Refinery Sector Rule Focused Compliance... · 2016. 2. 1. · MACT 1– Cokers •Must monitor the...

Presented by: Becca Bradley

Stephen Walls, P.E.Jeremy Sell, P.E.

Refinery Sector Rule Focused Compliance

Presenters


Stephen Walls, P.E.

Senior Engineer

Jeremy Sell, P.E.

Business Unit Manager

Becca Crumpler, E.I.T,

Associate Engineer

Class Introductions

Who are You?

Workshop Agenda


8:30-9:15 – RSR Overview (MACT CC & UUU Requirements)

10:00-10:15 – Break #1

8:30-9:15 – RSR Overview

1:30-2:30 – Fenceline Monitoring9:15-10:00 – Storage Tanks

10:15-11:15 – Vents (MPVs & PRDs)

11:15-12:00 – Activity #1

2:30-2:45 – Break #2

2:45-4:15 – Flares

4:15-4:45 – Activity #2

RSR Overview

Final rule effective February 1, 2016

Affected rules

MACT 1 (CC)

MACT 2 (UUU)

NSPS Subparts J/Ja

General duty clause documentation replaces SSM exemption/plan


Introduction / Regulatory Background

• Result of EPA’s Residual Risk and Technology Review • Included 2011 ICR data

• Objectives• Control toxic air emissions from refineries and provide

emissions data to public

• Virtually eliminate smoking flare emissions and pressure relief device (PRD) releases

• Require emission monitoring at key sources and around refinery fenceline


• Lower capacity and vapor pressure thresholds • More Group 1 tanks

• MACT Subpart G (HON) no longer applicable after 4/29/2016• MACT Subpart WW – floating roof tanks • MACT Subpart SS – fixed roof tanks

• Flares used as control device Subpart change• subject to §63.670, not §63.987

MACT 1 – Storage Vessels


• Definitions revised to remove references to SSM exemption• Maintenance vent

category added with separate requirements

• Definition expanded to include additional vent streams• Hot wells and high

point bleeds

MACT 1 – Miscellaneous Process Vents (MPVs)


MACT 1 – Maintenance Vents

• Subcategory of MPVs• Remove liquids and depressure to control device, fuel

gas system, or back to process then• Determine LEL or vessel pressure using process instruments or

portable device and verify below threshold or

• Determine VOC mass to verify below 72 lbs/day


• Includes PRVs, rupture disks, and similar equipment

• Major Exemptions• PTE < 72 lbs/day VOC• Thermal expansion valves• Set pressure

• Control requirements• Monitoring system – identify release,

track time, and notify operators

• Apply three redundant prevention measures

• Root cause analysis / corrective action analysis (RCA/CAA) process – emission calculations (similar to NSPS Subpart Ja and CD requirements)

MACT 1 – Pressure Relief Devices


http://www.mycheme.com/types‐of‐pressure‐relief‐devices/

http://www.cmctechnologies.com.au/item277.htm

MACT 1 - Delayed Coking Units (Cokers)

• New requirements• Pressure/temperature limits prior to venting to

atmosphere, draining, or deheading

• Overflow water storage tank – hard piped and submerged fill line if open top or fixed roof


MACT Existing vs. New

• Process Unit Construction Date?• After July 14, 1994?

• Process Unit HAP emissions • > 10 TPY of any HAP or >25 TPY of total HAPS?

• Yes to Both = must follow “new” source requirements


MACT 1– Cokers

• Must monitor the top (or overhead line) of each Coke Drum for temperature OR pressure prior to venting to the atmosphere, draining, or deheading


Existing Source

• Avg. vessel pressure ≤ 2 psig• 60 Event Rolling Avg.

OR

• Avg. vessel temperature ≤ 220˚F• 60 Event Rolling Avg.

New Source

• Vessel pressure ≤ 2.0 psig• Each decoking event

OR

• Vessel temperature ≤ 218˚F• Each decoking event

MACT 1 – Cokers• Quality Assurance Programs for CPMS – Coker• Verify correct accuracy

• Pressure – must be able to measure 2.0 psig within ±0.5 psig• Temperature - ± 1% of sensors range or 2.8˚C (whichever greater)

• Annual (or mfg. recommended) calibrations• And within 24 hours of exceeding maximum rated range

• Quarterly Visual Inspections• Unless redundant monitors

• Additional Requirement for Coker Pressure Monitor• Output pressure system must be reviewed daily to ensure fluctuation

and no plugging (If plugged, must be fixed before next operating period)


MACT 1 – Cokers

• Decoking Event Emissions• Compliance with the limits is based off a 5-minute rolling average

while drum is vented to the closed blowdown system

• The last complete 5-minute rolling avg. just prior to venting, draining, or deheading is used

• Readings after venting, draining, or deheading cannot be used to determine compliance

• Recommend that DCS coded to display the 5-minute rolling average for operations


MACT 1 – Cokers

• Water Overflow Cokers• No choice – must follow temperature limits• Overflow water must be close piped to storage tank with a

submerged fill pipe

• Double Quench Cokers• Designed cooling process of partially draining drum and re-filling

to adequately cool

• Add temperature CPMS on drum drain line• Temperature of drain water must be less than 210˚F• Include in CPMS QA programs


Cokers - Summary1/30/2019

• New requirements – some similar monitoring done informally for process control

• Determine if DCU is new or exiting source• Identify compliance strategy – temperature vs. pressure• Determine if double quench scenario exists requiring

temperature monitor on drain line• Install monitoring devices• Code in DCS to display 5-minute rolling average (not

instantaneous)• Water overflow tank – confirm hard piped and submerged fill

line


• Used to control MACT Subpart CC and MACT Subpart UUU sources -now comply with §63.670 instead of general requirements in §63.11 and other referenced subparts

• Focus on destruction efficiency instead of inlet vent gas control

• One set of operational standards apply• Across different flare types• Temporary and intermittent use

flare

• Operational standards apply when regulated material is vented to flare

MACT 1 - Flares


MACT 2 - Fluid Catalytic Cracking Units (FCCUs)

• Opacity requirement reduced – 30 percent to 20 percent

• Stack testing frequency increased

• Added compliance monitoring options for ESPs

• SSM exemption no longer applies – limits apply during S/U, S/D, hot standby

MACT 2 – FCCUs

• Different compliance options depending on control device• Electro-static Precipitators (ESPs)• Wet Gas Scrubbers (WGS)• Filters

• Added Continuous Parameter Monitoring Systems (CPMS) for Startup/Shutdown/Hot-standby (SU/SD/HS) situations

• Additional testing requirements


FCCU Major ChangesUnit Affected Parameter Old Requirement New Requirement

FCCUs Opacity 30% limit 20% limit

Performance testing (PM, Nickel, HCN)

Initial only for PM, Nickel

Every 5 years for PM, Nickel, and one-time HCN

Control monitoring options

No changes Added additional monitoring options for ESPs

Startup/Shutdownand Hot Standby

SSM exception Adds Hot Standby operation, and comply with J/Ja requirements at all times, or• 1% O2 limit (organics)• Primary cyclone velocity limit

(metals)


MACT 2 – FCCUs

• Performance Test Changes• Performance tests for particulate matter (PM) and Nickel (Ni) are required for

each FCCU every five years, with the first tests due by August 1, 2017.• If PM is > 80 percent of the PM limit, then switch to annual testing.

• One time hydrogen cyanide (HCN) test at the same time as the first PM performance test. • Exception if tested between March 31, 2011 and February 1, 2016; request agency

approval by March 30, 2016.

• Conduct PM performance tests during “maximum representative operating capacity.” Per EPA, this includes routine periods with higher PM emissions, such as soot blowing.

• HAP Standards• Current limit of 500 ppm carbon monoxide (CO) hourly average remains, and

per EPA demonstrates complete combustion and maximizes reduction of HCN.


• Control Device Monitoring Requirement/Option Changes• Electrostatic precipitator

• CPMS - Daily average (before August 2017) changed to 3-hour rolling average (after August 2017) of total power and secondary current operating limits determined during performance test

• COMS - Hourly average (before August 2017) changed to 3-hour rolling average (after August 2017) opacity

MACT 2 – FCCUs


MACT 2 – FCCUs

• Control Device Monitoring Requirement/Option Changes• Wet gas scrubber (WGS) with jet ejector or atomizing spray

nozzles

• In lieu of pressure drop CPMS - Recorded daily check of air or water pressure to spray nozzles, and conduct a 12-hour repair timeframe for faulty equipment.

