking. Including 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 requirements have recently been imposed for refinery flares 

through part 60 subpart Ja 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 NESHAPS, 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 imposed 

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, class 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) Any 2 psig limit imposed on the depressurization of coke drums should be an 

average for the following reasons:

a) Available data are not adequately 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 psig, 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 numerous vent pressures 

between 1 and 3.5 psig. As shown in the following graph, vent 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 pressures 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 pressure range encountered during coke drum operation (typically 0

- >50 psig).

Fenceline monitoring

1) We are particularly concerned with the current draft fenceline monitoring 

methodology, 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 sources 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 

shortcomings in diffusion models, such as AERMOD, particularly for sources 

near to the ground and the modeling source receptor. The action level should be 

set high enough to prevent false positives by accounting 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 developed 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 longer 

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 Standards are included 

in the Refining Sector rule proposal (e.g., continuous monitoring of atmospheric 

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, subparts CC and UUU address these overlaps 

extensively and thus provide clarity as to the applicability 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 contact me if you would like to discuss any of these 

issues further.

Sincerely,

/s/

Matthew Todd
April 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 combustion 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 required 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 vent 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, pressure, 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 ppm 
API Comments on RMACT 1 and 2 Startup and Shutdown and 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 CO2. 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 oil2is needed 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 the 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 startups, 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 increased CO during the startup 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 and 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-term 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-out 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 catalyst 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 vaporize 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 extremely 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 and 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 

maintained.

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 flue 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 unit 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. FCC 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 is 
API Comments on RMACT 1 and 2 Startup and Shutdown and 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 during 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 downtime, 

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 returning 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 operations 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 limit 
API Comments on RMACT 1 and 2 Startup and Shutdown and 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 

maintenance.

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, 

air 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 

malfunction 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 order 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 and 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 for 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 catalyst 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 flow.

Sulfur Plants

1. Catalyst sulfidation

Requirement: 250ppm SO2 (12-hr avg.) at the incinerator outlet or 300 

ppm TRS (12-hr avg.) and 10 ppm H2S (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 H2S 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 SO2 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 SO2 from each SRU for SD – justified 

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

April 10, 2012 Page 8

2. Sulfur flashing

Requirement: 250ppm SO2 (12-hr avg.) at the incinerator outlet or 300 

ppm TRS (12-hr avg.) and 10 ppm H2S (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 

incinerator. 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 SU/SD emissions and a long-term limit that includes 

SU/SD (e.g., 365-day average).

2. Establish an allowable mass of SO2 from each SRU for SD – justified 

by the unit’s design.

3. Hot sweep

Requirement: 250ppm SO2 (12-hr avg.) at the incinerator outlet or 300 

ppm TRS (12-hr avg.) and 10 ppm H2S (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 O2 in the convert outlets 

becomes unreliable under these conditions and can result in is too much 

O2. If there is too much O2, there is a potential for burn off of sulfur in the 

catalyst bed creating excess sulfur to the incinerator. 

Similarly, if the shutdown 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 temperatures 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 

combustion) 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 and 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 SO2 from each SRU for SD – justified 

by the unit’s design.

4. Hot strip prior to shutdown

Requirement: 250ppm SO2 (12-hr avg.) at the incinerator outlet or 300 

ppm TRS (12-hr avg.) and 10 ppm H2S (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 

maintenance. 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. 

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 SO2 from each SRU for SD – justified 

by the unit’s design.

5. Single train refinery shutdown

Requirement: 250ppm SO2 (12-hr avg.) at the incinerator outlet or 300 

ppm TRS (12-hr avg.) and 10 ppm H2S (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). In 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, the 
API Comments on RMACT 1 and 2 Startup and Shutdown and 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 unit 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 SO2 from each SRU for SD – justified 

by the unit’s design.

6. Hot nitrogen sweep

Requirement: 250ppm SO2 (12-hr avg.) at the incinerator outlet or 300 

ppm TRS (12-hr avg.) and 10 ppm H2S (12-hr avg.)

Situation: When the sulfur plant is not operating (no feed), a hot nitrogen 

sweep is maintained. The CEMS can register > 250 ppm during this 

situation, due to residual sulfur in the unit or interference from the hot 

nitrogen.

Recommendation: Be clear that SO2 limit only applies when the SRP is 

operating with acid gas feed to the unit and not when it is in hot standby 

mode.
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 Devices; 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 regulation 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 

regulation. 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 other 

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 background 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 

regulations3. Encouraging facility operators to try to avoid a PRD release to atmosphere could 

 

3

Such releases may be deviations under other applicable CAA requirements, 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 greater 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 interfaces, 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 facility 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 instrument 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 leak 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 language 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 monitoring 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 fails 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 

requirements, 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 failures, fires, process operating 

upsets, and other situations outside of the operators’ control. PRDs prevent 
catastrophic 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 processes. 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 oils 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 violation 

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 plant 

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 noncompliance.

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 capital 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 

reported 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 

refineries, 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, existing 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 under 

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 disallowing 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 subparts. 

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 PRDs 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 atmospheric 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 

PRDs 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 

occurs 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 routed 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 any, 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, proposed §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 reporting. 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 releases 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 

not allowed, you must comply with the requirements specified in paragraphs

(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 processall PRD in regulated material 

service, and any release 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, maintain, 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 closed 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 concept. 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 occur 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 control 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 leaksage

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. ...