Major Changes to Refinery Air Rules: The Final Refinery ...€¦ · Major Changes to Refinery Air...

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Major Changes to Refinery Air Rules: The Final Refinery Sector Rules ERM Webinar October 15, 2015


Agenda

Introductions Key Dates Fenceline Monitoring Cokers & Catalytic Reformers Flares SSM/Relief Valves FCCUs Tanks & LDAR Q&A

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Background/Key Dates

EPA was under a court order deadline to finalize Refinery MACT 1 and 2 by September 30, 2015

Signed by Administrator on September 29, 2015 Expected to be published in mid- to late-October Effective date is 60 days after publication in

Federal Register

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Background/Compliance Dates

Compliance dates are generally 3 years after the effective date, except: Electronic reporting, SSM, and the submerged filling requirement for

marine vessel loading require compliance immediately upon the effective date of the final rule;

Compliance with the FCCU standards is due within 18 months of the effective date & one time HCN test is required 20 months after effective date;

Compliance with the fenceline monitoring provisions is required 2 years after the effective date of the rule (changed from 3 years in proposal); and

Compliance with the storage tanks standards is determined according to the timeline in the Generic MACT (changes requiring an outage of the tank can be made at the next planned outage or within 10 years).

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Fenceline Monitoring Hedrick Strickland and Andy Woerner, P.E.


Regulation and Methods – The Basic Elements

Establish monitoring locations around the perimeter that encompass all “known” VOC sources

Identify meteorological station – install if necessary

Deploy/replace tubes every 14 days

Perform Method 325B analysis

Perform calculations and compare results to action level

Perform root cause analysis and initiate corrective actions

Develop and submit corrective action plan

Report concentrations for public availability

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Compliance Date, 2 years!


Establish a monitoring perimeter that encompasses all “known” VOC sources

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Fenceline Monitoring: Sample Locations

May be located inside the property boundary as long as it is at least 50 meters from a known emission source

Does NOT need to incorporate internal roads or other right-of-ways that bisect a facility


Establish monitoring locations Radial Method – 12 to 24 points minimum Linear Method – Every 2000 ft with a minimum of 12 For non-contiguous areas, place samplers a minimum of

500’ apart with a minimum of 3 monitors per area.

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Fenceline Monitoring: Sample Locations

Extra samplers when known emission sources are between 2 monitors and within 50 meters of the monitoring perimeter


Fenceline Monitoring: Sampling Period

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Monitoring period of 14 ±1 days

Burden reduction schedule for individual monitors Every biweekly sample ≤ 0.9 μg/m3 for 2 years sample monthly Every monthly sample ≤ 0.9 μg/m3 for 2 years sample quarterly Every quarterly sample ≤ 0.9 μg/m3 for 2 years sample

semiannually Every semiannual sample ≤ 0.9 μg/m3 for an 2 years sample

annually

If any result is above 0.9 μg/m3 at any stage in the reduction

schedule – step back up


Fenceline Monitoring: Met. Data Identify nearby or install on-site meteorological station US Weather Service met. station within 25 miles of refinery

(if not using a site-specific monitoring plan) On-site meteorological station must meet specified siting and

calibration criteria Collect and record hourly average

meteorological data, including wind speed, wind direction, temperature, and barometric pressure

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Fenceline Monitoring: Data Perform calculations and compare results to action level Period specific ΔC = highest result - lowest result Rolling average ΔC = average period specific ΔCs for the last 12 months Compare rolling average ΔC to action level, 9 μg/m3 (~2.8 ppb)

Initiate corrective actions if rolling average > 9 μg/m3 Complete root cause analysis and initial corrective actions within 45 days Submit a corrective action plan to the Administrator if actions to bring

benzene levels below 9 μg/m3 fail or can not be completed within 45 days

Report concentrations for public availability EPA’s Compliance and Emissions Data Reporting Interface (CEDRI)

Alternatives (optional) Site-specific monitoring plan Alternative test method

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Site Specific Monitoring Plan

Refineries can develop a site-specific monitoring plan to account for suspected benzene sources outside the refinery boundaries or onsite sources not subject to refinery MACT

A site specific monitoring plan must: Identify exempt or offsite sources and the fenceline monitoring

locations they impact. Describe additional monitoring locations and techniques. Describe planned data reduction and calculations. Use an on-site meteorological station.

