Vol. 79 Monday, 

No. 125 June 30, 2014 

Part II 

Environmental Protection Agency 

40 CFR Parts 60 and 63 

Petroleum Refinery Sector Risk and Technology Review and New Source 

Performance Standards; Proposed Rule 


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36880 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2010–0682; FRL–9720–4] 

RIN 2060–AQ75 

Petroleum Refinery Sector Risk and 

Technology Review and New Source 

Performance Standards 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: This action proposes 

amendments to the national emission 

standards for hazardous air pollutants 

for petroleum refineries to address the 

risk remaining after application of the 

standards promulgated in 1995 and 

2002. This action also proposes 

amendments to the national emission 

standards for hazardous air pollutants 

for petroleum refineries based on the 

results of the Environmental Protection 

Agency (EPA) review of developments 

in practices, processes and control 

technologies and includes new 

monitoring, recordkeeping and 

reporting requirements. The EPA is also 

proposing new requirements related to 

emissions during periods of startup, 

shutdown and malfunction to ensure 

that the standards are consistent with 

court opinions issued since 

promulgation of the standards. This 

action also proposes technical 

corrections and clarifications for new 

source performance standards for 

petroleum refineries to improve 

consistency and clarity and address 

issues raised after the 2008 rule 

promulgation. Implementation of this 

proposed rule will result in projected 

reductions of 1,760 tons per year (tpy) 

of hazardous air pollutants (HAP), 

which will reduce cancer risk and 

chronic health effects. 

DATES:

Comments. Comments must be 

received on or before August 29, 2014. 

A copy of comments on the information 

collection provisions should be 

submitted to the Office of Management 

and Budget (OMB) on or before July 30, 

2014. 

Public Hearing. The EPA will hold 

public hearings on this proposed rule on 

July 16, 2014, at Banning’s Landing 

Community Center, 100 E. Water Street, 

Wilmington, California 90744, and on 

August 5, 2014, at the Alvin D. Baggett 

Recreation Building 1302 Keene Street 

in Galena Park, Texas, 77547. 

ADDRESSES:

Comments. Submit your comments, 

identified by Docket ID Number EPA– 

HQ–OAR–2010–0682, by one of the 

following methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• Email: a-and-r-docket@epa.gov. 

Attention Docket ID Number EPA–HQ– 

OAR–2010–0682. 

• Fax: (202) 566–9744. Attention 

Docket ID Number EPA–HQ–OAR– 

2010–0682. 

• Mail: U.S. Postal Service, send 

comments to: EPA Docket Center, 

William Jefferson Clinton (WJC) West 

Building (Air Docket), Attention Docket 

ID Number EPA–HQ–OAR–2010–0682, 

U.S. Environmental Protection Agency, 

Mailcode: 28221T, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460. 

Please include a total of two copies. In 

addition, please mail a copy of your 

comments on the information collection 

provisions to the Office of Information 

and Regulatory Affairs, Office of 

Management and Budget (OMB), Attn: 

Desk Officer for EPA, 725 17th Street 

NW., Washington, DC 20503. 

• Hand Delivery: U.S. Environmental 

Protection Agency, WJC West Building 

(Air Docket), Room 3334, 1301 

Constitution Ave. NW., Washington, DC 

20004. Attention Docket ID Number 

EPA–HQ–OAR–2010–0682. Such 

deliveries are only accepted during the 

Docket’s normal hours of operation, and 

special arrangements should be made 

for deliveries of boxed information. 

Instructions. Direct your comments to 

Docket ID Number EPA–HQ–OAR– 

2010–0682. The EPA’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available online at 

http://www.regulations.gov, including 

any personal information provided, 

unless the comment includes 

information claimed to be confidential 

business information (CBI) or other 

information whose disclosure is 

restricted by statute. Do not submit 

information that you consider to be CBI 

or otherwise protected through http://

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should not include 

special characters or any form of 

encryption and be free of any defects or 

viruses. For additional information 

about the EPA’s public docket, visit the 

EPA Docket Center homepage at: 

http://www.epa.gov/dockets. 

Docket. The EPA has established a 

docket for this rulemaking under Docket 

ID Number EPA–HQ–OAR–2010–0682. 

All documents in the docket are listed 

in the regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy. 

Publicly available docket materials are 

available either electronically in 

regulations.gov or in hard copy at the 

EPA Docket Center, WJC West Building, 

Room 3334, 1301 Constitution Ave. 

NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the EPA Docket Center is 

(202) 566–1742. 

Public Hearing. The public hearing 

will be held in Wilmington, California 

on July 16, 2014 at Banning’s Landing 

Community Center, 100 E. Water Street, 

Wilmington, California 90744. The 

hearing will convene at 9 a.m. and end 

at 8 p.m. A lunch break will be held 

from 1 p.m. until 2 p.m. A dinner break 

will be held from 5 p.m. until 6 p.m. 

The public hearing in Galena Park, 

Texas will be held on August 5, 2014, 

at the Alvin D. Baggett Recreation 

Building 1302 Keene Street Galena Park, 

Texas 77547. The hearing will convene 

at 9 a.m. and will end at 8 p.m. A lunch 

break will be held from noon until 1 

p.m. A dinner break will be held from 

5 p.m. until 6 p.m. Please contact Ms. 

Virginia Hunt at (919) 541–0832 or at 

hunt.virginia@epa.gov to register to 

speak at the hearing. The last day to preregister in advance to speak at the 

hearing is July 11, 2014, for the 

Wilmington, California hearing and 

August 1, 2014, for the Galena Park, 

Texas hearing. Additionally, requests to 

speak will be taken the day of the 

hearing at the hearing registration desk, 

although preferences on speaking times 

may not be able to be fulfilled. If you 

require the service of a translator or 


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special accommodations such as audio 

description, please let us know at the 

time of registration. 

FOR FURTHER INFORMATION CONTACT: For 

questions about this proposed action, 

contact Ms. Brenda Shine, Sector 

Policies and Programs Division (E143– 

01), Office of Air Quality Planning and 

Standards (OAQPS), U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; telephone number: (919) 541– 

3608; fax number: (919) 541–0246; and 

email address: shine.brenda@epa.gov. 

For specific information regarding the 

risk modeling methodology, contact Mr. 

Ted Palma, Health and Environmental 

Impacts Division (C539–02), Office of 

Air Quality Planning and Standards 

(OAQPS), U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; telephone 

number: (919) 541–5470; fax number: 

(919) 541–0840; and email address: 

palma.ted@epa.gov. For information 

about the applicability of the National 

Emissions Standards for Hazardous Air 

Pollutants (NESHAP) or the New Source 

Performance Standards (NSPS) to a 

particular entity, contact Maria Malave, 

Office of Enforcement and Compliance 

Assurance (OECA), telephone number: 

(202) 564–7027; fax number: (202) 564– 

0050; and email address: 

malave.maria@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Preamble Acronyms and Abbreviations 

We use multiple acronyms and terms 

in this preamble. While this list may not 

be exhaustive, to ease the reading of this 

preamble and for reference purposes, 

the EPA defines the following terms and 

acronyms here: 

10/25 tpy emissions equal to or greater than 

10 tons per year of a single pollutant or 25 

tons per year of cumulative pollutants 

ACGIH American Conference of 

Governmental Industrial Hygienists 

ADAF age-dependent adjustment factors 

AEGL acute exposure guideline levels 

AERMOD air dispersion model used by the 

HEM–3 model 

APCD air pollution control devices 

API American Petroleum Institute 

BDT best demonstrated technology 

BLD bag leak detectors 

BSER best system of emission reduction 

Btu/ft2 British thermal units per square foot 

Btu/scf British thermal units per standard 

cubic foot 

CAA Clean Air Act 

CalEPA California EPA 

CBI confidential business information 

CCU catalytic cracking units 

Ccz combustion zone combustibles 

concentration 

CDDF chlorinated dibenzodioxins and 

furans 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data 

Reporting Interface 

CEMS continuous emissions monitoring 

system 

CFR Code of Federal Regulations 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e carbon dioxide equivalents 

COMS continuous opacity monitoring 

system 

COS carbonyl sulfide 

CPMS continuous parameter monitoring 

system 

CRU catalytic reforming units 

CS2 carbon disulfide 

DCU delayed coking units 

DIAL differential absorption light detection 

and ranging 

EBU enhanced biological unit 

EPA Environmental Protection Agency 

ERPG emergency response planning 

guidelines 

ERT Electronic Reporting Tool 

ESP electrostatic precipitator 

FCCU fluid catalytic cracking units 

FGCD fuel gas combustion devices 

FR Federal Register 

FTIR Fourier transform infrared 

spectroscopy 

g PM/kg grams particulate matter per 

kilogram 

GC gas chromatograph 

GHG greenhouse gases 

GPS global positioning system 

H2S hydrogen sulfide 

HAP hazardous air pollutants 

HCl hydrogen chloride 

HCN hydrogen cyanide 

HEM–3 Human Exposure Model, Version 

1.1.0 

HF hydrogen fluoride 

HFC highest fenceline concentration 

HI hazard index 

HQ hazard quotient 

ICR Information Collection Request 

IRIS Integrated Risk Information System 

km kilometers 

lb/day pounds per day 

LDAR leak detection and repair 

LFL lower flammability limit 

LFLcz combustion zone lower flammability 

limit 

LMC lowest measured concentration 

LOAEL lowest-observed-adverse-effect level 

LTD long tons per day 

MACT maximum achievable control 

technology 

mg/kg-day milligrams per kilogram per day 

mg/L milligrams per liter 

mg/m3 milligrams per cubic meter 

Mg/yr megagrams per year 

MFC measured fenceline concentration 

MFR momentum flux ratio 

MIR maximum individual risk 

mph miles per hour 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industry 

Classification System 

NAS National Academy of Sciences 

NATA National Air Toxics Assessment 

NEI National Emissions Inventory 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NFS near-field interfering source 

NHVcz combustion zone net heating value 

Ni nickel 

NIOSH National Institutes for Occupational 

Safety and Health 

NOAEL no-observed-adverse-effect level 

NOX nitrogen oxides 

NRC National Research Council 

NRDC Natural Resources Defense Council 

NSPS new source performance standards 

NTTAA National Technology Transfer and 

Advancement Act 

OAQPS Office of Air Quality Planning and 

Standards 

OECA Office of Enforcement and 

Compliance Assurance 

OMB Office of Management and Budget 

OSC off-site source contribution 

OTM other test method 

PAH polycyclic aromatic hydrocarbons 

PB–HAP hazardous air pollutants known to 

be persistent and bio-accumulative in the 

environment 

PBT persistent, bioaccumulative, and toxic 

PCB polychlorinated biphenyls 

PEL probable effect level 

PM particulate matter 

PM2.5 particulate matter 2.5 micrometers in 

diameter and smaller 

POM polycyclic organic matter 

ppm parts per million 

ppmv parts per million by volume 

ppmw parts per million by weight 

psia pounds per square inch absolute 

psig pounds per square inch gauge 

REL reference exposure level 

REM Model Refinery Emissions Model 

RFA Regulatory Flexibility Act 

RfC reference concentration 

RfD reference dose 

RTR residual risk and technology review 

SAB Science Advisory Board 

SBA Small Business Administration 

SBAR Small Business Advocacy Review 

SCR selective catalytic reduction 

SISNOSE significant economic impact on a 

substantial number of small entities 

S/L/Ts state, local and tribal air pollution 

control agencies 

SO2 sulfur dioxide 

SRU sulfur recovery unit 

SSM startup, shutdown and malfunction 

STEL short-term exposure limit 

TEQ toxicity equivalent 

TLV threshold limit value 

TOC total organic carbon 

TOSHI target organ-specific hazard index 

tpy tons per year 

TRIM.FaTE Total Risk Integrated 

Methodology.Fate, Transport, and 

Ecological Exposure model 

UB uniform background 

UF uncertainty factor 

UMRA Unfunded Mandates Reform Act 

URE unit risk estimate 

UV–DOAS ultraviolet differential optical 

absorption spectroscopy 

VCS voluntary consensus standards 

VOC volatile organic compounds 

WJC William Jefferson Clinton 

°F degrees Fahrenheit 

DC the concentration difference between 

the highest measured concentration and 

the lowest measured concentration 

mg/m3 micrograms per cubic meter 

The EPA also defines the following 

abbreviations for regulations cited 

within this preamble: 


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AWP Alternative Work Practice To Detect 

Leaks From Equipment (40 CFR 63.11(c), 

(d) and (e)) 

Benzene NESHAP National Emission 

Standards for Hazardous Air Pollutants: 

Benzene Emissions from Maleic Anhydride 

Plants, Ethylbenzene/Styrene Plants, 

Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product 

Recovery Plants (40 CFR part 61, subpart 

L as of publication in the Federal Register 

at 54 FR 38044, September 14, 1989) 

BWON National Emission Standard for 

Benzene Waste Operations (40 CFR part 61, 

subpart FF) 

Generic MACT National Emission 

Standards for Storage Vessels (40 CFR part 

63, subpart WW) 

HON National Emission Standards for 

Organic Hazardous Air Pollutants (40 CFR 

part 63, subparts F, G and H) 

Marine Vessel MACT National Emission 

Standards for Marine Tank Vessel Loading 

Operations (40 CFR part 63, subpart Y) 

Refinery MACT 1 National Emission 

Standards for Hazardous Air Pollutants 

From Petroleum Refineries (40 CFR part 

63, subpart CC) 

Refinery MACT 2 National Emission 

Standards for Hazardous Air Pollutants for 

Petroleum Refineries: Catalytic Cracking 

Units, Catalytic Reforming Units, and 

Sulfur Recovery Units (40 CFR part 63, 

subpart UUU) 

Refinery NSPS J Standards of Performance 

for Petroleum Refineries (40 CFR part 60, 

subpart J) 

Refinery NSPS Ja Standards of Performance 

for Petroleum Refineries for which 

Construction, Reconstruction, or 

Modification Commenced After May 14, 

2007 (40 CFR part 60, subpart Ja) 

Organization of This Document. The 

information in this preamble is 

organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this document 

and other related information? 

C. What should I consider as I prepare my 

comments for the EPA? 

D. Public Hearing 

II. Background 

A. What is the statutory authority for this 

action? 

B. What are the source categories and how 

do the NESHAP and NSPS regulate 

emissions? 

C. What data collection activities were 

conducted to support this action? 

D. What other relevant background 

information and data are available? 

III. Analytical Procedures 

A. How did we estimate post-MACT risks 

posed by the source categories? 

B. How did we consider the risk results in 

making decisions for this proposal? 

C. How did we perform the technology 

review? 

IV. Analytical Results and Proposed 

Decisions 

A. What actions are we taking pursuant to 

CAA sections 112(d)(2) and 112(d)(3)? 

B. What are the results and proposed 

decisions based on our technology 

review? 

C. What are the results of the risk 

assessment and analyses? 

D. What are our proposed decisions 

regarding risk acceptability, ample 

margin of safety and adverse 

environmental effects? 

E. What other actions are we proposing? 

F. What compliance dates are we 

proposing? 

V. Summary of Cost, Environmental and 

Economic Impacts 

A. What are the affected sources, the air 

quality impacts and cost impacts? 

B. What are the economic impacts? 

C. What are the benefits? 

VI. Request for Comments 

VII. Submitting Data Corrections 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

A redline version of the regulatory 

language that incorporates the proposed 

changes in this action is available in the 

docket for this action (Docket ID No. 

EPA–HQ–OAR–2010–0682). 

I. General Information 

A. Does this action apply to me? 

Table 1 of this preamble lists the 

industries that are the subject of this 

proposal. Table 1 is not intended to be 

exhaustive but rather to provide a guide 

for readers regarding the entities that 

this proposed action is likely to affect. 