• Fabric filter• In lieu of continuous opacity monitoring system (COMS) - Bag leak

detectors may be used


MACT 2 – FCCUs

• Startup/Shutdown and Hot Standby Options:• Meet the applicable MACT UUU requirements.

• Includes approved AMP limits• Current CEMS Reporting practices?

• May not need to add these CPMS programs

• Organic HAP control – Meet minimum oxygen (O2) hourly average of ≥ one (1) percent in regenerator exhaust gas for all types of FCCUs, in lieu of the 500 ppm CO limit.


MACT 2 – FCCUs (con’t)

• Startup/Shutdown and Hot Standby Options:• Metal HAP control – Meet minimum inlet velocity limit to the

primary (first stage) internal cyclones of ≥ 20 feet/second for each hour of event for all types of FCCUs, in lieu of the new opacity limit.

• Determine inlet velocity by determining the volumetric flow rate of the regenerator in actual cubic feet per minute (ACFM) averaged per hour; determine the cumulative cross-sectional area (cubic feet) of all primary cyclones (based on drawings); and calculating inlet velocity.


MACT 2 – FCCUs WGS Compliance

• Organic HAP control – O2 ≥ 1% • Regenerator exhaust gas = WGS effluent if no additional streams

added between to skew O2 readings • WGS with O3 addition – could possibly be an issue

• Metal HAP control • Approved AMP

• Monitoring differential pressure or liquid-to-gas ratio• Compliance with Ja

• Monitor both differential pressure and liquid-to-gas ratio• Primary cyclone inlet velocity > 20 fps


FCCUs – Potential CPMS Issues

• Verify analyzer is in a representative location for the regenerator gas (O2sensor)

• Add any additional monitors, as necessary• Oxygen analyzer accuracy

• ± 1% of range or ± 0.5%• Typically use existing CEMS analyzer (accuracy shouldn’t be an issue)

• Primary cyclone flow analyzer accuracy• ± 5% of range or 10 cfm

• Set up QA procedures• Annual calibrations & following “any period of more than 24 hours when the sensor

reading exceeds maximum operating range”

• Quarterly inspection of components for integrity, electrical continuity, corrosion, etc. (unless redundant sensor in place)

• Verify signals and calculations in DCS


FCCU – Summary8/1/2017 or Extension

• Have capability to obtain Cyclone Velocity or WGS pressure differential as CPMS for SSM/HS

• O2 and Velocity parameters are typically within the standards• Determining PM compliance (especially for WGS)• AMP vs New UUU standards

• Evaluate if O2 CEMS analyzer is representative of FCCU exhaust gas

• Set up new QAQC requirements for CPMS or look into having redundant monitors


MACT 2 – Catalytic Reforming Units (CRUs)

• CRU – change naphthas into higher octane aromatics using metal catalyst and chemical reactions

• Regenerator – part of CRU• Single or multiple configuration• Process – depressurization=>purge=>coke burn-off=>catalyst

rejuvenation=>final purge

• Regeneration process types• Non-regenerative – 1950s and 1960s, very few remaining• Semi-regenerative (SRR) – most common, S/D for in situ regen• Cyclic – swing reactor for isolation and regen, fewer S/D• Continuous (CCR) – most modern, increasing use, regenerate portion of

catalyst and continuously add back (typical Platformer)


MACT 2 – CRUs Organics

• Emission limits (Table 15) apply during initial catalyst depressurization/purging operations

• Two options• (Option 1) Route to a flare – new requirements apply • (Option 2) Less stringent of 98 percent by weight reduction non-

methane TOC or 20 ppmv concentration corrected to 3 percent O2• Prior to revision, flares comply with §63.11(b) and VE not to

exceed 5-minutes in any 2-hour period, and flare pilot lit at all times• Replaced with §63.670 compliance – add operational standards for

flare tip velocity, combustion zone heat content (formerly vent gas inlet), dilution parameter


• Operating limits (Table 16)• Flare – replaced general

§63.11(b) and pilot light monitoring with §63.670

• Percent reduction with incineration control –temperature maintained above limit established in performance test (no change)

• Concentration limit/uncontrolled – operation, maintenance, and monitoring plan (OMM Plan)



• Emission limits (Table 15) and operating limits (Table 16) • Apply to process vents prior to

coke-burn off (initial catalyst depressuring/purging operations)• Do not apply to coke burn-off or

catalyst rejuvenation

• Apply to process vents during active purging/depressuring, regardless of vent pressure • Adding N2 while venting

• Passive depressuring (≤ 5 psig) still not applicable



MACT 2 – CRUs Inorganic HAPs

• Applicable during coke burn and catalyst rejuvenation• Emission limits (Table 22) – no change• CRUs – reduce HCl 97% or to concentration of 10 ppmv corrected to

3% O2• Less restrictive limit existing SRR – reduce HCl 92% by wt or to

concentration of 30 ppmv corrected to 3% O2• Other compliance requirements for CRUs in Tables 23 through

28 did not change other than correcting spelling regulatory references

• Operating limits and continuous monitoring • Same regardless of CRU type• Differ depending on the type of control device

• Operating limits established during performance testRefinery Sector Rule Focused Compliance

• Updated calculations for enriched air system

• Startup and shutdown purge gas routed to:• §63.670 compliant flare

or

• Incinerator/thermal oxidizer with firebox temperature and O2 limits

MACT 2 – Sulfur Recovery Units (SRUs)

http://www.enerprocess.com/processing‐&‐treating‐units/gas‐conditioning‐&‐treating/TEG‐gas‐dehydration‐&‐regeneration‐units


MACT 2 –SRUs• Emissions limits (Table 29)• Meet SO2 limits NSPS Subparts J/Ja if subject or design capacity ≥

20 LTD otherwise• Elect SO2 limit in NSPS or• Comply with total reduced sulfur (TRS) limit

• SO2 NSPS limit• Reduction control system with incineration – 250 ppmv of SO2

corrected to 0 percent O2 or concentration calculated using Equation 1 in NSPS Subpart Ja

• Reduction control system no incineration – 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 corrected to 0 percent O2or concentration calculated using Equation 1 in NSPS Subpart Ja


MACT 2 –SRUs (con’t)

• TRS limit• Reduction control system, no incineration – 300 ppmv of total

reduced sulfur (TRS) compounds expressed as an equivalent SO2concentration corrected to 0 percent O2


• Operate in accordance with OMM Plan (no change)

• Startup / shutdown purge gases• Meet normal emission limits

• NSPS or TRS• Current CEMS practices?

• Route to flare – compliant with §63.670

• Route to thermal oxidizer/incinerator – minimum hourly average firebox temperature of 1,200 deg F and minimum hourly average O2concentration 2 percent

MACT 2 – SRUs

TRSH2SCOSCS2

SO2


MACT 2– SRUsMonitoring

• NSPS – either subject or elect to comply• SO2 emissions CEMS with O2 analyzer or• Reduced sulfur emissions CEMS with O2 analyzer and calculate SO2• Equation 1 concentration calculation

• CEMS to measure O2 concentration for inlet air/oxygen supplied or• CPMS to measure volumetric gas flow rate of ambient air or oxygen-

enriched gas

• TRS limit • TRS concentration CEMS with O2 analyzer


MACT 2– SRUs (con’t)Monitoring

• Startup / shutdown • Same as normal operation• Flare – §63.670 and §63.671 monitoring required by 1/30/2019,

general requirements in §63.11 prior

• Incinerator / oxidizer – CPMS for firebox temperature and exhaust O2concentration


CRU & SRU – Summary8/30/2017 or Extension

• Not much changed so compliance procedure and monitoring already in place

• SRU – factor enriched air system monitoring into NSPS compliance limit calculation

• SRU – route S/U and S/D purge gases to control, no longer exempt• Flares meet §63.670 requirements by 1/30/2019• Incinerator/thermox meet firebox temperature and O2 requirement

now

• CRU – verify MACT 2 limits for organic HAPs are being met throughout the entire active depressuring/purge cycles


Major Changes to ReportingMACT CC and UUU

• Electronic filing of Performance Tests/RATAs• Semiannual Compliance Reports (SARs)• Changes that are effective now• Upcoming changes

• Fenceline Monitoring Quarterly Reports• General Duty• No more Startup/Shutdown/Malfunction Plans (SSMPs)


• Electronic Reporting Requirements• February 1, 2016 - performance test reports and CEMS

performance evaluation reports must be submitted electronically using EPA’s Electronic Report Tool (ERT) “for test methods currently supported by the ERT.”• Not all test methods are currently supported by the current ERT • Need to continually check the ERT website

http://www3.epa.gov/ttn/chief/ert/ert_info.html for supported test methods, as this will change over time.