Long process required for EPA approval

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Alternative Test Method Alternative test method may be used in lieu of some or all of the passive samplers

Must be validated according to Method 301 or contain performance based procedures and indicators to ensure self-validation.

Requirements: Method detection limit must be ≤ 0.9 µg/m3. Spatial coverage must be equal to or better than 325A Non-integrating alternative test methods must provide a minimum of one

cycle of operation for each successive 15-minute period.

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Moving Forward

2015 2016 2017 2018

Pro

mul

gatio

n E

ffect

ive

Dat

e

Public Disclosure of Monitoring Data

Compare Data to Action Level and Perform RCA and CA as Required

Assess and Respond to Baseline Conditions Inform Selection of Sample Locations Determine “Where You Stand” (Baseline Concentrations) Identify Root Cause(s) of Any Issues Address Refinery Causes (Equipment/Work Practice/Process Modifications) Develop /Test Site-Specific Monitoring Plans to Account for Offsite Sources

Develop Compliance Strategies Screen/Select Laboratory or Develop On-Site Laboratory Capabilities Assess/Install Dedicated Meteorological Station Develop Procedures and Training

Sampling Protocol Data Management Root Cause Analysis and Corrective Action Process

Plan for Public Outreach

Com

plia

nce

Dat

e M

onito

ring

Beg

ins

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Delayed Coker Units (DCUs) & Catalytic Reforming Units (CRUs) Andy Woerner, P.E.

http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&docid=9KamkD1ElOT6lM&tbnid=GEGagcwwRboKSM:&ved=0CAUQjRw&url=http://en.wikipedia.org/wiki/Catalytic_reforming&ei=NqOoU5TyIsWzsATFhIGADA&bvm=bv.69411363,d.cWc&psig=AFQjCNE9-2emUn1mmnPFcNeNLkpFRswJ8A&ust=1403647152668678


Delayed Coking Unit – Drum Depressuring

16 http://www.epa.gov/apti/video/10182011Webinar/101811webinar.pdf

Prior to venting to atm, draining or deheading: Existing: < 2 psig OR An average vessel

temperature of 220F Determined on a rolling

60-event basis

New: < 2 psig OR An average vessel

temperature of 218F Each decoking event

http://www.epa.gov/apti/video/10182011Webinar/101811webinar.pdf

http://www.epa.gov/apti/video/10182011Webinar/101811webinar.pdf


Delayed Coking Unit – Monitoring Monitor Drum Pressure:

1. In representative location 2. 2 psig +/- 0.5 psig 3. Annual verification of sensor 4. Visually inspected every 3 months 5. Review output daily to verify pressure taps are not plugged

Monitor Drum Temperature: CPMS for vessel temperature (Table 13)

Compliance Check – obtain 5 minute rolling average while venting to blowdown system & use last complete 5 minutes rolling average to determine compliance

Special Scenarios Water overflow must be hard-piped when temperature > 220F For double quench, CPMS to measure temperature; temperature < 210F

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Catalytic Reforming Units

In Refinery MACT 2, emission limitations do not apply to process vents during depressuring and purging operations when the reactor vent pressure is 5 psig or less.

EPA intended exemption for CRUs with passive purging only.

EPA is clarifying that this exemption does not apply to CRUs with active purging techniques (such as continuous nitrogen purge or vacuum pump on the CRU reactor at low pressures).

EPA contends that units utilizing active purging techniques have the ability to direct the purge gas to a control system.

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Flares Pat Sorensen


Flares Brings the concept of continuous flare efficiency to NESHAP Flare used as control device – CC and UUU (FCCU and CRU organic HAP) CC - Storage vessels, marine vessel loading, gasoline loading racks,

wastewater controls, miscellaneous process vents, in-situ sampling streams, equipment leaks

No other requirements for emission points routed to a fuel gas system if flare meets work practice standards

Several revised/new definitions

Work practice standards – non-emergency flaring

Work practice standards – emergency flaring

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Flares

Work practice standards – non-emergency flaring When flaring a “regulated material”, for greater than 15-minutes of flare flow, at flow rate less than smokeless capacity of flare. Flame presence – deviation if not present more than 1 min. in each