These proposed standards, once 

promulgated, will be directly applicable 

to the affected sources. Thus, federal, 

state, local and tribal government 

entities would not be affected by this 

proposed action. As defined in the 

‘‘Initial List of Categories of Sources 

Under Section 112(c)(1) of the Clean Air 

Act Amendments of 1990’’ (see 57 FR 

31576, July 16, 1992), the ‘‘Petroleum 

Refineries—Catalytic Cracking (Fluid 

and other) Units, Catalytic Reforming 

Units, and Sulfur Plant Units’’ source 

category and the ‘‘Petroleum 

Refineries—Other Sources Not 

Distinctly Listed’’ both consist of any 

facility engaged in producing gasoline, 

naphthas, kerosene, jet fuels, distillate 

fuel oils, residual fuel oils, lubricants, or 

other products from crude oil or 

unfinished petroleum derivatives. The 

first of these source categories includes 

process vents associated with the 

following refinery process units: 

Catalytic cracking (fluid and other) 

units, catalytic reforming units and 

sulfur plant units. The second source 

category includes all emission sources 

associated with refinery process units 

except the process vents listed in the 

Petroleum Refineries—Catalytic 

Cracking (Fluid and Other) Units, 

Catalytic Reforming Units, and Sulfur 

Plant Units Source Category. The 

emission sources included in this 

source category include, but are not 

limited to, miscellaneous process vents 

(vents other than those listed in 

Petroleum Refineries—Catalytic 

Cracking (Fluid and Other) Units, 

Catalytic Reforming Units, and Sulfur 

Plant Units Source Category), 

equipment leaks, storage vessels, 

wastewater, gasoline loading, marine 

vessel loading, and heat exchange 

systems. 

TABLE 1—INDUSTRIES AFFECTED BY THIS PROPOSED ACTION

Industry NAICSa

Code Examples of regulated entities 

Petroleum Refining Industry ...................... 324110 Petroleum refinery sources that are subject to 40 CFR part 60, subpart J and Ja and 

40 CFR part 63, subparts CC and UUU. 

a North American Industry Classification System. 


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B. Where can I get a copy of this 

document and other related 

information? 

Following signature by the EPA 

Administrator, the EPA will post a copy 

of this proposed action at: http://

www.epa.gov/ttn/atw/petref.html. 

Following publication in the Federal 

Register, the EPA will post the Federal 

Register version of the proposal and key 

technical documents at the Web site. 

Information on the overall residual risk 

and technology review (RTR) program is 

available at the following Web site: 

http://www.epa.gov/ttn/atw/rrisk/

rtrpg.html. 

C. What should I consider as I prepare 

my comments for the EPA? 

Submitting CBI. Do not submit 

information containing CBI to the EPA 

through http://www.regulations.gov or 

email. Clearly mark the part or all of the 

information that you claim to be CBI. 

For CBI information on a disk or CD– 

ROM that you mail to the EPA, mark the 

outside of the disk or CD–ROM as CBI 

and then identify electronically within 

the disk or CD–ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comments that includes information 

claimed as CBI, you must submit a copy 

of the comments that does not contain 

the information claimed as CBI for 

inclusion in the public docket. If you 

submit a CD–ROM or disk that does not 

contain CBI, mark the outside of the 

disk or CD–ROM clearly that it does not 

contain CBI. Information not marked as 

CBI will be included in the public 

docket and the EPA’s electronic public 

docket without prior notice. Information 

marked as CBI will not be disclosed 

except in accordance with procedures 

set forth in 40 Code of Federal 

Regulations (CFR) part 2. Send or 

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), OAQPS, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention Docket ID Number 

EPA–HQ–OAR–2010–0682. 

D. Public Hearing 

The hearing will provide interested 

parties the opportunity to present data, 

views or arguments concerning the 

proposed action. The EPA will make 

every effort to accommodate all speakers 

who arrive and register. The EPA may 

ask clarifying questions during the oral 

presentations but will not respond to 

the presentations at that time. Written 

statements and supporting information 

submitted during the comment period 

will be considered with the same weight 

as oral comments and supporting 

information presented at the public 

hearing. Written comments on the 

proposed rule must be postmarked by 

August 29, 2014. Commenters should 

notify Ms. Virginia Hunt if they will 

need specific equipment, or if there are 

other special needs related to providing 

comments at the hearing. Oral testimony 

will be limited to 5 minutes for each 

commenter. The EPA encourages 

commenters to provide the EPA with a 

copy of their oral testimony 

electronically (via email or CD) or in 

hard copy form. Verbatim transcripts of 

the hearings and written statements will 

be included in the docket for the 

rulemaking. The EPA will make every 

effort to follow the schedule as closely 

as possible on the day of the hearing; 

however, please plan for the hearing to 

run either ahead of schedule or behind 

schedule. Information regarding the 

hearing will be available at: http://

www.epa.gov/ttnatw01/petrefine/

petrefpg.html. 

II. Background 

A. What is the statutory authority for 

this action? 

1. NESHAP 

Section 112 of the Clean Air Act 

(CAA) establishes a two-stage regulatory 

process to address emissions of HAP 

from stationary sources. In the first 

stage, after the EPA has identified 

categories of sources emitting one or 

more of the HAP listed in CAA section 

112(b), CAA section 112(d) requires us 

to promulgate technology-based 

national emissions standards for 

hazardous air pollutants (NESHAP) for 

those sources. ‘‘Major sources’’ are those 

that emit or have the potential to emit 

10 tpy or more of a single HAP or 25 tpy 

or more of any combination of HAP. For 

major sources, the technology-based 

NESHAP must reflect the maximum 

degree of emissions reductions of HAP 

achievable (after considering cost, 

energy requirements and non-air quality 

health and environmental impacts) and 

are commonly referred to as maximum 

achievable control technology (MACT) 

standards. 

MACT standards must reflect the 

maximum degree of emissions reduction 

achievable through the application of 

measures, processes, methods, systems 

or techniques, including, but not limited 

to, measures that (1) reduce the volume 

of or eliminate pollutants through 

process changes, substitution of 

materials or other modifications; (2) 

enclose systems or processes to 

eliminate emissions; (3) capture or treat 

pollutants when released from a 

process, stack, storage or fugitive 

emissions point; (4) are design, 

equipment, work practice or operational 

standards (including requirements for 

operator training or certification); or (5) 

are a combination of the above. CAA 

section 112(d)(2)(A)–(E). The MACT 

standards may take the form of design, 

equipment, work practice or operational 

standards where the EPA first 

determines either that (1) a pollutant 

cannot be emitted through a conveyance 

designed and constructed to emit or 

capture the pollutant, or that any 

requirement for, or use of, such a 

conveyance would be inconsistent with 

law; or (2) the application of 

measurement methodology to a 

particular class of sources is not 

practicable due to technological and 

economic limitations. CAA section 

112(h)(1)–(2). 

The MACT ‘‘floor’’ is the minimum 

control level allowed for MACT 

standards promulgated under CAA 

section 112(d)(3) and may not be based 

on cost considerations. For new sources, 

the MACT floor cannot be less stringent 

than the emissions control that is 

achieved in practice by the bestcontrolled similar source. The MACT 

floor for existing sources can be less 

stringent than floors for new sources but 

not less stringent than the average 

emissions limitation achieved by the 

best-performing 12 percent of existing 

sources in the category or subcategory 

(or the best-performing five sources for 

categories or subcategories with fewer 

than 30 sources). In developing MACT 

standards, the EPA must also consider 

control options that are more stringent 

than the floor. We may establish 

standards more stringent than the floor 

based on considerations of the cost of 

achieving the emission reductions, any 

non-air quality health and 

environmental impacts and energy 

requirements. 

The EPA is then required to review 

these technology-based standards and 

revise them ‘‘as necessary (taking into 

account developments in practices, 

processes, and control technologies)’’ no 

less frequently than every eight years. 

CAA section 112(d)(6). In conducting 

this review, the EPA is not required to 

recalculate the MACT floor. Natural 

Resources Defense Council (NRDC) v. 

EPA, 529 F.3d 1077, 1084 (D.C. Cir. 

2008). Association of Battery Recyclers, 

Inc. v. EPA, 716 F.3d 667 (D.C. Cir. 

2013). 

The second stage in standard-setting 

focuses on reducing any remaining (i.e., 

‘‘residual’’) risk according to CAA 

section 112(f). Section 112(f)(1) required 

that the EPA by November 1996 prepare 

a report to Congress discussing (among 


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other things) methods of calculating the 

risks posed (or potentially posed) by 

sources after implementation of the 

MACT standards, the public health 

significance of those risks and the EPA’s 

recommendations as to legislation 

regarding such remaining risk. The EPA 

prepared and submitted the Residual 

Risk Report to Congress, EPA–453/R– 

99–001 (Risk Report) in March 1999. 

CAA section 112(f)(2) then provides that 

if Congress does not act on any 

recommendation in the Risk Report, the 

EPA must analyze and address residual 

risk for each category or subcategory of 

sources 8 years after promulgation of 

such standards pursuant to CAA section 

112(d). 

Section 112(f)(2) of the CAA requires 

the EPA to determine for source 

categories subject to MACT standards 

whether the emission standards provide 

an ample margin of safety to protect 

public health. Section 112(f)(2)(B) of the 

CAA expressly preserves the EPA’s use 

of the two-step process for developing 

standards to address any residual risk 

and the agency’s interpretation of 

‘‘ample margin of safety’’ developed in 

the National Emissions Standards for 

Hazardous Air Pollutants: Benzene 

Emissions from Maleic Anhydride 

Plants, Ethylbenzene/Styrene Plants, 

Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product 

Recovery Plants (Benzene NESHAP) (54 

FR 38044, September 14, 1989). The 

EPA notified Congress in the Risk 

Report that the agency intended to use 

the Benzene NESHAP approach in 

making CAA section 112(f) residual risk 

determinations (EPA–453/R–99–001, p. 

ES–11). The EPA subsequently adopted 

this approach in its residual risk 

determinations and in a challenge to the 

risk review for the Synthetic Organic 

Chemical Manufacturing source 

category, the United States Court of 

Appeals for the District of Columbia 

Circuit upheld as reasonable the EPA’s 

interpretation that subsection 112(f)(2) 

incorporates the standards established 

in the Benzene NESHAP. See NRDC v. 

EPA, 529 F.3d 1077, 1083 (D.C. Cir. 

2008) (‘‘[S]ubsection 112(f)(2)(B) 

expressly incorporates the EPA’s 

interpretation of the Clean Air Act from 

the Benzene standard, complete with a 

citation to the Federal Register.’’); see 

also A Legislative History of the Clean 

Air Act Amendments of 1990, vol. 1, p. 

877 (Senate debate on Conference 

Report). 

The first step in the process of 

evaluating residual risk is the 

determination of acceptable risk. If risks 

are unacceptable, the EPA cannot 

consider cost in identifying the 

emissions standards necessary to bring 

risks to an acceptable level. The second 

step is the determination of whether 

standards must be further revised in 

order to provide an ample margin of 

safety to protect public health. The 

ample margin of safety is the level at 

which the standards must be set, unless 

an even more stringent standard is 

necessary to prevent, taking into 

consideration costs, energy, safety and 

other relevant factors, an adverse 

environmental effect. 

a. Step 1—Determining Acceptability 

The agency in the Benzene NESHAP 

concluded ‘‘that the acceptability of risk 

under section 112 is best judged on the 

basis of a broad set of health risk 

measures and information’’ and that the 

‘‘judgment on acceptability cannot be 

reduced to any single factor.’’ Id. at 

38046. The determination of what 

represents an ‘‘acceptable’’ risk is based 

on a judgment of ‘‘what risks are 

acceptable in the world in which we 

live’’ (Risk Report at 178, quoting NRDC 

v. EPA, 824 F. 2d 1146, 1165 (D.C. Cir. 

1987) (en banc) (‘‘Vinyl Chloride’’), 

recognizing that our world is not riskfree. 

In the Benzene NESHAP, we stated 

that ‘‘EPA will generally presume that if 

the risk to [the maximum exposed] 

individual is no higher than 

approximately one in 10 thousand, that 

risk level is considered acceptable.’’ 54 

FR at 38045, September 14, 1989. We 

discussed the maximum individual 

lifetime cancer risk (or maximum 

individual risk (MIR)) as being ‘‘the 

estimated risk that a person living near 

a plant would have if he or she were 

exposed to the maximum pollutant 

concentrations for 70 years.’’ Id. We 

explained that this measure of risk ‘‘is 

an estimate of the upper bound of risk 

based on conservative assumptions, 

such as continuous exposure for 24 

hours per day for 70 years.’’ Id. We 

acknowledged that maximum 

individual lifetime cancer risk ‘‘does not 

necessarily reflect the true risk, but 

displays a conservative risk level which 

is an upper-bound that is unlikely to be 

exceeded.’’ Id. 

Understanding that there are both 

benefits and limitations to using the 

MIR as a metric for determining 

acceptability, we acknowledged in the 

Benzene NESHAP that ‘‘consideration of 

maximum individual risk * * * must 

take into account the strengths and 

weaknesses of this measure of risk.’’ Id. 

Consequently, the presumptive risk 

level of 100-in-1 million (1-in-10 

thousand) provides a benchmark for 

judging the acceptability of maximum 

individual lifetime cancer risk, but does 

not constitute a rigid line for making 

that determination. Further, in the 

Benzene NESHAP, we noted that: 

[p]articular attention will also be accorded to 

the weight of evidence presented in the risk 

assessment of potential carcinogenicity or 

other health effects of a pollutant. While the 

same numerical risk may be estimated for an 

exposure to a pollutant judged to be a known 

human carcinogen, and to a pollutant 

considered a possible human carcinogen 

based on limited animal test data, the same 

weight cannot be accorded to both estimates. 

In considering the potential public health 

effects of the two pollutants, the Agency’s 

judgment on acceptability, including the 

MIR, will be influenced by the greater weight 

of evidence for the known human 

carcinogen. 

Id. at 38046. The agency also explained 

in the Benzene NESHAP that: 

[i]n establishing a presumption for MIR, 

rather than a rigid line for acceptability, the 

Agency intends to weigh it with a series of 

other health measures and factors. These 

include the overall incidence of cancer or 

other serious health effects within the 

exposed population, the numbers of persons 

exposed within each individual lifetime risk 

range and associated incidence within, 

typically, a 50 km exposure radius around 

facilities, the science policy assumptions and 

estimation uncertainties associated with the 

risk measures, weight of the scientific 

evidence for human health effects, other 

quantified or unquantified health effects, 

effects due to co-location of facilities, and coemission of pollutants. 

Id. at 38045. In some cases, these health 

measures and factors taken together may 

provide a more realistic description of 

the magnitude of risk in the exposed 

population than that provided by 

maximum individual lifetime cancer 

risk alone. 

As noted earlier, in NRDC v. EPA, the 

court held that section 112(f)(2) 

‘‘incorporates the EPA’s interpretation 

of the Clean Air Act from the Benzene 

Standard.’’ The court further held that 

Congress’ incorporation of the Benzene 

standard applies equally to carcinogens 

and non-carcinogens. 529 F.3d at 1081– 

82. Accordingly, we also consider noncancer risk metrics in our determination 

of risk acceptability and ample margin 

of safety. 

b. Step 2—Determination of Ample 

Margin of Safety 

CAA section 112(f)(2) requires the 

EPA to determine, for source categories 

subject to MACT standards, whether 

those standards provide an ample 

margin of safety to protect public health. 

As explained in the Benzene NESHAP, 

‘‘the second step of the inquiry, 

determining an ‘ample margin of safety,’ 

again includes consideration of all of 

the health factors, and whether to 

reduce the risks even further. . . . 


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1 ‘‘Adverse environmental effect’’ is defined as 

any significant and widespread adverse effect, 

which may be reasonably anticipated to wildlife, 

aquatic life or natural resources, including adverse 

impacts on populations of endangered or threatened 

species or significant degradation of environmental 

qualities over broad areas. CAA section 112(a)(7). 