• Reports generally must be submitted within 60 days following completion of the test.

Reporting – Electronic Filing


Reporting - SARs• What is Applicable now – MACT UUU SARs• If in compliance with filing electronically (63.1575(f)(1)(i))

• Summarize the results of applicable PTs/RATAs• If not in compliance with filing electronically (63.1575(f)(1)(ii))

• Attach all applicable PTs/RATAs not electronically reported• Sources not monitored by CEMS/COMS (63.1575(d)(4))

• Identification of each source for which there was a deviation.• The applicable limit or work practice for the deviation, including

description of the deviation.


Reporting – SARs (con’t)• Source monitored by CEMS/COMS (63.1575(e)(4))

• Estimate of quantity of regulated pollutants emitted over the limit during the event, and description of estimation method.


Reporting – MACT UUU SARs

• Estimating quantity from CEMS/COMS exceedances• CEMS reports determine exceedance/maintenance times, NOT

quantities

• Review CEMS data for periods over limits• Determine which excess periods were due to unit SU/SD and

exclude• These times are currently covered under the general duty clause (but

should verify General Duty was followed)

• After 8/1/2017 SU/SD events will be covered by CPMS and reported under sources not monitored by CEMS

• Estimate the quantity of emissions over the limits using the CEMS data and report


Reporting –SARs

• What is applicable now – MACT CC SARs• Tanks - Language is more clear that if a storage vessel fails an

inspection, the inspection report needs to be included in the SAR (63.655(g)(2-3))

• Updated reporting requirements for Group 1 MPVs when they are not routed to their control device (63.655(g)(6)(iii))

• Reporting changes for emission averaging (63.655(g)(8))• Any changes in the information provided in a previous Notification

of Compliance Status (NOCS) can now be reported in SARs (63.655(g)(14))


Upcoming Reporting –SARs

• Upcoming Reporting Requirements – MACT CC SARs• New PRD reporting requirements (once in compliance – January

2019) (63.655(g)(10))• New Flare reporting requirements (once in compliance – January

2019) (63.655(g)(11))• New Delayed Coking reporting requirements (once in compliance –

January 2019) (63.655(g)(12))• New Maintenance Vent reporting requirements (once in compliance

– Aug 2017) (63.655(g)(13))

• Upcoming Reporting Requirements – MACT UUU SARs• New SRU, FCCU, & CRU CPMS data under Sources not monitored by

CEMS/COMS (63.1575(d)(4))


Operation, Maintenance, and Monitoring Plans (OMMP)

• Covers all MACT UUU control systems and continuous monitoring systems

• Must be updated an approved after RSR changes• Quality control plan for all applicable UUU CEMS• Calibrations• Accuracy Audits

• Preventative maintenance schedule for all UUU monitoring systems and control devices

• §63.1574(f)


• General Duty Clause – EPA added language at §63.1570(c) to operate in a manner consistent with safety and good air pollution control practices to minimize emissions, replacing SSM language.

• Startup, Shutdown, and Malfunction Plans are no longer required.

Other Changes – General Duty


• Upload applicable RATA/PT to CDX

• Excess emission estimation and RATA summary added to MACT CC and MACT UUU SARs NOW

• Revise SAR templates/reports to include new provisions as they become effective

• General Duty documentation –no more SSM Plan need to document using good pollution control practices

Summary on Reporting & Recordkeeping


Presenter

Becca Crumpler, E.I.T.

Assistant Project Engineer

[email protected]

Oil and Gas Air RegulationsEquipment – Specific Requirements

WHAT WHY WHERE WHEN WHO HOW

Questions?

Presented by:

Stephen Walls, P.E.

Refinery Sector Rule Focused Compliance – Storage Vessels

• Applicability• Existing vs. new source• Tank grouping• Control requirements

Agenda

• Recordkeeping• Reporting• Compliance timeline

RSR Focused Compliance

§63.640(c)(2) – Three criteria listed for storage vessel to be subject to MACT Subpart CC

Meet storage vessel definition §63.641

Associated w/ petroleum process unit §63.640(e)

Refinery is HAP major source §63.640(a)(1) and contacts Table 1 listed HAP

§63.640(a)(2)

Applicability – Is My Tank In or Out ?


Applicability – Is My Tank In or Out ? (Storage Tank Definition)

Storage vessel = vessel storing organic liquids, excluding• Vessels on motor vehicles• Pressure vessels > 20.7 psi, no atm. emissions• Small vessels < 10,000-gal capacity• Bottoms receivers• Wastewater storage tanks

Units excluded from §63.641 storage vessel definition not subject to MACT Subpart CC


Applicability – Is My Tank In or Out ? (HAP Major Source Determination)

Meeting criteria in paragraph §63.640(a):

• Located at plant site that is major source • ≥ 10 tpy single HAP or • ≥ 25 tpy combined HAPs; and

Refinery process units at minor source refineries not subject


Applicability – Is My Tank In or Out ? (Refinery Process Unit Association)

Exclusive use by one process unit• Tank subject to MACT Subpart CC if process unit is subjectPredominant use by multiple process units• Predominant use determined by volume fed to vessel (process unit on

same site) or volume exiting vessel (process unit off site)• Tank subject to MACT Subpart CC if process unit is subjectNo predominant use by multiple process units• Tank subject if any process unit feeding material into tank is subject

Vessels not connected to any subject process unit are not affected


Applicability – Is My Tank In or Out ? (Special Exclusions)

• §63.640(d)(5): emission points routed to a fuel gas system

• §63.640(g)(2): excluded processes


Storage Vessel Applicability

RSR Essentials – Storage Vessels

Is vessel any of the following:• Attached to motor vehicle• Pressurized (> 29.7 psi) no atm. emis.•

Determining if Tank is Part of Existing or New Source

• Determine new vs. existing source to see what grouping criteria emission controls apply

• Existing • Constructed/reconstructed on or before 7/14/1994 and• Constructed after 7/14/1994 and does not meet major source

PTE threshold

• New• Process unit constructed at existing source after 7/14/1994 and

PTE ≥ 10 tpy (single HAP) or ≥ 25 tpy (total HAPs) or

• Reconstructed after 7/14/1994


Tank Grouping – Group 1

On or after 2/1/16Design Capacity Maximum TVP Annual Avg. TOH

Existing

Formerly existing tanks with capacity ≥ 177 m3 (45,000 gal) and TVP ≥ 10.4 kPa (1.5 psi) were Group 1

≥ 151 m3 (40,000 gal) ≥ 5.2 kPa (0.75 psi) ˃ 4 % w/w

≥ 76 m3 (20,000 gal) and < 151 m3 (40,000 gal)

≥ 13.1 kPa (1.9 psi) > 4 % w/w

New

≥ 151 m3 (40,000 gal) ≥ 3.4 kPa (0.5 psi) ˃ 2 % w/w

≥ 76 m3 (20,000 gal) and < 151 m3 (40,000 gal)

≥ 13.1 kPa (1.9 psi)

Formerly ≥ 77 kPa (11.1 psi)

> 2 % w/w

Group 1 Storage Vessels

TVP = true vapor pressureTOH = total organic HAP


Tank Grouping – Group 2

Group 2 means any tank that is not Group 1• Contents below TOH threshold

• ≤ 4% w/w HAP (existing) or ≤ 2% w/w HAP (new)• Design capacity between 40 m3 (10,000 gal) and 76 m3 (20,000 gal) • Below the appropriate maximum TVP threshold• Larger tanks ≥ 151 m3 (40,000 gal)

• Existing < 5.2 kPa (0.75 psi)• New < 3.4 kPa (0.5 psi)

• Smaller tanks ≥ 76 m3 (20,000 gal) and < 151 m3 (40,000 gal) • Existing/new < 13.1 kPa


What Control Requirements Apply?