15-min. block Visible emissions – no VE except for 5 min. in any 2 consecutive

hours Flare tip velocity – <60 fps or <400 fps and Vmax using formula Net heating value (combustion zone) at or above 270 Btu/cf, 15-min

block Dilution operating limit for air assisted flares CPMS Monitoring Plan

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Flares

Work practice standards – emergency flaring Develop a flare management plan to minimize flaring during periods of startup, shutdown, or emergency releases FMP content – in addition to std. descriptive items, vent catalog,

diagram, planned SU/SD procedures Minimization assessment - Modification of SU/SD procedures to reduce

the quantity of process gas discharged to the flare, implement prevention measures listed for PRD for each PRV that can discharge to the flare, install FGR or, if fuel gas long, Co-gen/CHPP

Smokeless capacity of the flare – a single value Maximum vent gas flow rate (hydraulic load capacity) PRD catalog – maintained on-site, not submitted with plan

- detailed description of each PRV – type, diameter, set pressure, prevention measure

Due 3 years and 60 days after date of publication

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Flares Helpful adjustments from proposed to final Flare flow monitoring instrument accuracy also for Ja FMPs

Different flow monitoring techniques can be used for different streams

Grab sampling alternative for composition analysis Net heating value of 1,212 Btu/scf for hydrogen Can use 920 Btu/scf for purchased pipeline quality natural gas Olefin/hydrogen concentration not an issue in NHV calculation “Dedicated” flare can do a single, 14-day analysis period Composition analysis on up to 15 distinct compounds, reasonably

expected, n-pentane = C5+, surrogate cal. gas C1-C5 normal hydrocarbons instead of C7

Can use video camera for VE (record 1 frame every 15 seconds)

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Startup, Shutdown, and Malfunction (SSM) Kristine Pelt, P.E. & Pat Sorensen


SSM In the proposed rule, EPA eliminated startup, shutdown and

malfunction (SSM) exemptions and required that refineries comply at all times.

Work practice standards for pressure relief devices (PRDs) and emergency flaring that includes proactive requirements and root cause analysis and corrective action.

The final rule has specific emission limits for FCCUs and SRU during both startup and shutdown.

No affirmative defense provisions are provided.

SSM Plan and associated requirements are eliminated.

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SSM Relief Valves New work practice requirement - at least three redundant

prevention measures

New work practice requirement - Root Cause and Corrective Action

PRDs routed to a closed-vent system and control device are exempt from all requirements

Other exemptions – heavy liquids, liquids to controlled drains, PTE < 72 lb/day VOC, set pressure < 2.5 psig

Final requirements (same as proposed) Monitor for discharges to the atmosphere Time and duration of the release Notification system to alert operators of release Quantify organic HAP emissions

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SSM Flares

Develop a flare management plan to minimize flaring during periods of startup, shutdown, or emergency releases.

Conduct a root cause analysis and a corrective action analysis when the vent gas flow rate exceeds the smokeless capacity of the flare and:

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Visible emissions are present from the flare for more than 5 minutes during any 2 consecutive hours during the release event; and/or

The 15-minute block average flare tip velocity exceeds the maximum flare tip velocity

http://www.google.com/url?sa=i&rct=j&q=&esrc=s&source=images&cd=&cad=rja&uact=8&ved=0CAMQjRxqFQoTCKKApfuEu8gCFdBNiAodWkUB0w&url=http://www.nola.com/traffic/index.ssf/2012/12/shell_chemical_equipment_failu.html&psig=AFQjCNGqLVOEcxkOhnddzX1pAAmFS-SMXg&ust=1444674212549987


Violation of PRD and Flare Work Practice Standard

Root cause is operator error or poor maintenance.

Limits on the number of times that a PRD may release to the atmosphere during a 3-year period.

Limits on the number of flaring events during startup, shutdown, or emergencies during a 3-year period.

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PRDs and Flares - Timing

A root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a flare flow event.

All corrective action(s) must be implemented within 45 days of the event for which the root cause and corrective action analyses were required or as soon thereafter as practicable (or implementation schedule).

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Startup and Shutdown Alternatives FCCUs CO: 1-percent minimum oxygen limit as an alternative to the 500 ppmv hourly CO limit. All FCCUs at startup and shutdown (proposed for only partial burn at startup).