2Specific statutory and regulatory provisions 

define what constitutes a modification or 

reconstruction of a facility. 40 CFR 60.14 provides 

that an existing facility is modified and, therefore, 

subject to an NSPS, if it undergoes ‘‘any physical 

change in the method of operation . . . which 

increases the amount of any air pollutant emitted 

by such source or which results in the emission of 

any air pollutant not previously emitted.’’ 40 CFR 

60.15, in turn, provides that a facility is 

reconstructed if components are replaced at an 

existing facility to such an extent that the capital 

cost of the new equipment/components exceed 50 

percent of what is believed to be the cost of a 

completely new facility. 

Beyond that information, additional 

factors relating to the appropriate level 

of control will also be considered, 

including costs and economic impacts 

of controls, technological feasibility, 

uncertainties and any other relevant 

factors. Considering all of these factors, 

the agency will establish the standard at 

a level that provides an ample margin of 

safety to protect the public health, as 

required by section 112.’’ 54 FR at 

38046, September 14, 1989. 

According to CAA section 

112(f)(2)(A), if the MACT standards for 

HAP ‘‘classified as a known, probable, 

or possible human carcinogen do not 

reduce lifetime excess cancer risks to 

the individual most exposed to 

emissions from a source in the category 

or subcategory to less than one in one 

million,’’ the EPA must promulgate 

residual risk standards for the source 

category (or subcategory), as necessary 

to provide an ample margin of safety to 

protect public health. In doing so, the 

EPA may adopt standards equal to 

existing MACT standards if the EPA 

determines that the existing standards 

(i.e., the MACT standards) are 

sufficiently protective. NRDC v. EPA, 

529 F.3d 1077, 1083 (D.C. Cir. 2008) (‘‘If 

EPA determines that the existing 

technology-based standards provide an 

‘ample margin of safety,’ then the 

Agency is free to readopt those 

standards during the residual risk 

rulemaking.’’) The EPA must also adopt 

more stringent standards, if necessary, 

to prevent an adverse environmental 

effect,1 but must consider cost, energy, 

safety and other relevant factors in 

doing so. 

The CAA does not specifically define 

the terms ‘‘individual most exposed,’’ 

‘‘acceptable level’’ and ‘‘ample margin 

of safety.’’ In the Benzene NESHAP, 54 

FR at 38044–38045, September 14, 1989, 

we stated as an overall objective: 

In protecting public health with an ample 

margin of safety under section 112, EPA 

strives to provide maximum feasible 

protection against risks to health from 

hazardous air pollutants by (1) protecting the 

greatest number of persons possible to an 

individual lifetime risk level no higher than 

approximately 1-in-1 million and (2) limiting 

to no higher than approximately 1-in-10 

thousand [i.e., 100-in-1 million] the 

estimated risk that a person living near a 

plant would have if he or she were exposed 

to the maximum pollutant concentrations for 

70 years. 

The agency further stated that ‘‘[t]he 

EPA also considers incidence (the 

number of persons estimated to suffer 

cancer or other serious health effects as 

a result of exposure to a pollutant) to be 

an important measure of the health risk 

to the exposed population. Incidence 

measures the extent of health risks to 

the exposed population as a whole, by 

providing an estimate of the occurrence 

of cancer or other serious health effects 

in the exposed population.’’ Id. at 

38045. 

In the ample margin of safety decision 

process, the agency again considers all 

of the health risks and other health 

information considered in the first step, 

including the incremental risk reduction 

associated with standards more 

stringent than the MACT standard or a 

more stringent standard that EPA has 

determined is necessary to ensure risk is 

acceptable. In the ample margin of 

safety analysis, the agency considers 

additional factors, including costs and 

economic impacts of controls, 

technological feasibility, uncertainties 

and any other relevant factors. 

Considering all of these factors, the 

agency will establish the standard ‘‘at a 

level that provides an ample margin of 

safety to protect the public health,’’ as 

required by CAA section 112(f). 54 FR 

38046, September 14, 1989. 

2. NSPS 

Section 111 of the CAA establishes 

mechanisms for controlling emissions of 

air pollutants from stationary sources. 

Section 111(b) of the CAA provides 

authority for the EPA to promulgate new 

source performance standards (NSPS) 

which apply only to newly constructed, 

reconstructed and modified sources. 

Once the EPA has elected to set NSPS 

for new and modified sources in a given 

source category, CAA section 111(d) 

calls for regulation of existing sources, 

with certain exceptions explained 

below. 

Specifically, section 111(b) of the 

CAA requires the EPA to establish 

emission standards for any category of 

new and modified stationary sources 

that the Administrator, in his or her 

judgment, finds ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ The EPA has 

previously made endangerment findings 

under this section of the CAA for more 

than 60 stationary source categories and 

subcategories that are now subject to 

NSPS. 

Section 111 of the CAA gives the EPA 

significant discretion to identify the 

affected facilities within a source 

category that should be regulated. To 

define the affected facilities, the EPA 

can use size thresholds for regulation 

and create subcategories based on 

source type, class or size. Emission 

limits also may be established either for 

equipment within a facility or for an 

entire facility. For listed source 

categories, the EPA must establish 

‘‘standards of performance’’ that apply 

to sources that are constructed, 

modified or reconstructed after the EPA 

proposes the NSPS for the relevant 

source category.2

The EPA also has significant 

discretion to determine the appropriate 

level for the standards. Section 111(a)(1) 

of the CAA provides that NSPS are to 

‘‘reflect the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any non-air quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated.’’ This level of control is 

commonly referred to as best 

demonstrated technology (BDT) or the 

best system of emission reduction 

(BSER). The standard that the EPA 

develops, based on the BSER achievable 

at that source, is commonly a numerical 

emission limit, expressed as a 

performance level (i.e., a rate-based 

standard). Generally, the EPA does not 

prescribe a particular technological 

system that must be used to comply 

with a NSPS. Rather, sources remain 

free to elect whatever combination of 

measures will achieve equivalent or 

greater control of emissions. 

Costs are also considered in 

evaluating the appropriate standard of 

performance for each category or 

subcategory. The EPA generally 

compares control options and estimated 

costs and emission impacts of multiple, 

specific emission standard options 

under consideration. As part of this 

analysis, the EPA considers numerous 

factors relating to the potential cost of 

the regulation, including industry 

organization and market structure, 

control options available to reduce 

emissions of the regulated pollutant(s) 

and costs of these controls. 


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B. What are the source categories and 

how do the NESHAP and NSPS regulate 

emissions? 

The source categories include 

petroleum refineries engaged in 

converting crude oil into refined 

products, including liquefied petroleum 

gas, gasoline, kerosene, aviation fuel, 

diesel fuel, fuel oils, lubricating oils and 

feedstocks for the petrochemical 

industry. Petroleum refinery activities 

start with the receipt of crude oil for 

storage at the refinery, include all 

petroleum handling and refining 

operations, and terminate with loading 

of refined products into pipelines, tank 

or rail cars, tank trucks, or ships or 

barges that take products from the 

refinery to distribution centers. 

Petroleum refinery-specific process 

units include fluid catalytic cracking 

units (FCCU) and catalytic reforming 

units (CRU), as well as units and 

processes found at many types of 

manufacturing facilities (including 

petroleum refineries), such as storage 

vessels and wastewater treatment 

plants. HAP emitted by this industry 

include organics (e.g., acetaldehyde, 

benzene, formaldehyde, hexane, phenol, 

naphthalene, 2-methylnaphthalene, 

dioxins, furans, ethyl benzene, toluene 

and xylene); reduced sulfur compounds 

(i.e., carbonyl sulfide (COS), carbon 

disulfide (CS2)); inorganics (e.g., 

hydrogen chloride (HCl), hydrogen 

cyanide (HCN), chlorine, hydrogen 

fluoride (HF)); and metals (e.g., 

antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, mercury, 

manganese and nickel). Criteria 

pollutants and other non-hazardous air 

pollutants that are also emitted include 

nitrogen oxides (NOX), particulate 

matter (PM), sulfur dioxide (SO2), 

volatile organic compounds (VOC), 

carbon monoxide (CO), greenhouse 

gases (GHG), and total reduced sulfur. 

The federal emission standards that 

are the primary subject of this proposed 

rulemaking are: 

• National Emission Standards for 

Hazardous Air Pollutants from 

Petroleum Refineries (40 CFR part 63, 

subpart CC) (Refinery MACT 1); 

• National Emission Standards for 

Hazardous Air Pollutants for Petroleum 

Refineries: Catalytic Cracking Units, 

Catalytic Reforming Units, and Sulfur 

Recovery Units (40 CFR part 63, subpart 

UUU) (Refinery MACT 2); 

• Standards of Performance for 

Petroleum Refineries (40 CFR part 60, 

subpart J) (Refinery NSPS J); and 

• Standards of Performance for 

Petroleum Refineries for which 

Construction, Reconstruction, or 

Modification Commenced After May 14, 

2007 (40 CFR part 60, subpart Ja) 

(Refinery NSPS Ja). 

1. Refinery MACT Standards 

The EPA promulgated MACT 

standards pursuant to CAA section 

112(d)(2) and (3) for refineries located at 

major sources in three separate rules. 

On August 18, 1995, the first Petroleum 

Refinery MACT standard was 

promulgated in 40 CFR part 63, subpart 

CC (60 FR 43620). This rule is known 

as ‘‘Refinery MACT 1’’ and covers the 

‘‘Sources Not Distinctly Listed,’’ 

meaning it includes all emission sources 

from petroleum refinery process units, 

except those listed separately under the 

section 112(c) source category list 

expected to be regulated by other MACT 

standards. Some of the emission sources 

regulated in Refinery MACT 1 include 

miscellaneous process vents, storage 

vessels, wastewater, equipment leaks, 

gasoline loading racks, marine tank 

vessel loading and heat exchange 

systems. 

Certain process vents that were listed 

as a separate source category under CAA 

section 112(c) and that were not 

addressed as part of the Refinery MACT 

1 were subsequently regulated under a 

second MACT standard specific to these 

petroleum refinery process vents, 

codified as 40 CFR part 63, subpart 

UUU, which we promulgated on April 

11, 2002 (67 FR 17762). This standard, 

which is referred to as ‘‘Refinery MACT 

2,’’ covers process vents on catalytic 

cracking units (CCU) (including FCCU), 

CRU and sulfur recovery units (SRU). 

Finally, on October 28, 2009, we 

promulgated MACT standards for heat 

exchange systems, which the EPA had 

not addressed in the original 1995 

Refinery MACT 1 rule (74 FR 55686). In 

this same 2009 action, we updated 

cross-references to the General 

Provisions in 40 CFR part 63. On June 

20, 2013 (78 FR 37133), we promulgated 

minor revisions to the heat exchange 

provisions of Refinery MACT 1. 

On September 27, 2012, Air Alliance 

Houston, California Communities 

Against Toxics and other environmental 

and public health groups filed a lawsuit 

alleging that the EPA missed statutory 

deadlines to review and revise Refinery 

MACT 1 and 2. 

The EPA has reached an agreement to 

settle that litigation. In a consent decree 

filed January 13, 2014 in the U.S. 

District Court for the District of 

Columbia, the EPA commits to perform 

the risk and technology review for 

Refinery MACT 1 and 2 and by May 15, 

2014, either propose any regulations or 

propose that additional regulations are 

not necessary. Under the Consent 

Decree, the EPA commits to take final 

action by April 17, 2015, establishing 

regulations pursuant to the risk and 

technology review or to issue a final 

determination that revision to the 

existing rules is not necessary. 

2. Refinery NSPS 

Refinery NSPS subparts J and Ja 

regulate criteria pollutant emissions, 

including PM, SO2, NOX and CO from 

FCCU catalyst regenerators, fuel gas 

combustion devices (FGCD) and sulfur 

recovery plants. Refinery NSPS Ja also 

regulates criteria pollutant emissions 

from fluid coking units and delayed 

coking units (DCU). 

The NSPS for petroleum refineries (40 

CFR part 60, subpart J; Refinery NSPS 

J) were promulgated in 1974, amended 

in 1976 and amended again in 2008, 

following a review of the standards. As 

part of the review that led to the 2008 

amendments to Refinery NSPS J, the 

EPA developed separate standards of 

performance for new process units (40 

CFR part 60, subpart Ja; Refinery NSPS 

Ja). However, the EPA received petitions 

for reconsideration and granted 

reconsideration on issues related to 

those standards. On December 22, 2008, 

the EPA addressed petition issues 

related to process heaters and flares by 

proposing amendments to certain 

provisions. Final amendments to 

Refinery NSPS Ja were promulgated on 

September 12, 2012 (77 FR 56422). 

In this action, we are proposing 

amendments to address technical 

corrections and clarifications raised in a 

2008 industry petition for 

reconsideration applicable to Refinery 

NSPS Ja. We are addressing these issues 

in this proposal because they also affect 

sources included within these proposed 

amendments to Refinery MACT 1 and 2. 

C. What data collection activities were 

conducted to support this action? 

In 2010, the EPA began a significant 

effort to gather additional information 

and perform analyses to determine how 

to address statutory obligations for the 

Refinery MACT standards and the 

NSPS. This effort focused on gathering 

comprehensive information through an 

industry-wide Information Collection 

Request (ICR) on petroleum refineries, 

conducted under CAA section 114 

authority. The information not claimed 

as CBI by respondents is available in the 

docket (see Docket Item Nos. EPA–HQ– 

OAR–2010–0682–0064 through 0069). 

The EPA issued a single ICR (OMB 

Control Number 2060–0657) for sources 

covered under Refinery MACT 1 and 2 

and Refinery NSPS J and Ja. 

On April 1, 2011, the ICR was sent out 

to the petroleum refining industry. In a 

comprehensive manner, the ICR 


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collected information on processing 

characteristics, crude slate 

characteristics, emissions inventories 

and source testing to fill known data 

gaps. The ICR had four components: (1) 

A questionnaire on processes and 

controls to be completed by all 

petroleum refineries (Component 1); (2) 

an emissions inventory to be developed 

by all petroleum refineries using the 

emissions estimation protocol 

developed for this effort (Component 2); 

(3) distillation feed sampling and 

analysis to be conducted by all 

petroleum refineries (Component 3); 

and (4) emissions source testing to be 

completed in accordance with an EPAapproved protocol for specific sources at 

specific petroleum refineries 

(Component 4). We received responses 

from 149 refineries. We have since 

learned that seven refineries are 

synthetic minor sources, bringing the 

total number of major source refineries 

operating in 2010 to 142. 

Information collected through the ICR 

was used to establish the baseline 

emissions and control levels for 

purposes of the regulatory reviews, to 

identify the most effective control 

measures, and to estimate the 

environmental and cost impacts 

associated with the regulatory options 

considered. As part of the information 

collection process, we provided a 

protocol for survey respondents to 

follow in developing the emissions 

inventories under Component 2 

(Emission Estimation Protocol for 

Petroleum Refineries, available as 

Docket Item Number EPA–HQ–OAR– 

2010–0682–0060). The protocol 

contained detailed guidance for 

estimating emissions from typical 

refinery emission sources and was 

intended to provide a measure of 

consistency and replicability for 

emission estimates across the refining 

industry. Prior to issuance of the ICR, 

the protocol was publicly disseminated 

and underwent several revisions after 

public comments were received. Draft 

and final versions of the emission 

estimation protocol are provided in the 

docket to this rule (Docket ID Number 

EPA–HQ–OAR–2010–0682). The 

protocol provided a hierarchy of 

methodologies available for estimating 

emissions that corresponded to the level 

of information available at refineries. 

For each emission source, the various 

emission measurement or estimation 

methods specific to that source were 

ranked in order of preference, with 

‘‘Methodology Rank 1’’ being the 

preferred method, followed by 

‘‘Methodology Rank 2,’’ and so on. 