G1 tanks

MACT Subpart G [§63.646]


MACT Subpart WW –floating roof and

MACT Subpart SS – fixed roof [§63.660]

Some G2 tanks overlap [§63.640(n)]

NSPS Subparts K, Ka, Kb, or Part 61, Subpart Y

What Control Requirements Apply?

• G2 tank stays G2 tank after rule revision• Continue to comply with K, Ka, Kb, or Part 61, Subpart Y unless• New/existing source under K or Ka not previously required to

apply controls – MACT Subpart CC or

• New source under Kb or Part 61, Subpart Y not previously required to apply controls – MACT Subpart CC

• G1 tank before rule revision• New/existing K or Ka tanks – comply with MACT Subpart CC• Continue to comply with Kb or Part 61, Subpart Y or choose to

comply with MACT Subpart CC


• G2 tank becomes G1 tank due to lower thresholds

• MACT Subpart CC – with potential extension to install controls (10-yr or next degassing)

What Control Requirements Apply? – Change in Group Designation


Subpart G requires G1 tanks controlled to 95 percent or 20 ppmv outlet concentration by• Floating roof conversion –

comply WW• CVS to control device – flare

§63.670• Fuel gas system, or • Vapor balancing – not SS option

Subpart SS has similar controls – no big change

Control Requirements – MACT Subpart CC (Fixed Roof Tanks)


Control Requirements – MACT Subpart CC (Fixed Roof Tanks)

Closed vent system (CVS)

AVO and Method 21 inspections – 500 ppm leak definition

Non-flare control device1

Reduce HAP emissions 95 percent or below 20 ppmv

Design evaluation or initial performance test for non-flare control device

Continuous parameter monitoring required

Flare1

Flares now subject to §63.670 and not §60.987

Route emissions to fuel gas or back to processOperate at all time when emissions are routed – SSM exemption does not apply.

1240 hrs/yr allowed for bypass of control device for planned maintenance

Control Requirements – MACT Subpart CC (Floating Roof Tanks)

• Regulations grant compliance extension of 10-yrs or until next degassing to:• Replace vapor-mounted rim seals without secondary seal on IFR

tanks – no extension for EFR tanks

• Replace vapor-mounted rim seals with secondary seals on EFR tanks

• Add secondary rim seal to a liquid-mounted or mechanical shoe type primary seal on EFR tanks



• §63.646 excludes tanks from compliance with deck fitting controls in MACT Subpart G

• No similar exclusion in §63.660 - §63.1063(a)(2) deck fitting controls apply

Deck fitting controls now required.



• Paragraph §63.660(b) - “may” elect to use a flexible enclosure device and either gasketed or welded cap flor slotted guidepole – additional compliance option

• Paragraph §63.660(b) - “shall” use one of the three control options for ladders with one slotted leg – new compliance requirement

It is unclear if the 10-yr or next degassing extension language applies to these control requirements


• 4/29/2016 –inspections, notifications, recordkeeping, and reporting

• 10-yrs or next degassing applies when controls need to be installed for compliance

Compliance Date



IFR EFR

Up-close visual inspection per §63.1063(d)(1)

Before initial fillEach time tank emptied/degassed (max. 10-yrs)

Each time tank emptied/degassed (max. 10-yrs)

Routine visual inspection per §63.1063(d)(2)

Seal gap inspection per §63.1063(d)(3)

Annually from opening in tank-topWithin 90 days of initial fillSecondary seal – annuallyPrimary seal – every 5-yrs

Inspections

Recordkeeping and Reporting

• Recordkeeping • Vessel grouping information• Inspection results• Floating roof landings

• Reporting • NOCS §63.655(f) – additional information for non-flare devices• Periodic reports include §63.655(g)

• 30-day inspection notification – up close or rim seal• Inspection failures• Extension requests for repairs and unsafe to perform


• Managing tank TVP data and contents changes

• Managing control device compliance –2019 flares vs. 2016 non-flare device

• Managing installation of controls not listed in MACT Subpart CC outside of MACT Subpart WW – 10-yr extension?

• Vapor mounted rim seal without secondary seal for EFR

• Guidepole ladder combination controls

Compliance Outlook


Presenter

Stephen Walls, P.E.

Senior Engineer

[email protected]



Questions?

Presented by:


Vents Miscellaneous Process Vents (MPVs) &

Pressure Relief Devices (PRDs)

Group 1Group 2

Maintenance Vents

MPVs

Major MPV RSR Changes

• Maintenance Vents• High point bleeds• Analyzer vents


• HAPs < 20 ppmv(0.002%)

HAP Content


• Steam• Water• Plant Air• Fresh Chemicals (i.e.

caustic)

• LPG• Purchased NG

HAP Content - Potentially Exempt Streams


• Some Site Dependent Streams• Sample Data

• Finished Butanes/Propanes• Hydrogen• Heavy Streams – vaporous

HAPs• Temperature Dependent• Diesels, Jet Gasolines, Resid,

Slurry, Vacuum Gas Oil

IF YOU DON’T HAVE RELIABLE SAMPLES - BE CONSERVATIVE

HAP Content - Potentially Exempt Streams


• Streams routed to a fuel gas system

• PRDs• LDAR Leaks• CCU regeneration vents• CRU regeneration vents• SRU vents• Vents from control devices on

other MACT UUU regulated equipment

• Stripping vents on units complying with associated wastewater provisions

• Emissions associated with delayed coking unit decoking operations

• Vents from storage vessels (i.e. Tanks)

• Emissions from wastewater collection and conveyance systems (i.e. wastewater drains, sewer vents, and sump drains)

• Hydrogen production plant vents through which carbon dioxide is removed from process streams or through which steam condensate produced or treated within the hydrogen plant is degassed or deaerated

MPV Exemptions/Exclusions


Group 1 MPVs

• Gas/Vapor stream• Continuously or periodically

discharged

• HAPs >20 ppmv• VOCs > 72 lbs/day (existing)• VOCs > 15 lbs/day (new) • Need to be routed to a

control device

Group 2 MPVs

• Gas/Vapor stream• Continuously or periodically

discharged

• HAPs >20 ppmv• VOCs < 72 lbs/day (existing)• VOCs < 15 lbs/day (new) • Should be identified and

documented

Group 1 vs. Group 2 MPVs


MACT Existing vs. New MPVs

• Process Unit Construction Date?• After July 14, 1994?

• Process Unit HAP emissions • > 10 TPY of any HAP or >25 TPY of total HAPS?

• Yes to Both = must follow “new” source requirements• Major difference between existing vs. new is allowed VOC

emissions• Existing = Group 1 if >72 lb/day VOC• New = Group 1 if >15 lb/day VOC

• No Group 1 vs. 2 designations for Maintenance vent subcategory


• 8/1/2017 Compliance Date vs Extension Requests?

• Practicing Compliance?

Maintenance MPVs


Maintenance MPVs

• MPVs only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed, or placed into service


Maintenance MPVs –Compliance Options

• Measurement < 10%* LEL when opened to atmosphere• Measurement < 5 psig when opened to atmosphere• Calculation < 72 lbs VOC


Maintenance MPVs – 10% LELPROs CONs

Less burden on Env. Department More burden on Ops/Maintenance

Typically already an operational procedure Compliance relies on Ops/Maintenance

Trouble vessels >10%

Possible extra purging/cleaning to get to 10%

More prep time

Sampling issues


Maintenance MPVs – 5 psigPROs CONs

Less burden on Env. Department More burden on Ops/Maintenance

Typically already an operational procedure Reasons for not monitoring LEL

Compliance relies on Ops/Maintenance


Maintenance MPVs – 72 lbs VOCPROs CONs

Less burden on Ops/Maintenance More burden on Environmental

Compliance controlled by Env. department Need A LOT of data/assumptions for calculation

Assistance from Engineering

Keep A LOT of records


Maintenance MPVs vs. Group 2 MPVs

MAINTENANCE (72 lbs option) GROUP 2

Emission Estimation Protocol (lbs) PTE (lbs/d)

Demonstrate events have < 72 lbs VOC Need FGRU

Include ALL in NOCS

• PTE needs to include all emissions• Controlled – flare/TO/Heater/Boiler – AND Uncontrolled• CAN exclude emissions sent for recovery (FGRU/VRU)


• DATA, DATA, and more DATA!