FCCUs PM: Minimum cyclone face velocity at or above 20 feet per second (proposed an

alternative opacity limit) Using a wet scrubber - maintain only the liquid to gas ratio operating limit (the

pressure drop operating limit does not apply) All FCCUs at startup and shutdown

SRUs Sulfur: A thermal oxidizer or incinerator operated at a minimum hourly average

temperature of 1,200 degrees Fahrenheit and a minimum hourly average outlet oxygen (O2) concentration of 2 volume percent (dry basis).

Startup and shutdown (proposed only shutdown)

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FCCU Kristine Pelt, P.E.


FCCUs

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Regulation Limit Compliance Additional Details

NSPS J 1 g PM/kg coke burnoff

20% opacity demonstration, 3-hour average site-specific opacity limit using COMS; control device limit using CPMS; bag leak detection

Additional incremental PM allowance for fuel burned in an incinerator or waste heat boiler

NSPS Ja 1 g PM/kg coke burnoff

Bag leak detectors for fabric filters; 3-hour rolling average using CPMS for ESPs and wet scrubbers; 3-hour rolling average using COMs - site-specific opacity limit

No incremental allowance; 0.5 g PM/kg coke burnoff for new FCCUs

NSPS Ja 0.040 gr/dscf PM CEMS 0.020 gr/dscf for new FCCUs

MACT II

1 mg Ni/kg coke burnoff or 13 g/hr Ni

Bag leak detectors for fabric filters; 3-hour rolling average using CPMS for control devices; 3-hour rolling average site-specific Ni limit using COMS

Monthly Ni concentration limits for catalyst also required


FCCUs

For FCCUs equipped with ESPs for PM control, monitoring and recording the total power and the secondary current to the entire system is required (for consistency with NSPS Ja).

The current Refinery MACT II requires monitoring voltage and secondary current or monitoring only the total power to the ESP.

For FCCUs equipped with wet scrubbers for PM control, daily checks of the air or water pressure to the spray nozzles is required.

A PM performance test once every 5 years for all FCCUs is required as well as a one-time test for HCN.

Annual tests if complying with NSPS J option and the PM emissions are within 80-percent of the PM limit during any periodic performance test.

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Tanks & LDAR Deever Bradley, P.E.


Storage Tanks

Group 1 Criteria

Additional Requirements for Group 1 Storage Vessels Guidepole controls for floating roof tanks Control of additional fittings/gaskets Visual inspections for newly controlled fittings

Tank roof landing/degassing requirements and domes on EFRTs found not cost-effective

EPA noted that fenceline monitoring will ensure effective management of fugitive emissions from landings, overfills, and leaking vents

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Former Criteria Final Criteria

≥46,760 gal ≥1.5 psia 20K-40K gal ≥1.9 psia

≥40K gal ≥0.75 psia


LDAR

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Definition of “seal” in OEL not finalized.

EPA noted that fenceline monitoring will detect any significant leaks from a cap, blind flange, plug or second valve that does not properly seal an OEL.

Following a release, PRD must be monitored 5 calendar days after returning to service to verify less than 500 ppm.

Optical gas imaging as an alternative to EPA Method 21 will be proposed in Appendix K to 40 CFR part 60 at a later date

“Leakless” valves as well as 500-ppm valve and 2,000-ppm pump leak definitions were deemed not cost-effective


Next Steps Prepare detailed summaries of the final requirements tailored to

your refinery operations.

Craft a detailed compliance plan for your refinery.

Conduct a pilot fenceline monitoring trial.

Develop a flare management plan for flaring events during SSM.

Conduct source testing for Particulate Matter and HCN.

Develop and implement efficient solutions for electronic data reporting using EPA’s Electronic Reporting Tool (ERT).

Address community concerns that may be triggered by the health risk information presented in the rule and the EPA’s press releases, as well as planning for the public availability of fenceline data.

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Today’s Speakers

Andy Woerner, P.E. Philadelphia, PA 484.913.0455 [email protected]

Pat Sorensen Indianapolis, IN 317.706.2007 [email protected]

Hedrick Strickland Raleigh, NC 919.233.4501 [email protected]

Kristine Pelt Raleigh, NC 919.855.2296 [email protected]

Deever Bradley, P.E. Houston, TX 832.786.5774 [email protected]

Toby Hanna, P.E. Ewing, NJ 609.403.7518 [email protected]

mailto:[email protected]






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