Refinery owners and operators were 

requested through the ICR to use the 

highest ranked method (with 

Methodology Rank 1 being the highest) 

for which data were available. 

Methodology Ranks 1 or 2 generally 

relied on continuous emission 

measurements. When continuous 

measurement data were not available, 

engineering calculations or site-specific 

emission factors (Methodology Ranks 3 

and 4) were specified in the protocol by 

EPA; these methods generally needed 

periodic, site-specific measurements. 

When site-specific measurement or test 

data were not available, default 

emission factors (Methodology Rank 5) 

were provided in the protocol by EPA. 

As we reviewed the ICR-submitted 

emissions inventories, we determined 

that, in some cases, refiners either did 

not follow the protocol methodology or 

made an error in their calculations. This 

was evident because pollutants that we 

expected to be reported from certain 

emission sources were either not 

reported or were reported in amounts 

that were not consistent with the 

protocol methodology. In these cases, 

we contacted the refineries and, based 

on their replies, made corrections to 

emission estimates. The original 

Component 2 submittals, 

documentation of the changes as a result 

of our review, and the final emissions 

inventories we relied on for our 

analyses are available in the technical 

memorandum entitled Emissions Data 

Quality Memorandum and Development 

of the Risk Model Input File, in Docket 

ID Number EPA–HQ–OAR–2010–0682. 

Collected emissions test data (test 

reports, continuous emissions 

monitoring system (CEMS) data and 

other continuous monitoring system 

data) were used to assess the 

effectiveness of existing control 

measures, to fill data gaps and to 

examine variability in emissions. The 

ICR requested source testing for a total 

of 90 specific process units at 75 

particular refineries across the industry. 

We received a total of 72 source tests; 

in some cases, refinery sources claimed 

that units we requested to be tested 

were no longer in operation, did not 

exist or did not have an emission point 

to the atmosphere (this was the case for 

hydrocrackers). In other cases, refiners 

claimed they were not able to conduct 

testing because of process 

characteristics. For example, source 

testing of DCU proved to be difficult 

because the moisture content of the 

steam vent required a significant 

amount of gas to be sampled to account 

for dilution. Venting periods of less than 

20 minutes did not accommodate this 

strategy and, therefore, if refiners vented 

for less than 20 minutes, they did not 

sample their steam vent. As a result, 

only two DCU tests out of eight 

requested were received as part of 

Component 4. Results of the stack test 

data are compiled and available in 

Docket ID Number EPA–HQ–OAR– 

2010–0682. 

D. What other relevant background 

information and data are available? 

Over the past several years, the EPA 

has worked with the Texas Commission 

on Environmental Quality and industry 

representatives to better characterize 

proper flare performance. Flares are 

used to control emissions from various 

vents at refineries as well as at other 

types of facilities not in the petroleum 

refinery source categories, such as 

chemical and petrochemical 

manufacturing facilities. In April 2012, 

we released a technical report for peer 

review that discussed our observations 

regarding the operation and 

performance of flares. The report was a 

result of the analysis of several flare 

efficiency studies and flare performance 

test reports. To provide an objective 

evaluation of our analysis, we asked a 

third party to facilitate an ad hoc peer 

review process of the technical report. 

This third party established a balanced 

peer review panel of reviewers from 

outside the EPA. These reviewers 

consisted of individuals that could be 

considered ‘‘technical combustion 

experts’’ within four interest groups: the 

refinery industry, industrial flare 

consultants, academia, and 

environmental stakeholders. 

The EPA developed a charge 

statement with ten charge questions for 

the review panel. The peer reviewers 

were asked to perform a thorough 

review of the technical report and 

answer the charge questions to the 

extent possible, based on their technical 

expertise. The details of the peer review 

process and the charge questions, as 

well as comments received from the 

peer review process, were posted online 

to the Consolidated Petroleum Refinery 

Rulemaking Repository at the EPA’s 

Technology Transfer Network Air 

Toxics Web site (see http://

www.epa.gov/ttn/atw/petref.html). 

These items are also provided in a 

memorandum entitled Peer Review of 

‘‘Parameters for Properly Designed and 

Operated Flares’’ (see Docket ID 

Number EPA–HQ–OAR–2010–0682). 

After considering the comments 

received from the peer review process, 

we developed a final technical 

memorandum (see technical 

memorandum, Flare Performance Data: 

Summary of Peer Review Comments and 

Additional Data Analysis for SteamVerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2

emcdonald on DSK67QTVN1PROD with PROPOSALS2
36888 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

3U.S. EPA SAB. Risk and Technology Review 

(RTR) Risk Assessment Methodologies: For Review 

by the EPA’s Science Advisory board with Case 

Studies—MACT I Petroleum Refining Sources and 

Portland Cement Manufacturing, May 2010. 

4The emissions inventory and the revised 

emissions modeling file can also be found at http:// 

www.epa.gov/ttn/atw/petref.htm. 

Assisted Flares, in Docket ID Number 

EPA–HQ–OAR–2010–0682). 

III. Analytical Procedures 

In this section, we describe the 

analyses performed to support the 

proposed decisions for the RTR and 

other issues addressed in this proposal. 

A. How did we estimate post-MACT 

risks posed by the source categories? 

The EPA conducted a risk assessment 

that provided estimates of the MIR 

posed by the HAP emissions from each 

source in the source categories, the 

hazard index (HI) for chronic exposures 

to HAP with the potential to cause noncancer health effects, and the hazard 

quotient (HQ) for acute exposures to 

HAP with the potential to cause noncancer health effects. The assessment 

also provided estimates of the 

distribution of cancer risks within the 

exposed populations, cancer incidence 

and an evaluation of the potential for 

adverse environmental effects for each 

source category. The eight sections that 

follow this paragraph describe how we 

estimated emissions and conducted the 

risk assessment. The docket for this 

rulemaking (Docket ID Number EPA– 

HQ–OAR–2010–0682) contains the 

following document which provides 

more information on the risk assessment 

inputs and models: Draft Residual Risk 

Assessment for the Petroleum Refining 

Source Sector. The methods used to 

assess risks (as described in the eight 

primary steps below) are consistent with 

those peer-reviewed by a panel of the 

EPA’s Science Advisory Board (SAB) in 

2009 and described in their peer review 

report issued in 2010 3; they are also 

consistent with the key 

recommendations contained in that 

report. 

1. How did we estimate actual 

emissions and identify the emissions 

release characteristics? 

We compiled data sets using the ICR 

emission inventory submittals as a 

starting point. The data sets were 

refined following an extensive quality 

assurance check of source locations, 

emission release characteristics, annual 

emission estimates and FCCU release 

parameters. They were then updated 

based on additional information 

received from refineries. In addition, we 

supplemented these data with results 

from stack testing, which were required 

later than the inventories under the ICR. 

As the stack test information was 

received, we compared these data 

against the refined emission inventories 

and the default emission factors 

provided in the Emission Estimation 

Protocol for Petroleum Refineries 

(Docket Item Number EPA–HQ–OAR– 

2010–0682–0060). 

Based on the stack test data for FCCU, 

we calculated that, on average, HCN 

emissions were a factor of 10 greater 

than the average emission factor of 770 

pounds per barrel FCCU feed provided 

in the protocol. Therefore, we revised 

the HCN emissions for FCCU in the 

emissions inventory used for the risk 

modeling runs (the results are presented 

in this preamble). For the 10 facilities 

that performed a stack test to determine 

HCN emissions from their FCCU, we 

used the actual emissions measured 

during the stack tests in place of the 

inventories originally supplied in 

response to the ICR. For those facilities 

that did not perform a stack test, but 

reported HCN emissions in the 

emissions inventory portion of the ICR, 

we increased the emissions of HCN by 

a factor of 10, assuming the original 

emission inventory estimates for FCCU 

HCN emissions were based on the 

default emission factor in the protocol. 

The emissions inventory from the ICR 

and documentation of the changes made 

to the file as a result of our review are 

contained in the technical 

memorandum entitled Emissions Data 

Quality Memorandum and Development 

of the Risk Model Input File, in Docket 

ID Number EPA–HQ–OAR–2010–0682 

and available on our Web site.4

2. How did we estimate MACTallowable emissions? 

The available emissions data in the 

RTR dataset (i.e., the emissions 

inventory) include estimates of the mass 

of HAP emitted during the specified 

annual time period. In some cases, these 

‘‘actual’’ emission levels are lower than 

the emission levels required to comply 

with the MACT standards. The 

emissions level allowed to be emitted by 

the MACT standards is referred to as the 

‘‘MACT-allowable’’ emissions level. We 

discussed the use of both MACTallowable and actual emissions in the 

final Coke Oven Batteries residual risk 

rule (70 FR 19998–19999, April 15, 

2005) and in the proposed and final 

Hazardous Organic NESHAP residual 

risk rules (71 FR 34428, June 14, 2006, 

and 71 FR 76609, December 21, 2006, 

respectively). In those previous actions, 

we noted that assessing the risks at the 

MACT-allowable level is inherently 

reasonable since these risks reflect the 

maximum level facilities could emit and 

still comply with national emission 

standards. We also explained that it is 

reasonable to consider actual emissions, 

where such data are available, in both 

steps of the risk analysis, in accordance 

with the Benzene NESHAP approach. 

(54 FR 38044, September 14, 1989.) 

We requested allowable emissions 

data in the ICR. However, unlike for 

actual emissions, where the ICR 

specified the use of the Emission 

Estimation Protocol for Petroleum 

Refineries (available as Docket Item 

Number EPA–HQ–OAR–2010–0682– 

0060), we did not specify a method to 

calculate allowable emissions. As a 

result, in our review of these data and 

when comparing estimates between 

facilities, we found that facilities did 

not estimate allowable emissions 

consistently across the industry. In 

addition, facilities failed to report 

allowable emissions for many emission 

points, likely because they did not know 

how to translate a work practice or 

performance standard into an allowable 

emission estimate and they did not 

know how to speciate individual HAP 

where the MACT standard is based on 

a surrogate, such as PM or VOC. 

Therefore, the ICR-submitted 

information for allowable emissions did 

not include emission estimates for all 

HAP and sources of interest. 

Consequently, we used our Refinery 

Emissions Model (REM Model) to 

estimate allowable emissions. The REM 

model relies on model plants that vary 

based on throughput capacity. Each 

model plant contains process-specific 

default emission factors, adjusted for 

compliance with the Refinery MACT 1 

and 2 emission standards. 

The risks associated with the 

allowable emissions were evaluated 

using the same dispersion modeling 

practices, exposure assumptions and 

health benchmarks as the actual risks. 

However, because each refinery’s 

allowable emissions were calculated by 

using model plants, selected based on 

each refinery’s actual capacities and 

throughputs, emission estimates for 

point sources are not specific to a 

particular latitude/longitude location. 

Therefore, for risk modeling purposes, 

all allowable emissions were assumed to 

be released from the centroid of the 

facility. (Note: for fugitive (area) 

sources, the surface area was selected by 

the size of the model plant and the 

release point was shifted to the 

southwest so the center of the fugitive 

area was near the centroid of the 

facility). The emission and risk 

estimates for the actual emission 

inventory were compared to the 


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5This metric comes from the Benzene NESHAP. 

See 54 FR 38046, September 14, 1989. 

6U.S. EPA. Revision to the Guideline on Air 

Quality Models: Adoption of a Preferred General 

Purpose (Flat and Complex Terrain) Dispersion 

Model and Other Revisions (70 FR 68218, 

November 9, 2005). 

7A census block is the smallest geographic area 

for which census statistics are tabulated. 

8Supplemental Guidance for Assessing 

Susceptibility from Early-Life Exposure to 

Carcinogens. Risk Assessment Forum, U.S. 

Environmental Protection Agency, Washington, DC. 

EPA/630/R–03/003F. March 2005. Available at 

http://www.epa.gov/ttn/atw/childrens_supplement_

final.pdf. 

9These classifications also coincide with the 

terms ‘‘known carcinogen, probable carcinogen, and 

possible carcinogen,’’ respectively, which are the 

terms advocated in the EPA’s previous Guidelines 

for Carcinogen Risk Assessment, published in 1986 

(51 FR 33992, September 24, 1986). Summing the 

risks of these individual compounds to obtain the 

cumulative cancer risks is an approach that was 

recommended by the EPA’s SAB in their 2002 peer 

review of EPA’s National Air Toxics Assessment 

(NATA) entitled, NATA—Evaluating the Nationalscale Air Toxics Assessment 1996 Data—an SAB 

Advisory, available at: http://yosemite.epa.gov/sab/ 

sabproduct.nsf/

214C6E915BB04E14852570CA007A682C/$File/

ecadv02001.pdf. 

allowable emissions and risk estimates. 

For most work practices, where 

allowable emission estimates are 

difficult to predict, the actual risk 

estimates were higher than those 

projected using the REM Model 

estimates. Consequently, we postprocessed the two risk files, taking the 

higher risk estimates from the actual 

emissions inventory for sources subject 

to work practice standards, such as 

process equipment leaks, and sources 

that were not covered in the REM 

Model, combining them with the risk 

estimates from sources with more 

readily determined allowable emissions. 

The combined post-processed allowable 

risk estimates provide a high estimate of 

the risk allowed under Refinery MACT 

1 and 2. The REM Model assumptions 

and emission estimates, along with the 

post-processing of risk estimate results 

that produced the final risk estimates for 

the allowable emissions, are provided in 

the docket (see Refinery Emissions and 

Risk Estimates for Modeled ‘‘Allowable’’ 

Emissions in Docket ID Number EPA– 

HQ–OAR–2010–0682). 

3. How did we conduct dispersion 

modeling, determine inhalation 

exposures and estimate individual and 

population inhalation risks? 

Both long-term and short-term 

inhalation exposure concentrations and 

health risks from the source categories 

addressed in this proposal were 

estimated using the Human Exposure 

Model (Community and Sector HEM–3 

version 1.1.0). The HEM–3 performs 

three primary risk assessment activities: 

(1) Conducting dispersion modeling to 

estimate the concentrations of HAP in 

ambient air, (2) estimating long-term 

and short-term inhalation exposures to 

individuals residing within 50 

kilometers (km) of the modeled 

sources 5, and (3) estimating individual 

and population-level inhalation risks 

using the exposure estimates and 

quantitative dose-response information. 

The air dispersion model used by the 

HEM–3 model (AERMOD) is one of the 

EPA’s preferred models for assessing 

pollutant concentrations from industrial 

facilities.6 To perform the dispersion 

modeling and to develop the 

preliminary risk estimates, HEM–3 

draws on three data libraries. The first 

is a library of meteorological data, 

which is used for dispersion 

calculations. This library includes 1 

year (2011) of hourly surface and upper 

air observations for 824 meteorological 

stations, selected to provide coverage of 

the United States and Puerto Rico. A 

second library of United States Census 

Bureau census block 7 internal point 

locations and populations provides the 

basis of human exposure calculations 

(U.S. Census, 2010). In addition, for 

each census block, the census library 

includes the elevation and controlling 

hill height, which are also used in 

dispersion calculations. A third library 

of pollutant unit risk factors and other 

health benchmarks is used to estimate 

health risks. These risk factors and 

health benchmarks are the latest values 

recommended by the EPA for HAP and 

other toxic air pollutants. These values 

are available at: http://www.epa.gov/ttn/ 

atw/toxsource/summary.html and are 

discussed in more detail later in this 

section. 

In developing the risk assessment for 

chronic exposures, we used the 

estimated annual average ambient air 

concentrations of each HAP emitted by 

each source for which we have 

emissions data in the source category. 

The air concentrations at each nearby 

census block centroid were used as a 

surrogate for the chronic inhalation 

exposure concentration for all the 

people who reside in that census block. 