• Vessel• Size

• Stream Contents • Speciated data• VOC % (wt & vol)• SG• MW• Phase (gas vs. liquid)

Maintenance MPVs72 lbs VOC Calculation Methodology


Maintenance MPVs

• Assumptions, Assumptions, and more ASSUMPTIONS!• Pressure• Temperature• Purge?• Packing Material/Void Factors?• Heel %• Clingage %• Set as conservative constants then vary depending on

specific situations

72 lbs VOC Calculation Methodology


Maintenance MPVs

• Follow Emissions Estimation Protocol for Petroleum Refineries (2015)• Section 11• Examples 11-1 & 11-2

• Gas vs. Liquid Emission Estimates

GAS

LIQUID

528°

%

100

62.4 % %



Maintenance MPVs

GAS LIQUID

MW & VOC fraction (vol) SG & VOC fraction (wt)

Speciation/Lab Data

VOC % MW SG

Constants & Assumptions

T & P Atm Pressure Stream Phase Clingage VoidFractions



Maintenance MPVs

EXAMPLES

Maintenance Vent Examples



Maintenance MPVs

PROBLEM SOLVING ACTIVITY:

Gas50 bbl vesselFlare Gas

VOC %: 9.87MW: 16.52MWVOC*VOC%: 6.46

Same Assumptions:P: 15 psigT: 200 FPact: 11.7 psigFvoid: 1

No Purge

Liquid50 bbl vesselNaphtha

VOC frac: 0.98SG: 0.73

Same Assumptions:P: 15 psigT: 200 FPact: 11.7 psigFvoid: 1Heel%: 0.5

No Purge



Maintenance MPVs

PROBLEM SOLVING ACTIVITY:

Gas50 bbl vesselFlare Gas

VOC %: 9.87MW: 16.52MWVOC*VOC%: 6.46

Same Assumptions:P: 15 psigT: 200 FPact: 11.7 psigFvoid: 1

No Purge

Liquid50 bbl vesselNaphtha

VOC frac: 0.98SG: 0.73

Same Assumptions:P: 15 psigT: 200 FPact: 11.7 psigFvoid: 1Heel%: 0.5

No PurgeVOC = 59.48 lbs VOC = 62.66 lbs



Maintenance Vent Problem Solving

RECORDS – NO LONGER REQUIRED!!!• 3/19/2018 Proposed

Amendments• Original Rule - Needed

records of all maintenance activities

• Focus on calculating maintenance vent VOCs accurately• Have template spreadsheet to

calculate emissions • Minimize inputs

Maintenance MPVs72 lbs VOC Calculation Methodology


Maintenance MPVs – 10 LEL Considerations

• Testing/Sampling LEL• Hot temperatures• Steam

• Some sort of cooling method necessary?• Large Vaporous Vessels• Trouble meeting

Maintenance MPVs – Records

• Tracking Maintenance and Compliance• Inventory

• All in one place• Not have to search

• Maintenance Databases (EMPACT/SAP/FacilityPlus…)• Search individual events separately• Verify has all required information

• Different depending on compliance option for each vent

• Maintenance Venting Forms• What should be included on these?

• Environmental Maintenance Vent Form


Maintenance MPVs

Other Issues/Ideas on Maintenance Vents?


MPVs – High Point BleedsMAINTENANCE (72 lbs option) GROUP 2

Emission Estimation Protocol (lbs) PTE (lbs/d)

Maintenance event Records/Demonstration Need FGRU

IDENTIFY & Include ALL in NOCS

• Maintenance HP Bleeds• Compliance Option?

• Use Line/piping ‘Look-up’ table• Identify as they come up

• Group 2 HP Bleeds• Initial identification for NOCS

• P&ID reviews• Field walk downs

• Don’t need the continuous records


• HAP Content• Units with High Gas

Combustion• Lab data* show HAPs < 20

ppmv• FCC• Heaters• EXEMPT?

• Trace Erase• Assume HAPs consumed

before venting• Verify preventative

maintenance

MPVs – Analyzer Vents


• Determining Best Category for YOU: • Gr. 1• Gr. 2• Maintenance

• Determining Best Maintenance Vent Compliance Option:• < 10% LEL• < 5 psig• < 72 lbs VOC

• RECORDS• Creating Form• Making Inventory• Utilizing databases already

around

MPVs – Summary



MPV Questions?

PRDs

Discharge to Atmosphere

Pressure Relief Devices (PRDs)

• Pressure Relief Valves (PRVs) • Rupture Disks • Any Other Pressure Relief System• Still need to operate PRDs with < 500 ppm per Method 21

• Not during a pressure release event• Non-exempt atmospheric relief valves have significant requirements

• Monitoring System• Identify release• Track time• Notify operators

• 3 Redundant Prevention Measures• Root cause analysis/corrective actions (RCAs) • Emission Calculations

• similar to Consent Decree and Flare NSPS Ja RCA/CA requirements


PRD Exemptions

• PRDs routed to a control device• PRDs in heavy liquid service• PRDs that only release liquids (at STP: 1 atm and 68˚ F) and

are hard-piped to a controlled drain system or piped back to the process or pipeline

• Thermal expansion relief valves• PRDs with a set relief pressure < 2.5 psig• PRDs that emit < 72 lbs/day VOC• Based on the valve diameter, the set release pressure, and the

equipment contents

• PRDs on mobile equipmentRSR Focused Compliance

• Must have a monitor on the PRD or associated system with the following capabilities:• Identify a pressure release• Record the time and duration of

a pressure release• Alert operators immediately of a

pressure release

• Common Examples• Motion detector• Flow monitor• Pressure monitor• Magnetic sensor• Other ideas?

PRD Monitoring Devices


PRD Redundant Measures

• Each PRD must have at least 3 redundant measures to prevent releases• Must be documented

• Preventive Measure Examples:• Any additional monitors mentioned earlier• Temperature monitors• Level indicators• Routine inspections/maintenance and/or operator training

• Documented• Can only account for 1 measure

• Inherently safer designs or safety instrumentation systems• Deluge systems• Staged relief system with 1st PRD routed to closed system or control device


PRD Reporting and Tracking

• Calculate quantity of Organic Hazardous Air Pollutants (OHAP) released for each event• Can be based on monitoring data and process knowledge• Include in MACT CC Semiannual Compliance reports

• Conduct Root Cause/Corrective Action Analyses (RC/CA) for each event (discussed in next slide)

• Track number of releases from each PRD• Per Calendar year basis• Note events with force majeure root causes

• PRD release event violations:• Operator error/Poor maintenance• 2nd release from same PRD with same root cause within 3 calendar years• 3rd release from same PRD within 3 calendar years


PRD Reporting and Tracking

• Create Compliance Tracking Program• Organize data and events all in one location for tracking• Identify all applicable PRDs

• Compliance monitor• List redundant measures

• Track individual releases

PRD Compliance Tracking Spreadsheet


PRD Root Cause/Corrective Action Analyses

• Required for all PRD atmospheric releases• Within 45 days of event• Only 1 RC/CA analysis is required for an event that causes multiple

PRD releases on the same equipment

• RC/CA analyses from various equipment may be combined to 1 analysis if the initial RC/CA determines the events have the same RC

• Corrective Actions (CAs)• Implemented within 45 days or as soon as practicable

• Implementation schedule required for CAs not conducted within 45 days• Record the dates CAs were completed

• If no CAs deemed necessary, record and explain reasoning within 45 days


PRDs - Summary1/30/2019

• Sites should have a good starting point on existing PRDs• Included in PSM/inspection programs

• LDAR teams currently perform monitoring on atmospheric PRDs

• Need to verify HAP PRDs to atmosphere• Need to survey current monitoring devices on these PRDs• If no appropriate monitors they will need to be installed

• Determining and documenting 3 (at least) redundant measures

• New program to document and conduct RC/CA when PRDs release



PRD Questions?

Presenter


Assistant Project Engineer

[email protected]


Presented by:

Jeremy Sell, P.E.

Fenceline Monitoring

• Radial Method• 800 acre

facility

• 26,000 feet perimeter

Establish Fenceline Monitoring Stations

Refinery Size(acres)

Required Angle

Minimum Sample Stations

1,500 15 24

• Rule updates• Fenceline data review• Data management• Lessons learned • Root cause analysis

process

• CEDRI reporting• Public outreach

Fenceline Monitoring Overview

RSR Essentials – Fenceline Monitoring

Fenceline Monitoring Rule Updates

• September 2017 ExxonMobil Letter• Method 325B update to only use temperature• Sample collection timing clarification• QAQC sample frequency change• Duplicate sample calculation

• March 2018 EPA Proposed Amendments and Technical Corrections• Method 21 in place of additional sample location• Reporting clarification


• Method 325B change• Dropped pressure from the

calculation so temperature is all that is needed now

• Sample collection timing clarification• Allows for placement or

retrieval earlier or later than 13 to 15 days when circumstances do no permit safe work

• Has to be reported in the next reporting cycle




• QAQC sample frequency change• Originally duplicates were at a rate of 1 per 10 locations and 2

blanks per event

• Update• 19 or fewer locations – 1 duplicate and 1 blank• 20 or more locations – 2 duplicates and 1 blank

• Cost savings for small site (


• Duplicate sample calculation example

• Station 14: Sample – 3.7 µg/m3Duplicate sample – 2.9 µg/m3

Average – 3.3 µg/m3

• Station 8: Sample – 3.5 µg/m3No duplicate

• Station 1: Sample – 1.1 µg/m3

What is the Δc for this sampling event? 3.5 – 1.1 = 2.4 µg/m3



• Method 21 in place of additional sample• If only emissions sources within 50 meters of fenceline are

equipment leak sources and meet all the following:

• Sources in HAP service are limited to valves, pumps, connectors, sampling connections, and open-ended lines

• Leak sources in HAP service must be monitored using EPA Method 21 at least quarterly

• Leak sources in HAP service must have monthly AVO inspections• All leaks repaired with 15 days with no DOR provision


• Reporting clarification• Quarterly reports are

based on calendar quarters rather than being tied to compliance dates

• First report due 45 days after the end of the calendar quarter in which 12-months of data was obtained (May 15, 2019)



Fenceline Data Review

• 39 facilities• Nearly 600,000 benzene results• 21 of 39 facilities below action level, 7 others with slight

exceedances

• Δc at remaining 11 facilities ranged from 15 µg/m3 to over 500 µg/m3, with an average of 39 µg/m3

• 1 in 4 refineries will require corrective actions


• Most common source issues include:• Tanks farms• Loading racks (truck and

barge)

• Wastewater treatment areas

• Process areas

Fenceline Data Review


Fenceline Data Management

• Fenceline sampling for many sites will be a data management exercise• 26 sample events x 20 stations + 3 QA samples = 598/year • Hourly weather data = 8,760/year

• However, it only takes a couple of events to change things• Site with Δc of 4 µg/m3 will exceed action level with:

• 2 events of 100 µg/m3• 3 events of 50 µg/m3• 6 events of 30 µg/m3


Lessons Learned

• Adjacent property/subareas


700 ft

• Weather station interruption• Use a different weather station

that is located within 25 miles

• Use the average of data you have for the period

• Since pressure is no longer part of calculation, use a certified local temperature reading

• No temperature data, the data for the period would not be valid, possible enforcement action

Lessons Learned


Root Cause Analysis /Corrective Action

• Within 45 days of completion of sampling period, determine if action level is exceeded

• Initiate root cause analysis within 5 days of determining action level exceedance

• Initial corrective actions taken no later than 45 days after determining there is an exceedance

• If the next Δc value exceeds the action level, develop a Corrective Action Plan to submit to Administrator within 60 days of receiving data


CEDRI Reporting

• Facility name and address• Year and reporting quarter• Lat/long for each sample station (1st time only)• Dates for each sample period• Individual results for benzene• Data flags for outliers


• Develop training for refinery employees

• Present data to refinery work group

• Develop website to provide data with and explanation of what it means

• Other ideas?

Public Outreach


Presenter

Jeremy Sell, P.E.


[email protected]



Questions?

Presented by:

Stephen Walls, P.E.

Refinery Sector Rule Essentials Flares

• General Overview• Applicability• Definitions• Enhanced Operational

Standards – Flares

• Emergency Provisions• Recordkeeping/reporting• Consent Decrees, ADIs,

and AMPs

Agenda

RSR Essentials – Flares

Rule Overview – How We Got Here

• Replace 40 CFR 60.18(b) and 40 CFR 63.11• Focus on destruction efficiency when in HAP service• Extend to additional flare types• Consistent standards for all flare types• PFTIR monitoring infeasible on continuous basis• Compliance date = January 30, 2019


Applicability – What Flares Subject?

Flare = APCD used to control HAP emissions from

• Petroleum refining process units (c)(1) through (c)(9) *Don’t forget MACT UUU sources – FCCU, CRU & SRU

• Refinery = HAP major source (≥ 10 tpy single HAP or ≥ 25 tpy total HAPs)

• Contain/contact one of 27 HAPs listed in Table 1*a.k.a. regulated material routed to flare



Source type MACT Subpart CC citation Applicable regulations prior to January 30, 2019

Volatile organic liquid storage vessels

§63.640(n)(8)(viii) Part 60, subpart Kb

Benzene storage vessels §63.640(n)(10)(viii) Part 61, subpart Y

Wastewater treatment§63.640(o)(2)(i)(D) §63.640(o)(2)(ii)(C), and§63.647(c)

Part 61, subparts FF (BWON)Part 63, subpart G (SOCMI NESHAP)

Miscellaneous process vents §63.643(a)(1) 40 CFR 63.11 (b)

Equipment leaks §63.648(a)(3) Part 60, subpart VV

Equipment leaks §63.648(c)(12) §§63.172 and 63.180

Gasoline loading racks §63.650(d) Part 63, subpart R

Marine tank vessel loading §63.651(e) Part 63, subpart Y

Regulatory Overlap

§63.640(s) includes “catch all” flares subject to general requirements (§60.18 and §63.11) comply with MACT Subpart CC

Regulations with flare requirements now specifically reference MACT Subpart CC.

• Regulated material• Control device• Combustion device• Flare• Assist-steam – upper, lower,

center• Assist-air – perimeter and pre-

mix• Combustion zone• Pilot, purge, sweep,

supplemental, waste, and vent gases

Definitions


Typical Flare System Diagram

Pilot gas

Assist media

K.O. Drum

Waste gas

Seal Drum

FGR

Purge gas

Supplemental gas

Sweep gas

Sweep gas

• Pilot flame presence• Visible emissions• Flare tip velocity• Combustion zone net

heating value (NHVcz)

• Dilution parameter (NHVdil)

Enhanced Operational Standards


• Compliance during 15-min block

• Not rolling 15-min block• Based on cumulative

and average data during clock segments

Averaging Time


45‐60 min

0‐15 min

15‐30 min

30‐45 min

4 compliance blocks per hour

Pilot Flame Presence


Requirement (§63.670) Description

Standard (b) A pilot flame present at all times

When applicable (b) Regulated material vented to flare

Deviation (b) 15-min block with no pilot flame for at least 1-min

Monitoring (g) Continuous with thermocouple, UV beam sensor, IR sensor, or equivalent

Monitor location (Table 13) Manufacturer specifications

Excluded from Table 13 minimum accuracy, and calibration requirements per §63.671(a)(1)

• Consistent with §60.18 and §63.11 => no 1-min deviation

• Additional monitoring types added

• Prevent HAP emissions without control



• Monitoring Types• Thermocouple• Pyrometer• Ionization• UV beam sensor• IR sensor• Acoustic

• Combination of multiple methods



Visible Emissions



Standard (c) Operate with no visible emissions (smoke)

When applicable (c) Regulated material vented to flare Vent gas flow less than smokeless capacity

Deviation (c) More than 5-min of smoke in consecutive 2-hr period

Monitoring (h) Method 22 observations (initial 2-hr, daily 5-min) orContinuous recording with video surveillance camera

Monitor location (h)(2) Camera positioned to record flame and reasonable distance above flame at an angle suitable for visible emission observations

No Table 13 minimum accuracy, calibration, or inspection requirements.