We calculated the MIR for each facility 

as the cancer risk associated with a 

continuous lifetime (24 hours per day, 

7 days per week, and 52 weeks per year 

for a 70-year period) exposure to the 

maximum concentration at the centroid 

of inhabited census blocks. Individual 

cancer risks were calculated by 

multiplying the estimated lifetime 

exposure to the ambient concentration 

of each of the HAP (in micrograms per 

cubic meter (mg/m3)) by its unit risk 

estimate (URE). The URE is an upper 

bound estimate of an individual’s 

probability of contracting cancer over a 

lifetime of exposure to a concentration 

of 1 microgram of the pollutant per 

cubic meter of air. For residual risk 

assessments, we generally use URE 

values from the EPA’s Integrated Risk 

Information System (IRIS). For 

carcinogenic pollutants without EPA 

IRIS values, we look to other reputable 

sources of cancer dose-response values, 

often using California EPA (CalEPA) 

URE values, where available. In cases 

where new, scientifically credible doseresponse values have been developed in 

a manner consistent with the EPA 

guidelines and have undergone a peer 

review process similar to that used by 

the EPA, we may use such doseresponse values in place of, or in 

addition to, other values, if appropriate. 

We note here that several carcinogens 

emitted by facilities in these source 

categories have a mutagenic mode of 

action. For these compounds, we 

applied the age-dependent adjustment 

factors (ADAF) described in the EPA’s 

Supplemental Guidance for Assessing 

Susceptibility from Early-Life Exposure 

to Carcinogens.8 This adjustment has 

the effect of increasing the estimated 

lifetime risks for these pollutants by a 

factor of 1.6. Although only a small 

fraction of the total polycyclic organic 

matter (POM) emissions were reported 

as individual compounds, the EPA 

expresses carcinogenic potency of POM 

relative to the carcinogenic potency of 

benzo[a]pyrene, based on evidence that 

carcinogenic POM have the same 

mutagenic mode of action as does 

benzo[a]pyrene. The EPA’s Science 

Policy Council recommends applying 

the ADAF to all carcinogenic polycyclic 

aromatic hydrocarbons (PAH) for which 

risk estimates are based on potency 

relative to benzo[a]pyrene. Accordingly, 

we have applied the ADAF to the 

benzo[a]pyrene-equivalent mass portion 

of all POM mixtures. 

The EPA estimated incremental 

individual lifetime cancer risks 

associated with emissions from the 

facilities in the source categories as the 

sum of the risks for each of the 

carcinogenic HAP (including those 

classified as carcinogenic to humans, 

likely to be carcinogenic to humans, and 

suggestive evidence of carcinogenic 

potential 9) emitted by the modeled 

sources. Cancer incidence and the 

distribution of individual cancer risks 

for the population within 50 km of the 

sources were also estimated for the 

source categories as part of this 

assessment by summing individual 

risks. A distance of 50 km is consistent 

with both the analysis supporting the 


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10National Academy of Sciences (NAS), 2001. 

Standing Operating Procedures for Developing 

Acute Exposure Levels for Hazardous Chemicals, 

page 2. 

1989 Benzene NESHAP (54 FR 38044, 

September 14, 1989) and the limitations 

of Gaussian dispersion models, 

including AERMOD. 

To assess the risk of non-cancer 

health effects from chronic exposures, 

we summed the HQ for each of the HAP 

that affects a common target organ 

system to obtain the HI for that target 

organ system (or target organ-specific 

HI, TOSHI). The HQ is the estimated 

exposure divided by the chronic 

reference level, which is a value 

selected from one of several sources. 

First, the chronic reference level can be 

the EPA Reference Concentration (RfC) 

(http://www.epa.gov/riskassessment/

glossary.htm), defined as ‘‘an estimate 

(with uncertainty spanning perhaps an 

order of magnitude) of a continuous 

inhalation exposure to the human 

population (including sensitive 

subgroups) that is likely to be without 

an appreciable risk of deleterious effects 

during a lifetime.’’ Alternatively, in 

cases where an RfC from the EPA’s IRIS 

database is not available or where the 

EPA determines that using a value other 

than the RfC is appropriate, the chronic 

reference level can be a value from the 

following prioritized sources: (1) The 

Agency for Toxic Substances and 

Disease Registry Minimum Risk Level 

(http://www.atsdr.cdc.gov/mrls/

index.asp), which is defined as ‘‘an 

estimate of daily human exposure to a 

hazardous substance that is likely to be 

without an appreciable risk of adverse 

non-cancer health effects (other than 

cancer) over a specified duration of 

exposure’’; (2) the CalEPA Chronic 

Reference Exposure Level (REL) (http:// 

www.oehha.ca.gov/air/hot_spots/pdf/ 

HRAguidefinal.pdf), which is defined as 

‘‘the concentration level (that is 

expressed in units of mg/m3 for 

inhalation exposure and in a dose 

expressed in units of milligram per 

kilogram per day (mg/kg-day) for oral 

exposures), at or below which no 

adverse health effects are anticipated for 

a specified exposure duration’’; or (3), as 

noted above, a scientifically credible 

dose-response value that has been 

developed in a manner consistent with 

the EPA guidelines and has undergone 

a peer review process similar to that 

used by the EPA, in place of or in 

concert with other values. 

The EPA also evaluated screening 

estimates of acute exposures and risks 

for each of the HAP at the point of 

highest off-site exposure for each facility 

(i.e., not just the census block 

centroids), assuming that a person is 

located at this spot at a time when both 

the peak (hourly) emissions rate and 

worst-case dispersion conditions occur. 

The acute HQ is the estimated acute 

exposure divided by the acute doseresponse value. In each case, the EPA 

calculated acute HQ values using best 

available, short-term dose-response 

values. These acute dose-response 

values, which are described below, 

include the acute REL, acute exposure 

guideline levels (AEGL) and emergency 

response planning guidelines (ERPG) for 

1-hour exposure durations. As 

discussed below, we used realistic 

assumptions based on knowledge of the 

emission point release characteristics 

for emission rates, and conservative 

assumptions for meteorology and 

exposure location for our acute analysis. 

As described in the CalEPA’s Air 

Toxics Hot Spots Program Risk 

Assessment Guidelines, Part I, The 

Determination of Acute Reference 

Exposure Levels for Airborne Toxicants, 

an acute REL value (http://

www.oehha.ca.gov/air/pdf/acuterel.pdf) 

is defined as ‘‘the concentration level at 

or below which no adverse health 

effects are anticipated for a specified 

exposure duration.’’ Id. at page 2. Acute 

REL values are based on the most 

sensitive, relevant, adverse health effect 

reported in the peer-reviewed medical 

and toxicological literature. Acute REL 

values are designed to protect the most 

sensitive individuals in the population 

through the inclusion of margins of 

safety. Because margins of safety are 

incorporated to address data gaps and 

uncertainties, exceeding the REL value 

does not automatically indicate an 

adverse health impact. 

AEGL values were derived in 

response to recommendations from the 

National Research Council (NRC). As 

described in Standing Operating 

Procedures (SOP) of the National 

Advisory Committee on Acute Exposure 

Guideline Levels for Hazardous 

Substances (http://www.epa.gov/oppt/

aegl/pubs/sop.pdf),10 ‘‘the NRC’s 

previous name for acute exposure 

levels—community emergency exposure 

levels—was replaced by the term AEGL 

to reflect the broad application of these 

values to planning, response, and 

prevention in the community, the 

workplace, transportation, the military, 

and the remediation of Superfund 

sites.’’ Id. at 2. 

This document also states that AEGL 

values ‘‘represent threshold exposure 

limits for the general public and are 

applicable to emergency exposures 

ranging from 10 minutes to eight 

hours.’’ Id. at 2. The document lays out 

the purpose and objectives of AEGL by 

stating that ‘‘the primary purpose of the 

AEGL program and the National 

Advisory Committee for Acute Exposure 

Guideline Levels for Hazardous 

Substances is to develop guideline 

levels for once-in-a-lifetime, short-term 

exposures to airborne concentrations of 

acutely toxic, high-priority chemicals.’’ 

Id. at 21. In detailing the intended 

application of AEGL values, the 

document states that ‘‘[i]t is anticipated 

that the AEGL values will be used for 

regulatory and nonregulatory purposes 

by U.S. Federal and state agencies and 

possibly the international community in 

conjunction with chemical emergency 

response, planning and prevention 

programs. More specifically, the AEGL 

values will be used for conducting 

various risk assessments to aid in the 

development of emergency 

preparedness and prevention plans, as 

well as real-time emergency response 

actions, for accidental chemical releases 

at fixed facilities and from transport 

carriers.’’ Id. at 31. 

The AEGL–1 value is then specifically 

defined as ‘‘the airborne concentration 

(expressed as ppm (parts per million) or 

mg/m 3 (milligrams per cubic meter)) of 

a substance above which it is predicted 

that the general population, including 

susceptible individuals, could 

experience notable discomfort, 

irritation, or certain asymptomatic 

nonsensory effects. However, the effects 

are not disabling and are transient and 

reversible upon cessation of exposure.’’ 

Id. at 3. The document also notes that, 

‘‘Airborne concentrations below AEGL– 

1 represent exposure levels that can 

produce mild and progressively 

increasing but transient and 

nondisabling odor, taste, and sensory 

irritation or certain asymptomatic, 

nonsensory effects.’’ Id. Similarly, the 

document defines AEGL–2 values as 

‘‘the airborne concentration (expressed 

as parts per million or milligrams per 

cubic meter) of a substance above which 

it is predicted that the general 

population, including susceptible 

individuals, could experience 

irreversible or other serious, long-lasting 

adverse health effects or an impaired 

ability to escape.’’ Id. 

ERPG values are derived for use in 

emergency response, as described in the 

American Industrial Hygiene 

Association’s ERP Committee document 

entitled, ERPGS Procedures and 

Responsibilities, which states that, 

‘‘Emergency Response Planning 

Guidelines were developed for 

emergency planning and are intended as 

health-based guideline concentrations 

for single exposures to 


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11ERP Committee Procedures and 

Responsibilities. November 1, 2006. American 

Industrial Hygiene Association. Available at 

https://www.aiha.org/get-involved/AIHAGuideline

Foundation/EmergencyResponsePlanning

Guidelines/Documents/ERP-SOPs2006.pdf. 

12The SAB peer review of RTR Risk Assessment 

Methodologies is available at: http://

yosemite.epa.gov/sab/sabproduct.nsf/

4AB3966E263D943A8525771F00668381/$File/EPASAB-10-007-unsigned.pdf. 

13U.S. EPA. (2009) Chapter 2.9 Chemical Specific 

Reference Values for Formaldehyde in Graphical 

Arrays of Chemical-Specific Health Effect Reference 

Values for Inhalation Exposures (Final Report). U.S. 

Environmental Protection Agency, Washington, DC, 

EPA/600/R–09/061, and available on-line at 

http://cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=211003. 

chemicals.’’ 11 Id. at 1. The ERPG–1 

value is defined as ‘‘the maximum 

airborne concentration below which it is 

believed that nearly all individuals 

could be exposed for up to 1 hour 

without experiencing other than mild 

transient adverse health effects or 

without perceiving a clearly defined, 

objectionable odor.’’ Id. at 2. Similarly, 

the ERPG–2 value is defined as ‘‘the 

maximum airborne concentration below 

which it is believed that nearly all 

individuals could be exposed for up to 

one hour without experiencing or 

developing irreversible or other serious 

health effects or symptoms which could 

impair an individual’s ability to take 

protective action.’’ Id. at 1. 

As can be seen from the definitions 

above, the AEGL and ERPG values 

include the similarly-defined severity 

levels 1 and 2. For many chemicals, a 

severity level 1 value AEGL or ERPG has 

not been developed because the types of 

effects for these chemicals are not 

consistent with the AEGL–1/ERPG–1 

definitions; in these instances, we 

compare higher severity level AEGL–2 

or ERPG–2 values to our modeled 

exposure levels to screen for potential 

acute concerns. When AEGL–1/ERPG–1 

values are available, they are used in 

our acute risk assessments. 

Acute REL values for 1-hour exposure 

durations are typically lower than their 

corresponding AEGL–1 and ERPG–1 

values. Even though their definitions are 

slightly different, AEGL–1 values are 

often the same as the corresponding 

ERPG–1 values, and AEGL–2 values are 

often equal to ERPG–2 values. 

Maximum HQ values from our acute 

screening risk assessments typically 

result when basing them on the acute 

REL value for a particular pollutant. In 

cases where our maximum acute HQ 

value exceeds 1, we also report the HQ 

value based on the next highest acute 

dose-response value (usually the AEGL– 

1 and/or the ERPG–1 value). 

To develop screening estimates of 

acute exposures in the absence of hourly 

emissions data, generally we first 

develop estimates of maximum hourly 

emissions rates by multiplying the 

average actual annual hourly emissions 

rates by a default factor to cover 

routinely variable emissions. However, 

for the petroleum refineries category, we 

incorporated additional information and 

process knowledge in order to better 

characterize acute emissions, as 

described below. The ICR included 

input fields for both annual emissions 

and maximum hourly emissions. The 

maximum hourly emission values were 

often left blank or appeared to be 

reported in units other than those 

required for this emissions field 

(pounds per hour). Consequently, 

instead of relying on the inadequate 

data provided in response to the ICR, we 

elected to estimate the hourly emissions 

based on the reported annual emissions 

(converted to average hourly emissions 

in terms of pounds per hour) and then 

to apply an escalation factor, 

considering the different types of 

emission sources and their inherent 

variability, in order to calculate 

maximum hourly rates. For sources with 

relatively continuous operations and 

steady state emissions, such as FCCU, 

sulfur recovery plants, and continuous 

catalytic reformers, a factor of 2 was 

used to estimate the maximum hourly 

rates from the average hourly emission 

rates. For sources with relatively 

continuous emissions, but with more 

variability, like storage tanks and 

wastewater systems, a factor of 4 was 

used to estimate the maximum hourly 

rates from the average hourly emission 

rates. For non-continuous emission 

sources with more variability, such as 

DCU, cyclic CRU, semi-regenerative 

CRU, and transfer and loading 

operations, the number of hours in the 

venting cycle and the variability of 

emissions expected in that cycle were 

used to determine the escalation factor 

for each emissions source. The 

escalation factors for these processes 

range from 10 to 60. For more detail 

regarding escalation factors and the 

rationale for their selection, see 

Derivation of Hourly Emission Rates for 

Petroleum Refinery Emission Sources 

Used in the Acute Risk Analysis, 

available in the docket for this 

rulemaking (Docket ID Number EPA– 

HQ–OAR–2010–0682). 

As part of our acute risk assessment 

process, for cases where acute HQ 

values from the screening step were less 

than or equal to 1 (even under the 

conservative assumptions of the 

screening analysis), acute impacts were 

deemed negligible and no further 

analysis was performed. In cases where 

an acute HQ from the screening step 

was greater than 1, additional sitespecific data were considered to 

develop a more refined estimate of the 

potential for acute impacts of concern. 

For these source categories, the data 

refinements employed consisted of 

using the site-specific facility layout to 

distinguish facility property from an 

area where the public could be exposed. 

These refinements are discussed more 

fully in the Draft Residual Risk 

Assessment for the Petroleum Refining 

Source Sector, which is available in the 

docket for this rulemaking (Docket ID 

Number EPA–HQ–OAR–2010–0682). 

Ideally, we would prefer to have 

continuous measurements over time to 

see how the emissions vary by each 

hour over an entire year. Having a 

frequency distribution of hourly 

emissions rates over a year would allow 

us to perform a probabilistic analysis to 

estimate potential threshold 

exceedances and their frequency of 

occurrence. Such an evaluation could 

include a more complete statistical 

treatment of the key parameters and 

elements adopted in this screening 

analysis. Recognizing that this level of 

data is rarely available, we instead rely 

on the multiplier approach. 

To better characterize the potential 

health risks associated with estimated 

acute exposures to HAP, and in 

response to a key recommendation from 

the SAB’s peer review of the EPA’s RTR 

risk assessment methodologies,12 we 

generally examine a wider range of 

available acute health metrics (e.g., REL, 

AEGL) than we do for our chronic risk 

assessments. This is in response to the 

SAB’s acknowledgement that there are 

generally more data gaps and 

inconsistencies in acute reference 

values than there are in chronic 

reference values. In some cases, e.g., 

when Reference Value Arrays 13 for HAP 

have been developed, we consider 

additional acute values (i.e., 

occupational and international values) 

to provide a more complete risk 

characterization. 

4. How did we conduct the 

multipathway exposure and risk 

screening? 

The EPA conducted a screening 

analysis examining the potential for 

significant human health risks due to 

exposures via routes other than 

inhalation (i.e., ingestion). We first 

determined whether any sources in the 

source categories emitted any hazardous 

air pollutants known to be persistent 

and bio-accumulative in the 

environment (PB–HAP). The PB–HAP 

compounds or compound classes are 


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14 In doing so, EPA notes that the legal standard 

for a primary NAAQS—that a standard is requisite 

to protect public health and provide an adequate 

margin of safety (CAA Section 109(b))—differs from 

the Section 112(f) standard (requiring among other 

things that the standard provide an ‘‘ample margin 

of safety’’). However, the lead NAAQS is a 

reasonable measure of determining risk 

acceptability (i.e., the first step of the Benzene 

NESHAP analysis) since it is designed to protect the 

most susceptible group in the human population— 

children, including children living near major lead 

emitting sources. 73 FR 67002/3; 73 FR 67000/3; 73 

FR 67005/1, November 12, 2008. In addition, 

applying the level of the primary lead NAAQS at 

the risk acceptability step is conservative, since that 

primary lead NAAQS reflects an adequate margin 

of safety. 

identified for the screening from the 

EPA’s Air Toxics Risk Assessment 

Library (available at http://

www.epa.gov/ttn/fera/risk_atra_

vol1.html). 

For the petroleum refinery source 

categories, we identified emissions of 

cadmium compounds, chlorinated 

dibenzodioxins and furans (CDDF), lead 

compounds, mercury compounds, 

polychlorinated biphenyls (PCB), and 

polycylic organic matter (POM). 

Because PB–HAP are emitted by at least 

one facility, we proceeded to the second 

step of the evaluation. In this step, we 

determined whether the facility-specific 

emission rates of each of the emitted 

PB–HAP were large enough to create the 

potential for significant non-inhalation 

human health risks under reasonable 

worst-case conditions. To facilitate this 

step, we developed emissions rate 

screening levels for each PB–HAP using 

a hypothetical upper-end screening 

exposure scenario developed for use in 

conjunction with the EPA’s ‘‘Total Risk 

Integrated Methodology. Fate, 

Transport, and Ecological Exposure’’ 

(TRIM.FaTE) model. We conducted a 

sensitivity analysis on the screening 

scenario to ensure that its key design 

parameters would represent the upper 

end of the range of possible values, such 

that it would represent a conservative 

but not impossible scenario. The 

facility-specific emissions rates of each 

of the PB–HAP were compared to their 

corresponding emission rate screening 

values to assess the potential for 

significant human health risks via noninhalation pathways. We call this 

application of the TRIM.FaTE model the 

Tier I TRIM- Screen or Tier I screen. 

For the purpose of developing 

emissions rates for our Tier I TRIMScreen, we derived emission levels for 

each PB–HAP (other than lead) at which 

the maximum excess lifetime cancer 

risk would be 1-in-1 million or, for HAP 

that cause non-cancer health effects, the 

maximum HQ would be 1. If the 

emissions rate of any PB–HAP exceeds 

the Tier I screening emissions rate for 

any facility, we conduct a second 

screen, which we call the Tier II TRIMscreen or Tier II screen. In the Tier II 

screen, the location of each facility that 

exceeded the Tier I emission rate is used 

to refine the assumptions associated 

with the environmental scenario while 

maintaining the exposure scenario 

assumptions. We then adjust the riskbased Tier I screening level for each PB– 

HAP for each facility based on an 

understanding of how exposure 

concentrations estimated for the 

screening scenario change with 

meteorology and environmental 

assumptions. PB–HAP emissions that do 

not exceed these new Tier II screening 

levels are considered to pose no 

unacceptable risks. When facilities 

exceed the Tier II screening levels, it 

does not mean that multi-pathway 

impacts are significant, only that we 

cannot rule out that possibility based on 

the results of the screen. These facilities 

may be further evaluated for multipathway risks using the TRIM.FaTE 

model. 

In evaluating the potential for multipathway risk from emissions of lead 

compounds, rather than developing a 

screening emissions rate for them, we 

compared modeled maximum estimated 

chronic inhalation exposures with the 

level of the current National Ambient 

Air Quality Standards (NAAQS) for 

lead.14 Values below the level of the 

primary (health-based) lead NAAQS 

were considered to have a low potential 

for multi-pathway risk. 

For further information on the multipathway analysis approach, see the 

Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, 

which is available in the docket for this 

action (Docket ID Number EPA–HQ– 

OAR–2010–0682). 

5. How did we assess risks considering 

emissions control options? 

In addition to assessing baseline 

inhalation risks and screening for 

potential multipathway risks, we also 

estimated risks considering the potential 

emission reductions that would be 

achieved by the control options under 

consideration. We used the same 

emissions inventory that we used for the 

risk modeling and applied emission 

reduction estimates for the control 

options we are proposing to calculate 

the post-control risk. We note that for 

storage vessels, in response to the ICR 

some facilities reported emissions for 

their tank farm or a group of storage 

vessels rather than for each individual 

storage vessel. In order to calculate 

emissions for each storage vessel, we 

used unit-specific data from the ICR to 

estimate the pre- and post-control 

emissions based on the operating 

characteristics and controls reported for 

each unit. For example, HAP emissions 

from each storage vessel were estimated 

based on the size, contents, and controls 

reported for that storage vessel. If 

additional controls would be necessary 

to comply with proposed requirements 

for storage vessels, the HAP emissions 

were again estimated based on the 

upgraded controls. The pre- and postcontrol emissions were summed across 

all storage vessels at the facility to 

determine a facility-specific emission 

reduction factor. The facility-specific 

emission reduction factor was then used 

to adjust the emissions for each of the 

pollutants reported for storage vessels at 

that facility to account for the postcontrol emissions. In this manner, the 

expected emission reductions were 

applied to the specific HAP and 

emission points in the source category 

dataset to develop corresponding 

estimates of risk and incremental risk 

reductions. The resulting emission file 

used for post-control risk analysis is 

available in the docket for this action 

(Docket ID Number EPA–HQ–OAR– 

2010–0682). 

6. How did we conduct the 

environmental risk screening 

assessment? 

a. Adverse Environmental Effect 

The EPA has developed a screening 

approach to examine the potential for 

adverse environmental effects as 

required under section 112(f)(2)(A) of 

the CAA. Section 112(a)(7) of the CAA 

defines ‘‘adverse environmental effect’’ 

as ‘‘any significant and widespread 

adverse effect, which may reasonably be 

anticipated, to wildlife, aquatic life, or 

other natural resources, including 

adverse impacts on populations of 

endangered or threatened species or 

significant degradation of 

environmental quality over broad 

areas.’’ 

b. Environmental HAP 

The EPA focuses on seven HAP, 

which we refer to as ‘‘environmental 

HAP,’’ in its screening analysis: five PB– 

HAP and two acid gases. The five PB– 

HAP are cadmium, dioxins/furans, 

POM, mercury (both inorganic mercury 

and methyl mercury) and lead 

compounds. The two acid gases are HCl 

and HF. The rationale for including 

these seven HAP in the environmental 

risk screening analysis is presented 

below. 

HAP that persist and bioaccumulate 

are of particular environmental concern 

because they accumulate in the soil, 

sediment and water. The PB–HAP are 


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15The secondary lead NAAQS is a reasonable 

measure of determining whether there is an adverse 

environmental effect since it was established 

considering ‘‘effects on soils, water, crops, 

vegetation, man-made materials, animals, wildlife, 

weather, visibility and climate, damage to and 

deterioration of property, and hazards to 

transportation, as well as effects on economic 

values and on personal comfort and well-being.’’ 

taken up, through sediment, soil, water, 

and/or ingestion of other organisms, by 

plants or animals (e.g., small fish) at the 

bottom of the food chain. As larger and 

larger predators consume these 

organisms, concentrations of the PB– 

HAP in the animal tissues increases as 

does the potential for adverse effects. 

The five PB–HAP we evaluate as part of 

our screening analysis account for 99.8 

percent of all PB–HAP emissions 

nationally from stationary sources (on a 

mass basis from the 2005 National 

Emissions Inventory (NEI)). 

In addition to accounting for almost 

all of the mass of PB–HAP emitted, we 

note that the TRIM.Fate model that we 

use to evaluate multipathway risk 

allows us to estimate concentrations of 

cadmium compounds, dioxins/furans, 

POM and mercury in soil, sediment and 

water. For lead compounds, we 

currently do not have the ability to 

calculate these concentrations using the 

TRIM.Fate model. Therefore, to evaluate 

the potential for adverse environmental 

effects from lead, we compare the 

estimated HEM-modeled exposures 

from the source category emissions of 

lead with the level of the secondary 

NAAQS for lead.15 We consider values 

below the level of the secondary lead 

NAAQS to be unlikely to cause adverse 

environmental effects. 

Due to their well-documented 

potential to cause direct damage to 

terrestrial plants, we include two acid 

gases, HCl and HF, in the environmental 

screening analysis. According to the 

2005 NEI, HCl and HF account for about 

99 percent (on a mass basis) of the total 

acid gas HAP emitted by stationary 

sources in the U.S. In addition to the 

potential to cause direct damage to 

plants, high concentrations of HF in the 

air have been linked to fluorosis in 

livestock. Air concentrations of these 

HAP are already calculated as part of 

the human multipathway exposure and 

risk screening analysis using the HEM3– 

AERMOD air dispersion model, and we 

are able to use the air dispersion 

modeling results to estimate the 

potential for an adverse environmental 

effect. 

The EPA acknowledges that other 

HAP beyond the seven HAP discussed 

above may have the potential to cause 

adverse environmental effects. 

Therefore, the EPA may include other 

relevant HAP in its environmental risk 

screening in the future, as modeling 

science and resources allow. The EPA 

invites comment on the extent to which 

other HAP emitted by the source 

categories may cause adverse 

environmental effects. Such information 

should include references to peerreviewed ecological effects benchmarks 

that are of sufficient quality for making 

regulatory decisions, as well as 

information on the presence of 

organisms located near facilities within 

the source categories that such 

benchmarks indicate could be adversely 

affected. 

c. Ecological Assessment Endpoints and 

Benchmarks for PB–HAP 

An important consideration in the 

development of the EPA’s screening 

methodology is the selection of 

ecological assessment endpoints and 

benchmarks. Ecological assessment 

endpoints are defined by the ecological 

entity (e.g., aquatic communities 

including fish and plankton) and its 

attributes (e.g., frequency of mortality). 

Ecological assessment endpoints can be 

established for organisms, populations, 

communities or assemblages, and 

ecosystems. 

For PB–HAP, we evaluated the 

following community-level ecological 

assessment endpoints to screen for 

organisms directly exposed to HAP in 

soils, sediment and water: 

• Local terrestrial communities (i.e., 

soil invertebrates, plants) and 

populations of small birds and 

mammals that consume soil 

invertebrates exposed to PB–HAP in the 

surface soil. 

• Local benthic (i.e., bottom sediment 

dwelling insects, amphipods, isopods 

and crayfish) communities exposed to 

PB–HAP in sediment in nearby water 

bodies. 

• Local aquatic (water-column) 

communities (including fish and 

plankton) exposed to PB–HAP in nearby 

surface waters. 

For PB–HAP, we also evaluated the 

following population-level ecological 

assessment endpoint to screen for 

indirect HAP exposures of top 

consumers via the bioaccumulation of 

HAP in food chains. 

• Piscivorous (i.e., fish-eating) 

wildlife consuming PB–HAPcontaminated fish from nearby water 

bodies. 

For cadmium compounds, dioxins/

furans, POM and mercury, we identified 

the available ecological benchmarks for 

each assessment endpoint. An 

ecological benchmark represents a 

concentration of HAP (e.g., 0.77 

micrograms of HAP per liter of water) 

that has been linked to a particular 

environmental effect level (e.g., a noobserved-adverse-effect level (NOAEL)) 

through scientific study. For PB–HAP 

we identified, where possible, 

ecological benchmarks at the following 

effect levels: 

• Probable effect level (PEL): Level 

above which adverse effects are 

expected to occur frequently. 

• Lowest-observed-adverse-effect 

level (LOAEL): The lowest exposure 

level tested at which there are 

biologically significant increases in 

frequency or severity of adverse effects. 

• No-observed-adverse-effect level 

(NOAEL): The highest exposure level 

tested at which there are no biologically 

significant increases in the frequency or 

severity of adverse effect. 

We established a hierarchy of 

preferred benchmark sources to allow 

selection of benchmarks for each 

environmental HAP at each ecological 

assessment endpoint. In general, the 

EPA sources that are used at a 

programmatic level (e.g., Office of 

Water, Superfund Program) were used, 

if available. If not, the EPA benchmarks 

used in regional programs (e.g., 

Superfund) were used. If benchmarks 

were not available at a programmatic or 

regional level, we used benchmarks 

developed by other federal agencies 

(e.g., NOAA) or state agencies. 

Benchmarks for all effect levels are 

not available for all PB–HAP and 

assessment endpoints. In cases where 

multiple effect levels were available for 

a particular PB–HAP and assessment 

endpoint, we use all of the available 

effect levels to help us to determine 

whether ecological risks exist and, if so, 

whether the risks could be considered 

significant and widespread. 

d. Ecological Assessment Endpoints and 

Benchmarks for Acid Gases 

The environmental screening analysis 

also evaluated potential damage and 

reduced productivity of plants due to 

direct exposure to acid gases in the air. 

For acid gases, we evaluated the 

following ecological assessment 

endpoint: 

• Local terrestrial plant communities 

with foliage exposed to acidic gaseous 

HAP in the air. 

The selection of ecological 

benchmarks for the effects of acid gases 

on plants followed the same approach 

as for PB–HAP (i.e., we examine all of 

the available chronic benchmarks). For 

HCl, the EPA identified chronic 

benchmark concentrations. We note that 

the benchmark for chronic HCl exposure 

to plants is greater than the reference 

concentration for chronic inhalation 

exposure for human health. This means 


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that where EPA includes regulatory 

requirements to prevent an exceedance 

of the reference concentration for 

human health, additional analyses for 

adverse environmental effects of HCl 

would not be necessary. 

For HF, EPA identified chronic 

benchmark concentrations for plants 

and evaluated chronic exposures to 

plants in the screening analysis. High 

concentrations of HF in the air have also 

been linked to fluorosis in livestock. 

However, the HF concentrations at 

which fluorosis in livestock occur are 

higher than those at which plant 

damage begins. Therefore, the 

benchmarks for plants are protective of 

both plants and livestock. 

e. Screening Methodology 

For the environmental risk screening 

analysis, the EPA first determined 

whether any petroleum refineries 

emitted any of the seven environmental 

HAP. For the petroleum refinery source 

categories, we identified emissions of 

cadmium, dioxins/furans, POM, 

mercury (both inorganic mercury and 

methyl mercury), lead, HCl and HF. 