• Consistent with §60.18 and §63.11

• Added camera monitoring option

• Prevent smoking during normal operation

• Emergency flaring RCA

Visible Emissions


Sidebar – Smokeless Capacity• Quantity of gas that can be combusted without generating

smoke

• Physical limitation on quantity of steam to the flare tip• Affected by• Gas volume• Gas composition / MW

• Expressed in volumetric units, mass units, or percentage of hydraulic capacity

• Flow rate vs. total flow


Method 22 observation

• 40 CFR part 60, Appendix A-7• Daily 5-min• Additional daily VE routinely

observed

• Extend 2-hr if 1-min VE observed in 5-min

• Cease 2-hr when 5-min VE observed

Visible Emissions


Video surveillance camera

• Continuously record• 1 frame per 15-min• Time & date stamps

• Suitable position• Flare flame• Reasonable distance

above flame

• Output continuously manned location

Flare Tip Velocity



Standard (d) < 60 ft/sec or< 400 ft/sec and < vmax = (NHVvg + 1,212) / 850

When applicable (d) Regulated material vented to flare for at least 15-minVent gas flow less than smokeless capacity

Deviation (d) 15-min block where vtip = Qcum / (Area x 900) exceeds standard

Monitoring (i) & (j) Vent gas flow – incl. P/T monitors for 68 deg. F and 1 atm correctionGas composition or heat content

Monitor location (Table 13) Flow – representative, minimize upstream/downstream disturbancePressure – representative, minimize pulsating, vibration, corrosionTemperature – representative, shielded from electromagnetic interference and chemical contaminantsGas composition - 0.5d upstream and 2d downstream from concentration change or control device (PS 9, Section 8.1)Heat content – 0.5d upstream and 2d downstream of disturbance, 2d from concentration change or control device

• Consistent with §60.18 and §63.11

• Same for steam-, air-, and non-assisted

• vmax calc. changes –mostly metric to S.I. conversion

• Remove size and H2criteria non-assisted

Flare Tip Velocity


Sidebar – Unobstructed Area

• Total tip area vent gas can pass through• Excludes stability tabs, stability rings, upper steam ring,

lower steam tubes, etc.

• Determine using engineering principles• Watch out for ID (flare tip) and OD (steam tubes)• Vendor can determine


Sidebar – Vent Gas Flow Monitoring

• Continuous measurement• Include waste gas, sweep gas (typically combined with waste

gas), purge gas, and supplemental gas• May require multiple monitors• Supplemental gas requires separate monitor for feed-forward calculation

• STP correction – 68 °F and 1 atm• Alternative monitoring option with MW from gas composition

• Mass flow meters with volumetric conversion .

• Continuous P/T with engineering calculation• Different methods can be used for different streams, as long as all

streams are included


• Turndown – flow changes• MW fluctuations• No pressure drop• Monitoring Types• Ultrasonic• Thermal mass• Coriolis• Optical scintilation

Vent Gas Flow Monitoring


Vent Gas Flow Monitoring



Min. accuracy (Table 13) ±20 percent of flow rate at velocities 0.1 to 1 ft/sec±5 percent of flow rate at velocities > 1 ft/secP sensor – greater of ±5 percent over normal range or 0.5-in H2OT sensor - greater of ±1 percent over normal range or 2.9 deg. (all in deg. C)

Calibration (Table 13) Biennial P sensor – Annual gauge and transducerT sensor – Annual* Flow, P, and T - after 24-hr period where measured parameter exceeds manufacturer maximum rated value

Inspection (Table 13) Quarterly integrity and electrical inspectionP sensor – Quarterly integrity, electrical continuity, mechanical leakageT sensor – Quarterly integrity, electrical continuity, oxidation, corrosion

Pressure sensors also have requirement for weekly review of data for straight line (unchanging) pressure to check flor blockage.

Vent Gas Flow Calculations

• Monitors typically provide rate – volume or mass per unit time

• May need to convert to total flow – volume or mass during specific time block

• Cumulative flow (Qcum) = sum of total flow for 15-min block

• Convert mass to volumetric before sum• Use average P/T to calculate 15-min block flow


Vent Gas Flow Calculations


Monitoring strategy How to calculate cumulative flow, Q Gas composition data required

Continuous volumetric flow monitoring

Sum P and T corrected volumetric flow data for each 15-min block

Gas composition data not required for flow rate conversion only for determining net heating value

Continuous mass flow monitoring

Mass flow data converted to volumetric flow

385.3Sum calculated Qvol for each 15-min block

Gas composition data from continuous monitoring or grab sampling every 8-hrs required to determine MW

Use default MW for assist media, no default for natural gas

Continuous P and T monitoring with engineering calculations

Calculate average P and T for each 15-min block*Use calculated average P and T as input parameters for each 15-min block flow calculation*

Gas composition data from continuous monitoring or grab sampling every 8-hrs may be required if part of engineering calculation

*Can divide each block into equal subperiods instead of performing calculation for entire 15-min period

Sidebar – Vent Gas NHV Monitoring

• Direct compositional• Continuous measurement – GC or mass spec (every 15-min)• Evacuated canister grab sample (8-hr interval)

• Net heating value monitoring• Calorimeter• Optional H2 analyzer for 1,212 Btu/scf correction


• Speciation• Sample time• Cost• Monitoring Types• GC• Mass spec• Auto sampler / lab analysis• Calorimeter

Vent Gas NHV Monitoring


Vent Gas NHV Monitoring



Min. accuracy (Table 13) GC – ±10 percent calibration gas (PS 9)Calorimeter - ±10 percent of spanOptional H2 analyzer – greater of ±2 percent of concentration measured and 0.1 vol. percent

Calibration (Table 13) GC – initial calibration error, initial an quarterly performance evaluation, daily drift, quarterly multi-pointCalorimeter – min. manufacturer rec., specify in CPMSOptional H2 analyzer - min. manufacturer rec., specify in CPMS

Inspection (Table 13) GC – pretest prep Method 18Calorimeter – none listed, manufacturer rec.Optional H2 analyzer – none listed, manufacturer rec.

Mass spec broadly applicable alternative follows PS 9 with a pre-survey to identify compounds and concentrations present.

Additional GC Requirements

• QA requirements in Table 13 – PS 9 in Part 60, Appendix B except• Single daily mid-level check – not triplicate• Multi-point calibration quarterly – not monthly• Minimum sampling temperature 60 deg C – not 120 deg C

• Calibration gases• Single combined gas that includes all listed species (some listed compounds

optional)

• Multiple gases used to include all listed species – must calibrate on all gases• N-pentane response factor used to quantify hydrocarbons that elute after C5• Can use surrogate calibration gas of C1 to C5 normal hydrocarbons

• Use RF for nearest n-alkane to quantify unknown compounds• Use RF for n-pentane to unknown compounds that elute after n-pentane


Vent Gas NHV Calculations

• Calculate using analyte concentration – Table 12• Direct monitor – w/ or w/o H2 adjustment• Determine separately for each stream• Natural gas – measurement, annual supplier NHV, or default

(920 Btu/scf)

• NHV determined based on calc. method selected• Direct - arithmetic average• Feed-forward – most recent value previous 15-min block• Based on time data available, not sample collected• Flow-weighted average of 15-min block data for NHVvg


Vent Gas NHV Calculations


Monitoring strategy Calculate NHV

Direct compositional monitoring- Continuous component concentration- Grab sampling

xi = concentration of component i in flare gas, volume fractionNHVi = net heating value of component i from Table 12

Continuous calorimeter without hydrogen monitoring

NHV determined by direct output of monitoring system in Btu/scf

Continuous calorimeter with hydrogen monitoring

938

Vent Gas NHV CalculationsTime NHV

Nat. GasNHV

Waste GasBlock Avg.