Because one or more of the seven 

environmental HAP evaluated are 

emitted by at least one petroleum 

refinery, we proceeded to the second 

step of the evaluation. 

f. PB–HAP Methodology 

For cadmium, mercury, POM and 

dioxins/furans, the environmental 

screening analysis consists of two tiers, 

while lead is analyzed differently as 

discussed earlier. In the first tier, we 

determined whether the maximum 

facility-specific emission rates of each of 

the emitted environmental HAP were 

large enough to create the potential for 

adverse environmental effects under 

reasonable worst-case environmental 

conditions. These are the same 

environmental conditions used in the 

human multipathway exposure and risk 

screening analysis. 

To facilitate this step, TRIM.FaTE was 

run for each PB–HAP under 

hypothetical environmental conditions 

designed to provide conservatively high 

HAP concentrations. The model was set 

to maximize runoff from terrestrial 

parcels into the modeled lake, which in 

turn, maximized the chemical 

concentrations in the water, the 

sediments, and the fish. The resulting 

media concentrations were then used to 

back-calculate a screening threshold 

emission rate that corresponded to the 

relevant exposure benchmark 

concentration value for each assessment 

endpoint. To assess emissions from a 

facility, the reported emission rate for 

each PB–HAP was compared to the 

screening threshold emission rate for 

that PB–HAP for each assessment 

endpoint. If emissions from a facility do 

not exceed the Tier I threshold, the 

facility ‘‘passes’’ the screen, and 

therefore, is not evaluated further under 

the screening approach. If emissions 

from a facility exceed the Tier I 

threshold, we evaluate the facility 

further in Tier II. 

In Tier II of the environmental 

screening analysis, the screening 

emission thresholds are adjusted to 

account for local meteorology and the 

actual location of lakes in the vicinity of 

facilities that did not pass the Tier I 

screen. The modeling domain for each 

facility in the Tier II analysis consists of 

eight octants. Each octant contains five 

modeled soil concentrations at various 

distances from the facility (5 soil 

concentrations × 8 octants = total of 40 

soil concentrations per facility) and one 

lake with modeled concentrations for 

water, sediment and fish tissue. In the 

Tier II environmental risk screening 

analysis, the 40 soil concentration 

points are averaged to obtain an average 

soil concentration for each facility for 

each PB–HAP. For the water, sediment 

and fish tissue concentrations, the 

highest value for each facility for each 

pollutant is used. If emission 

concentrations from a facility do not 

exceed the Tier II threshold, the facility 

passes the screen, and is typically not 

evaluated further. If emissions from a 

facility exceed the Tier II threshold, the 

facility does not pass the screen and, 

therefore, may have the potential to 

cause adverse environmental effects. 

Such facilities are evaluated further to 

investigate factors such as the 

magnitude and characteristics of the 

area of exceedance. 

g. Acid Gas Methodology 

The environmental screening analysis 

evaluates the potential phytotoxicity 

and reduced productivity of plants due 

to chronic exposure to acid gases. The 

environmental risk screening 

methodology for acid gases is a singletier screen that compares the average 

off-site ambient air concentration over 

the modeling domain to ecological 

benchmarks for each of the acid gases. 

Because air concentrations are 

compared directly to the ecological 

benchmarks, emission-based thresholds 

are not calculated for acid gases as they 

are in the ecological risk screening 

methodology for PB–HAP. 

For purposes of ecological risk 

screening, EPA identifies a potential for 

adverse environmental effects to plant 

communities from exposure to acid 

gases when the average concentration of 

the HAP around a facility exceeds the 

LOAEL ecological benchmark. In such 

cases, we further investigate factors 

such as the magnitude and 

characteristics of the area of exceedance 

(e.g., land use of exceedance area, size 

of exceedance area) to determine if there 

is an adverse environmental effect. 

For further information on the 

environmental screening analysis 

approach, see section IV.C.5 of this 

preamble and the Draft Residual Risk 

Assessment for the Petroleum Refining 

Source Sector, which is available in the 

docket for this action (Docket ID 

Number EPA–HQ–OAR–2010–0682). 

7. How did we conduct facility-wide 

assessments? 

To put the source category risks in 

context, following the assessment 

approach outlined in the SAB (2010) 

review, we examine the risks from the 

entire ‘‘facility,’’ where the facility 

includes all HAP-emitting operations 

within a contiguous area and under 

common control. In other words, we 

examine the HAP emissions not only 

from the source category emission 

points of interest, but also emissions of 

HAP from all other emission sources at 

the facility for which we have data. 

The emissions inventories provided 

in response to the ICR included 

emissions information for all emission 

sources at the facilities that are part of 

the refineries source categories. 

Generally, only a few emission sources 

located at refineries are not subject to 

either Refinery MACT 1 or 2; the most 

notable are boilers, process heaters and 

internal combustion engines, which are 

addressed by other MACT standards. 

We analyzed risks due to the 

inhalation of HAP that are emitted 

‘‘facility-wide’’ for the populations 

residing within 50 km of each facility, 

consistent with the methods used for 

the source category analysis described 

above. For these facility-wide risk 

analyses, the modeled source category 

risks were compared to the facility-wide 

risks to determine the portion of facilitywide risks that could be attributed to 

each of the source categories addressed 

in this proposal. We specifically 

examined the facility that was 

associated with the highest estimates of 

risk and determined the percentage of 

that risk attributable to the source 

category of interest. The Draft Residual 

Risk Assessment for the Petroleum 

Refining Source Sector available 

through the docket for this action 

(Docket ID Number EPA–HQ–OAR– 

2010–0682) provides the methodology 

and results of the facility-wide analyses, 

including all facility-wide risks and the 

percentage of source category 

contribution to facility-wide risks. 


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16Short-term mobility is movement from one 

micro-environment to another over the course of 

hours or days. Long-term mobility is movement 

from one residence to another over the course of a 

lifetime. 

8. How did we consider uncertainties in 

risk assessment? 

In the Benzene NESHAP we 

concluded that risk estimation 

uncertainty should be considered in our 

decision-making under the ample 

margin of safety framework. Uncertainty 

and the potential for bias are inherent in 

all risk assessments, including those 

performed for this proposal. Although 

uncertainty exists, we believe that our 

approach, which used conservative 

tools and assumptions, ensures that our 

decisions are health protective and 

environmentally protective. A brief 

discussion of the uncertainties in the 

emissions datasets, dispersion 

modeling, inhalation exposure estimates 

and dose-response relationships follows 

below. A more thorough discussion of 

these uncertainties is included in the 

Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, 

which is available in the docket for this 

action (Docket ID Number EPA–HQ– 

OAR–2010–0682). 

a. Uncertainties in the Emission 

Datasets 

Although the development of the RTR 

datasets involved quality assurance/

quality control processes, the accuracy 

of emissions values will vary depending 

on the source of the data, the degree to 

which data are incomplete or missing, 

the degree to which assumptions made 

to complete the datasets are accurate, 

errors in emission estimates and other 

factors. The emission estimates 

considered in this analysis are annual 

totals for 2010, and they do not reflect 

short-term fluctuations during the 

course of a year or variations from year 

to year. The estimates of peak hourly 

emissions rates for the acute effects 

screening assessment were based on 

emission adjustment factors applied to 

the average annual hourly emission 

rates, which are intended to account for 

emission fluctuations due to normal 

facility operations. 

As discussed previously, we 

attempted to provide a consistent 

framework for reporting of emissions 

information by developing the refinery 

emissions estimation protocol and 

requesting that refineries follow the 

protocol when reporting emissions 

inventory data in response to the ICR. 

This protocol, called Emission 

Estimation Protocol for Petroleum 

Refineries, is available in the docket for 

this rulemaking (Docket Item Number 

EPA–HQ–OAR–2010–0682–0060). 

Additionally, we developed our own 

estimates of emissions that are based on 

the factors provided in the protocol and 

the REM Model. We developed emission 

estimates based on refinery unit 

capacities, which also provided an 

estimate of allowable emissions. We 

then conducted risk modeling using 

REM Model estimates and by locating 

emissions at the centroid of each 

refinery in an attempt to understand the 

risk associated with emissions from 

each refinery. Therefore, even if there 

were errors in the emission inventories 

reported in the ICR, as was the case in 

many instances, emissions for those 

facilities were also modeled using the 

protocol emission factors. The risk 

modeling of allowable emissions based 

on emission factors and unit capacities 

did not result in significantly different 

risk results than the actual emissions 

modeling runs. Results of the allowable 

emissions risk estimates are provided in 

the Draft Residual Risk Assessment for 

the Petroleum Refining Source Sector, 

which is available in Docket ID Number 

EPA–HQ–OAR–2010–0682. 

b. Uncertainties in Dispersion Modeling 

We recognize there is uncertainty in 

ambient concentration estimates 

associated with any model, including 

the EPA’s recommended regulatory 

dispersion model, AERMOD. In using a 

model to estimate ambient pollutant 

concentrations, the user chooses certain 

options to apply. For RTR assessments, 

we select some model options that have 

the potential to overestimate ambient air 

concentrations (e.g., not including 

plume depletion or pollutant 

transformation). We select other model 

options that have the potential to 

underestimate ambient impacts (e.g., not 

including building downwash). Other 

options that we select have the potential 

to either under- or overestimate ambient 

levels (e.g., meteorology and receptor 

locations). On balance, considering the 

directional nature of the uncertainties 

commonly present in ambient 

concentrations estimated by dispersion 

models, the approach we apply in the 

RTR assessments should yield unbiased 

estimates of ambient HAP 

concentrations. 

c. Uncertainties in Inhalation Exposure 

The EPA did not include the effects 

of human mobility on exposures in the 

assessment. Specifically, short-term 

mobility and long-term mobility 

between census blocks in the modeling 

domain were not considered.16 The 

approach of not considering short- or 

long-term population mobility does not 

bias the estimate of the theoretical MIR 

(by definition), nor does it affect the 

estimate of cancer incidence because the 

total population number remains the 

same. It does, however, affect the shape 

of the distribution of individual risks 

across the affected population, shifting 

it toward higher estimated individual 

risks at the upper end and reducing the 

number of people estimated to be at 

lower risks, thereby increasing the 

estimated number of people at specific 

high-risk levels (e.g., 1-in-10 thousand 

or 1-in-1 million). 

In addition, the assessment predicted 

the chronic exposures at the centroid of 

each populated census block as 

surrogates for the exposure 

concentrations for all people living in 

that block. Using the census block 

centroid to predict chronic exposures 

tends to over-predict exposures for 

people in the census block who live 

further from the facility and underpredict exposures for people in the 

census block who live closer to the 

facility. Thus, using the census block 

centroid to predict chronic exposures 

may lead to a potential understatement 

or overstatement of the true maximum 

impact, but is an unbiased estimate of 

average risk and incidence. We reduce 

this uncertainty by analyzing large 

census blocks near facilities using aerial 

imagery and adjusting the location of 

the block centroid to better represent the 

population in the block, as well as 

adding additional receptor locations 

where the block population is not well 

represented by a single location. 

The assessment evaluates the cancer 

inhalation risks associated with 

pollutant exposures over a 70-year 

period, which is the assumed lifetime of 

an individual. In reality, both the length 

of time that modeled emission sources 

at facilities actually operate (i.e., more 

or less than 70 years) and the domestic 

growth or decline of the modeled 

industry (i.e., the increase or decrease in 

the number or size of domestic 

facilities) will influence the future risks 

posed by a given source or source 

category. Depending on the 

characteristics of the industry, these 

factors will, in most cases, result in an 

overestimate both in individual risk 

levels and in the total estimated number 

of cancer cases. However, in the 

unlikely scenario where a facility 

maintains, or even increases, its 

emissions levels over a period of more 

than 70 years, residents live beyond 70 

years at the same location, and the 

residents spend most of their days at 

that location, then the cancer inhalation 

risks could potentially be 

underestimated. However, annual 

cancer incidence estimates from 

exposures to emissions from these 


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17U.S. EPA. National-Scale Air Toxics 

Assessment for 1996. (EPA 453/R–01–003; January 

2001; page 85.) 

18 IRIS glossary (http://ofmpub.epa.gov/sor_

internet/registry/termreg/searchandretrieve/

glossariesandkeywordlists/search.do?details=&

glossaryName=IRIS%20Glossary). 

19An exception to this is the URE for benzene, 

which is considered to cover a range of values, each 

end of which is considered to be equally plausible, 

and which is based on maximum likelihood 

estimates. 

20According to the NRC report, Science and 

Judgment in Risk Assessment (NRC, 1994) 

‘‘[Default] options are generic approaches, based on 

general scientific knowledge and policy judgment, 

that are applied to various elements of the risk 

assessment process when the correct scientific 

model is unknown or uncertain.’’ The 1983 NRC 

report, Risk Assessment in the Federal Government: 

Managing the Process, defined default option as 

‘‘the option chosen on the basis of risk assessment 

policy that appears to be the best choice in the 

absence of data to the contrary’’ (NRC, 1983a, p. 63). 

Therefore, default options are not rules that bind 

the Agency; rather, the Agency may depart from 

them in evaluating the risks posed by a specific 

substance when it believes this to be appropriate. 

In keeping with EPA’s goal of protecting public 

health and the environment, default assumptions 

are used to ensure that risk to chemicals is not 

underestimated (although defaults are not intended 

to overtly overestimate risk). See EPA, 2004, An 

Examination of EPA Risk Assessment Principles 

and Practices, EPA/100/B–04/001 available at: 

http://www.epa.gov/osa/pdfs/ratf-final.pdf. 

sources would not be affected by the 

length of time an emissions source 

operates. 

The exposure estimates used in these 

analyses assume chronic exposures to 

ambient (outdoor) levels of pollutants. 

Because most people spend the majority 

of their time indoors, actual exposures 

may not be as high, depending on the 

characteristics of the pollutants 

modeled. For many of the HAP, indoor 

levels are roughly equivalent to ambient 

levels, but for very reactive pollutants or 

larger particles, indoor levels are 

typically lower. This factor has the 

potential to result in an overestimate of 

25 to 30 percent of exposures.17

In addition to the uncertainties 

highlighted above, there are several 

factors specific to the acute exposure 

assessment that should be highlighted. 

The accuracy of an acute inhalation 

exposure assessment depends on the 

simultaneous occurrence of 

independent factors that may vary 

greatly, such as hourly emissions rates, 

meteorology and human activity 

patterns. In this assessment, we assume 

that individuals remain for 1 hour at the 

point of maximum ambient 

concentration as determined by the cooccurrence of peak emissions and worstcase meteorological conditions. These 

assumptions would tend to be worstcase actual exposures as it is unlikely 

that a person would be located at the 

point of maximum exposure during the 

time when peak emissions and worstcase meteorological conditions occur 

simultaneously. 

d. Uncertainties in Dose-Response 

Relationships 

There are uncertainties inherent in 

the development of the dose-response 

values used in our risk assessments for 

cancer effects from chronic exposures 

and non-cancer effects from both 

chronic and acute exposures. Some 

uncertainties may be considered 

quantitatively, and others generally are 

expressed in qualitative terms. We note 

as a preface to this discussion a point on 

dose-response uncertainty that is 

brought out in the EPA’s 2005 Cancer 

Guidelines; namely, that ‘‘the primary 

goal of EPA actions is protection of 

human health; accordingly, as an 

Agency policy, risk assessment 

procedures, including default options 

that are used in the absence of scientific 

data to the contrary, should be health 

protective’’ (EPA 2005 Cancer 

Guidelines, pages 1–7). This is the 

approach followed here as summarized 

in the next several paragraphs. A 

complete detailed discussion of 

uncertainties and variability in doseresponse relationships is given in the 

Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, 

which is available in the docket for this 

action (Docket ID Number EPA–HQ– 

OAR–2010–0682). 