NHV (Direct)NHVvg

(Direct)Block Avg. NHV (Feed-forward)

NHVvg(Feed-forward)

11:48

980 Btu/scf

Provided annually

by supplier

1,116 Btu/scf

12:00

600 Btu/scfarithmetic average of

data available

within block

663 Btu/scf flow-weighted average of 15-

min block data

1,116 Btu/scfmost recent

data available from previous

block

1,093 Btu/scf flow-weighted average of 15-min block data

12:01 900 Btu/scf

12:14 300 Btu/scf

12:15

850 Btu/scf 872 Btu/scf 300 Btu/scf 413 Btu/scf12:27 850 Btu/scf


Assume cumulative Q nat. gas = 200 scf/15-min and Q waste gas = 1,000 scf/15-min

Flare Tip Velocity, Vtip• Evaluate compliance for each 15-minute blockFor NHVvg < 300 Btu/scf (may no comply with NHVcz std.)

/

For 300 Btu/scf < NHVvg < 1,000 Btu/scf

,

For NHVvg > 1,000 Btu/scf

/

• Qcum only required to include flow during period of regulated material flow – what does that mean for 900 sec/15-min block constant


Combustion Zone NHV



Standard (e) ≥ 270 Btu/scf

When applicable (e) Regulated material vented to flare for at least 15-min

Deviation (e) 15-min block where NHVcz less than standard

Monitoring (i) & (j) Same flow, P/T, and NHV monitoring as vtipAdditional assist-media flow monitoring (steam and premix air)Separate flow monitor for supplemental fuel (feed-forward method)

Monitor location (Table 13)

Same flow, P/T, and NHV monitoring as vtipAssist media – representative, reduce swirling/disturbance/abnormal velocity distribution from upstream and downstream disturbances

• Lower std. than §60.18 and §63.11 – 300 Btu/scf to 270 Btu/scf

• Same for steam-, air-, and non-assisted

• Compliance point change

• Now calculate using one of two methods

Combustion Zone NHV


Sidebar – Assist Media Flow Monitoring

• Continuous measurement• Assist steam (upper, lower, and center) flow• Pre-mix assist air – perimeter assist air not req’d NHVcz• Monitor perimeter and pre-mix assist air separately

• STP correction – 68 °F and 1 atm• Same monitoring options as vent gas flow – volumetric,

mass, and P/T• Default MW provided – steam = 18 lb/lbmol, air = 29 lb/lbmol

• Monitor fan speed/power and fan curve (assist air only)


• More consistent flow• Default MWs• Pressure drop monitors

OK

• Monitoring Types• Ultrasonic• Coriolis• Pressure drop – orifice

plate, V-cone, vortex, etc.

Assist Media Flow Monitoring


Assist Media Flow Monitoring



Min. accuracy (Table 13) Liquid flow: Greater of ±5 percent over normal range or 0.5 gpmGas flow: Greater of ±5 percent over normal range or 10 cfmMass flow: ±5 percent over normal rangeP and T sensors same as vent gas flow monitors

Calibration (Table 13) Same as vent gas flow monitors

Inspection (Table 13) Quarterly for leakageP and T sensors same as vent gas flow monitors

Feed-forward calculation

,

Direct calculation

,

NHVcz Calculation Methods


Dilution Parameter



Standard (f) ≥ 22 Btu/ft2

When applicable (f) Regulated material vented to flare for at least 15-minFlares with perimeter assist air

Deviation (f) 15-min block where NHVdil less than standard

Monitoring (i) & (j) Same flow and P/T monitoring as assist media flowMust monitor pre-mix and perimeter assist air separately

Monitor location (Table 13)

Same flow and P/T monitoring as assist media flowMust monitor pre-mix and perimeter assist air separately

• New – nothing in §60.18 or §63.11

• Only for flares with perimeter assist air

• Not calculated 15-min block w/o perimeter assist air

• Determine effective diameter from unobstructed area

2 /

Dilution Parameter


Feed-forward calculation

, ,

Direct calculation

, ,

NHVdil Calculation Methods


Typical Flare Monitors

Pilot gas

Assist media

K.O. Drum

Waste gas

Seal Drum

FGR

Purge gas

Supplemental gas

Sweep gas

Sweep gas

FTP

FTP

F T PF T P

FTP

F T PGas Comp.

Thermocouple, IR, UV monitoring

Emergency Provisions – §63.670(o)

• Flare management plan (FMP) - minimize flaring during startup (S/U), shutdown (S/D), and emergency events• Contents listed (o)(1)(i) through (o)(1)(vii)• Different from NSPS Subpart Ja FMP• Maintain on site and submit to agency

• RCA/CAA process• Operational standards VE and vtip apply Qvg < smokeless capacity• Qvg > smokeless capacity and either VE or vtip standard exceeded = RCA/CAA• Track total RCA/CAA events for violation of work practice standard

• Same RC > 2 VE or vtip events in 3-yr (calendar) period• Any RC > 3 VE or vtip events in 3-yr (calendar) period• Any event where operator error is root cause


Recordkeeping and Reporting

Recordkeeping §63.670(p) [reference §63.655(i)(9)]• Monitoring data and VE observations – raw data and calculated parameters• 15-min block cumulative flow and averages• Operating values outside standard• Period no monitoring was performed• Times – flaring ≠ regulated material, not flaring, and Qvg > smokeless capacity• RCA/CAA

Reporting §63.670(q) reporting [reference §63.655(g)(11)]• Periodic report – exceedance of pilot flame, VE, vtip, NHVcz, or NHVdil parameters• Emergency flaring events – RCA/CAA


Special Cases

• Alternative Means of Emission Limitation (AMEL) - §63.670(r)• Establish site-specific limits for single flare• Demonstrate CE 96.5 percent or DE 98 percent• Submit test plan and final report to EPA – published in FR upon acceptance

• Alternative Monitoring Plan (AMP) - §63.8(f)• Propose new monitoring method – different from requirement• Submit to agency for approval prior to use

• Heat content monitoring exemption - §63.670(j)(6)• Apply to exempt stream from heat content monitoring• Constant composition or fixed minimum heat content• Eff. date exemption = date completed application submitted to agency


General Monitoring Requirements• Comply with Table 13 accuracy and QA/QC & out-of-control

procedures – excludes pilot flame monitors

• Readout accessible – ops. board, local display, DAS software• One cycle each 15-minutes (sample, analyze, and record)• Operate at all times when regulated material is routed to flare –

excludes monitoring system malfunctions, periods of repairs, and required system QC activities

• Operate per CPMS Monitoring Plan• Maintain on site - submit to agency upon request

• Capable of measuring over the range of values expected


Consent Decrees

• EPA flaring initiative• AG and HC flares = NSPS Subpart J/Ja applicability• Flow monitoring• H2S/sulfur monitoring – SO2 emission limit• Some STP inconsistencies

• RCA process for flaring events• Some flaring specific CDs with requirements similar to

MACT Subpart CC


Consent Decrees

• Older flares (pre-1973) surveyed• FGR / caustic scrubber controls• Some CDs have expanded flare requirements• MACT Subpart CC• Momentum flux ratio• Waste gas mapping/minimization• PFTIR evaluation for DE

• Chemical plants getting pulled in


Things to Think About

• Duplicative monitoring pilot flame – excess emissions• Flare event determination monitoring• Not included in RSR, CPMS Plan inclusion?

• Flow meter trouble shooting – no golden arrow• Total flow vs. flow rate data reduction• Building in 15-min cumulative flows and average NHV

• Setting up data reduction• Local transmitter vs. PLC/DCS vs. DAS, vs. external


Things to Think About

• Opportunities for AMP – CD/permit and RSR inconsistent• Different target analytes• Calibration gas ranges• Exclusion of out-of-control and calibration data• Calibration criteria – analyte concentration vs. NHV value• P/T correction – some CDs show information for both standards 60

deg. F and 68 deg. F in the same document

• 8-hr sample analysis during off hours• Default MW for natural gas• Ultrasonic MW instead of GC or mass spec• Inclusion of center steam from vtip calculation


Presenter


Stephen Walls, P.E.

[email protected]


Questions?

Presenters


Stephen Walls, P.E.

Senior Engineer

Jeremy Sell, P.E.


Becca Crumpler, E.I.T,

Associate Engineer

Date post:	29-Jan-2021
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