Cancer URE values used in our risk 

assessments are those that have been 

developed to generally provide an upper 

bound estimate of risk. That is, they 

represent a ‘‘plausible upper limit to the 

true value of a quantity’’ (although this 

is usually not a true statistical 

confidence limit).18 In some 

circumstances, the true risk could be as 

low as zero; however, in other 

circumstances, the risk could also be 

greater.19 When developing an upperbound estimate of risk and to provide 

risk values that do not underestimate 

risk, health-protective default 

approaches are generally used. To err on 

the side of ensuring adequate healthprotection, the EPA typically uses the 

upper bound estimates rather than 

lower bound or central tendency 

estimates in our risk assessments, an 

approach that may have limitations for 

other uses (e.g., priority-setting or 

expected benefits analysis). 

Chronic non-cancer RfC and reference 

dose (RfD) values represent chronic 

exposure levels that are intended to be 

health-protective levels. Specifically, 

these values provide an estimate (with 

uncertainty spanning perhaps an order 

of magnitude) of a continuous 

inhalation exposure (RfC) or a daily oral 

exposure (RfD) to the human population 

(including sensitive subgroups) that is 

likely to be without an appreciable risk 

of deleterious effects during a lifetime. 

To derive values that are intended to be 

‘‘without appreciable risk,’’ the 

methodology relies upon an uncertainty 

factor (UF) approach (U.S. EPA, 1993, 

1994) which considers uncertainty, 

variability and gaps in the available 

data. The UF are applied to derive 

reference values that are intended to 

protect against appreciable risk of 

deleterious effects. The UF are 

commonly default values,20 e.g., factors 

of 10 or 3, used in the absence of 

compound-specific data; where data are 

available, UF may also be developed 

using compound-specific information. 

When data are limited, more 

assumptions are needed and more UF 

are used. Thus, there may be a greater 

tendency to overestimate risk in the 

sense that further study might support 

development of reference values that are 

higher (i.e., less potent) because fewer 

default assumptions are needed. 

However, for some pollutants, it is 

possible that risks may be 

underestimated. 

While collectively termed ‘‘UF,’’ these 

factors account for a number of different 

quantitative considerations when using 

observed animal (usually rodent) or 

human toxicity data in the development 

of the RfC. The UF are intended to 

account for: (1) Variation in 

susceptibility among the members of the 

human population (i.e., inter-individual 

variability); (2) uncertainty in 

extrapolating from experimental animal 

data to humans (i.e., interspecies 

differences); (3) uncertainty in 

extrapolating from data obtained in a 

study with less-than-lifetime exposure 

(i.e., extrapolating from sub-chronic to 

chronic exposure); (4) uncertainty in 

extrapolating the observed data to 

obtain an estimate of the exposure 

associated with no adverse effects; and 

(5) uncertainty when the database is 

incomplete or there are problems with 

the applicability of available studies. 

Many of the UF used to account for 

variability and uncertainty in the 

development of acute reference values 

are quite similar to those developed for 

chronic durations, but they more often 

use individual UF values that may be 

less than 10. The UF are applied based 

on chemical-specific or health effectspecific information (e.g., simple 

irritation effects do not vary appreciably 

between human individuals, hence a 

value of 3 is typically used), or based on 

the purpose for the reference value (see 

the following paragraph). The UF 


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21 In the context of this discussion, the term 

‘‘uncertainty’’ as it pertains to exposure and risk 

encompasses both variability in the range of 

expected inputs and screening results due to 

existing spatial, temporal, and other factors, as well 

as uncertainty in being able to accurately estimate 

the true result. 

applied in acute reference value 

derivation include: (1) Heterogeneity 

among humans; (2) uncertainty in 

extrapolating from animals to humans; 

(3) uncertainty in lowest observable 

adverse effect (exposure) level to no 

observed adverse effect (exposure) level 

adjustments; and (4) uncertainty in 

accounting for an incomplete database 

on toxic effects of potential concern. 

Additional adjustments are often 

applied to account for uncertainty in 

extrapolation from observations at one 

exposure duration (e.g., 4 hours) to 

derive an acute reference value at 

another exposure duration (e.g., 1 hour). 

Not all acute reference values are 

developed for the same purpose and 

care must be taken when interpreting 

the results of an acute assessment of 

human health effects relative to the 

reference value or values being 

exceeded. Where relevant to the 

estimated exposures, the lack of shortterm dose-response values at different 

levels of severity should be factored into 

the risk characterization as potential 

uncertainties. 

Although every effort is made to 

identify appropriate human health effect 

dose-response assessment values for all 

pollutants emitted by the sources in this 

risk assessment, some HAP emitted by 

these source categories are lacking doseresponse assessments. Accordingly, 

these pollutants cannot be included in 

the quantitative risk assessment, which 

could result in quantitative estimates 

understating HAP risk. To help to 

alleviate this potential underestimate, 

where we conclude similarity with a 

HAP for which a dose-response 

assessment value is available, we use 

that value as a surrogate for the 

assessment of the HAP for which no 

value is available. To the extent use of 

surrogates indicates appreciable risk, we 

may identify a need to increase priority 

for new IRIS assessment of that 

substance. We additionally note that, 

generally speaking, HAP of greatest 

concern due to environmental 

exposures and hazard are those for 

which dose-response assessments have 

been performed, reducing the likelihood 

of understating risk. Further, HAP not 

included in the quantitative assessment 

are assessed qualitatively and 

considered in the risk characterization 

that informs the risk management 

decisions, including with regard to 

consideration of HAP reductions 

achieved by various control options. 

For a group of compounds that are 

unspeciated (e.g., glycol ethers), we 

conservatively use the most protective 

reference value of an individual 

compound in that group to estimate 

risk. Similarly, for an individual 

compound in a group (e.g., ethylene 

glycol diethyl ether) that does not have 

a specified reference value, we also 

apply the most protective reference 

value from the other compounds in the 

group to estimate risk. 

e. Uncertainties in the Multipathway 

Assessment 

For each source category, we 

generally rely on site-specific levels of 

PB-HAP emissions to determine 

whether a refined assessment of the 

impacts from multipathway exposures 

is necessary. This determination is 

based on the results of a two-tiered 

screening analysis that relies on the 

outputs from models that estimate 

environmental pollutant concentrations 

and human exposures for four PB-HAP. 

Two important types of uncertainty 

associated with the use of these models 

in RTR risk assessments and inherent to 

any assessment that relies on 

environmental modeling are model 

uncertainty and input uncertainty.21

Model uncertainty concerns whether 

the selected models are appropriate for 

the assessment being conducted and 

whether they adequately represent the 

actual processes that might occur for 

that situation. An example of model 

uncertainty is the question of whether 

the model adequately describes the 

movement of a pollutant through the 

soil. This type of uncertainty is difficult 

to quantify. However, based on feedback 

received from previous EPA SAB 

reviews and other reviews, we are 

confident that the models used in the 

screen are appropriate and state-of-theart for the multipathway risk 

assessments conducted in support of 

RTR. 

Input uncertainty is concerned with 

how accurately the models have been 

configured and parameterized for the 

assessment at hand. For Tier I of the 

multipathway screen, we configured the 

models to avoid underestimating 

exposure and risk. This was 

accomplished by selecting upper-end 

values from nationally-representative 

data sets for the more influential 

parameters in the environmental model, 

including selection and spatial 

configuration of the area of interest, lake 

location and size, meteorology, surface 

water and soil characteristics and 

structure of the aquatic food web. We 

also assume an ingestion exposure 

scenario and values for human exposure 

factors that represent reasonable 

maximum exposures. 

In Tier II of the multipathway 

assessment, we refine the model inputs 

to account for meteorological patterns in 

the vicinity of the facility versus using 

upper-end national values and we 

identify the actual location of lakes near 

the facility rather than the default lake 

location that we apply in Tier I. By 

refining the screening approach in Tier 

II to account for local geographical and 

meteorological data, we decrease the 

likelihood that concentrations in 

environmental media are overestimated, 

thereby increasing the usefulness of the 

screen. The assumptions and the 

associated uncertainties regarding the 

selected ingestion exposure scenario are 

the same for Tier I and Tier II. 

For both Tiers I and II of the 

multipathway assessment, our approach 

to addressing model input uncertainty is 

generally cautious. We choose model 

inputs from the upper end of the range 

of possible values for the influential 

parameters used in the models, and we 

assume that the exposed individual 

exhibits ingestion behavior that would 

lead to a high total exposure. This 

approach reduces the likelihood of not 

identifying high risks for adverse 

impacts. 

Despite the uncertainties, when 

individual pollutants or facilities do 

screen out, we are confident that the 

potential for adverse multipathway 

impacts on human health is very low. 

On the other hand, when individual 

pollutants or facilities do not screen out, 

it does not mean that multipathway 

impacts are significant, only that we 

cannot rule out that possibility and that 

a refined multipathway analysis for the 

site might be necessary to obtain a more 

accurate risk characterization for the 

source categories. 

For further information on 

uncertainties and the Tier I and II 

screening methods, refer to the risk 

document Appendix 4, Technical 

Support Document for TRIM-Based 

Multipathway Tiered Screening 

Methodology for RTR. 

f. Uncertainties in the Environmental 

Risk Screening Assessment 

For each source category, we 

generally rely on site-specific levels of 

environmental HAP emissions to 

perform an environmental screening 

assessment. The environmental 

screening assessment is based on the 

outputs from models that estimate 

environmental HAP concentrations. The 

same models, specifically the 

TRIM.FaTE multipathway model and 

the AERMOD air dispersion model, are 

used to estimate environmental HAP 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36898 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

22 In the context of this discussion, the term 

‘‘uncertainty,’’ as it pertains to exposure and risk 

assessment, encompasses both variability in the 

range of expected inputs and screening results due 

to existing spatial, temporal, and other factors, as 

well as uncertainty in being able to accurately 

estimate the true result. 

concentrations for both the human 

multipathway screening analysis and for 

the environmental screening analysis. 

Therefore, both screening assessments 

have similar modeling uncertainties. 

Two important types of uncertainty 

associated with the use of these models 

in RTR environmental screening 

assessments—and inherent to any 

assessment that relies on environmental 

modeling—are model uncertainty and 

input uncertainty.22

Model uncertainty concerns whether 

the selected models are appropriate for 

the assessment being conducted and 

whether they adequately represent the 

movement and accumulation of 

environmental HAP emissions in the 

environment. For example, does the 

model adequately describe the 

movement of a pollutant through the 

soil? This type of uncertainty is difficult 

to quantify. However, based on feedback 

received from previous EPA SAB 

reviews and other reviews, we are 

confident that the models used in the 

screen are appropriate and state-of-theart for the environmental risk 

assessments conducted in support of 

our RTR analyses. 

Input uncertainty is concerned with 

how accurately the models have been 

configured and parameterized for the 

assessment at hand. For Tier I of the 

environmental screen for PB–HAP, we 

configured the models to avoid 

underestimating exposure and risk to 

reduce the likelihood that the results 

indicate the risks are lower than they 

actually are. This was accomplished by 

selecting upper-end values from 

nationally-representative data sets for 

the more influential parameters in the 

environmental model, including 

selection and spatial configuration of 

the area of interest, the location and size 

of any bodies of water, meteorology, 

surface water and soil characteristics 

and structure of the aquatic food web. 

In Tier I, we used the maximum facilityspecific emissions for cadmium 

compounds, dioxins/furans, POM, and 

mercury and each of the media when 

comparing to ecological benchmarks. 

This is consistent with the conservative 

design of Tier I of the screen. In Tier II 

of the environmental screening analysis 

for PB–HAP, we refine the model inputs 

to account for meteorological patterns in 

the vicinity of the facility versus using 

upper-end national values, and we 

identify the locations of water bodies 

near the facility location. By refining the 

screening approach in Tier II to account 

for local geographical and 

meteorological data, we decrease the 

likelihood that concentrations in 

environmental media are overestimated, 

thereby increasing the usefulness of the 

screen. To better represent widespread 

impacts, the modeled soil 

concentrations are averaged in Tier II to 

obtain one average soil concentration 

value for each facility and for each PB– 

HAP. For PB–HAP concentrations in 

water, sediment and fish tissue, the 

highest value for each facility for each 

pollutant is used. 

For the environmental screening 

assessment for acid gases, we employ a 

single-tiered approach. We use the 

modeled air concentrations and 

compare those with ecological 

benchmarks. 

For both Tiers I and II of the 

environmental screening assessment, 

our approach to addressing model input 

uncertainty is generally cautious. We 

choose model inputs from the upper 

end of the range of possible values for 

the influential parameters used in the 

models, and we assume that the 

exposed organism (e.g., invertebrate, 

fish) exhibits ingestion behavior that 

would lead to a high total exposure. 

This approach reduces the likelihood of 

not identifying potential risks for 

adverse environmental impacts. 

Uncertainty also exists in the 

ecological benchmarks for the 

environmental risk screening analysis. 

We established a hierarchy of preferred 

benchmark sources to allow selection of 

benchmarks for each environmental 

HAP at each ecological assessment 

endpoint. In general, EPA benchmarks 

used at a programmatic level (e.g., 

Office of Water, Superfund Program) 

were used if available. If not, we used 

EPA benchmarks used in regional 

programs (e.g., Superfund). If 

benchmarks were not available at a 

programmatic or regional level, we used 

benchmarks developed by other 

agencies (e.g., NOAA) or by state 

agencies. 

In all cases (except for lead, which 

was evaluated through a comparison to 

the NAAQS), we searched for 

benchmarks at the following three effect 

levels, as described in section III.A.6 of 

this preamble: 

1. A no-effect level (i.e., NOAEL). 

2. Threshold-effect level (i.e., 

LOAEL). 

3. Probable effect level (i.e., PEL). 

For some ecological assessment 

endpoint/environmental HAP 

combinations, we could identify 

benchmarks for all three effect levels, 

but for most, we could not. In one case, 

where different agencies derived 

significantly different numbers to 

represent a threshold for effect, we 

included both. In several cases, only a 

single benchmark was available. In 

cases where multiple effect levels were 

available for a particular PB–HAP and 

assessment endpoint, we used all of the 

available effect levels to help us to 

determine whether risk exists and if the 

risks could be considered significant 

and widespread. 

The EPA evaluated the following 

seven HAP in the environmental risk 

screening assessment: Cadmium, 

dioxins/furans, POM, mercury (both 

inorganic mercury and methyl mercury), 

lead compounds, HCl and HF. These 

seven HAP represent pollutants that can 

cause adverse impacts for plants and 

animals either through direct exposure 

to HAP in the air or through exposure 

to HAP that is deposited from the air 

onto soils and surface waters. These 

seven HAP also represent those HAP for 

which we can conduct a meaningful 

environmental risk screening 

assessment. For other HAP not included 

in our screening assessment, the model 

has not been parameterized such that it 

can be used for that purpose. In some 

cases, depending on the HAP, we may 

not have appropriate multipathway 

models that allow us to predict the 

concentration of that pollutant. The EPA 

acknowledges that other HAP beyond 

the seven HAP that we are evaluating 

may have the potential to cause adverse 

environmental effects and, therefore, the 

EPA may evaluate other relevant HAP in 

the future, as modeling science and 

resources allow. 

Further information on uncertainties 

and the Tier I and II environmental 

screening methods is provided in 

Appendix 5 of the document Technical 

Support Document for TRIM-Based 

Multipathway Tiered Screening 

Methodology for RTR: Summary of 

Approach and Evaluation. Also, see the 

Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, 

available in the docket for this action 

(Docket ID Number EPA–HQ–OAR– 

2010–0682). 

B. How did we consider the risk results 

in making decisions for this proposal? 

As discussed in section II.A.1 of this 

preamble, in evaluating and developing 

standards under CAA section 112(f)(2), 

we apply a two-step process to address 

residual risk. In the first step, the EPA 

determines whether risks are acceptable. 

This determination ‘‘considers all health 

information, including risk estimation 

uncertainty, and includes a presumptive 

limit on maximum individual lifetime 


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23Although defined as ‘‘maximum individual 

risk,’’ MIR refers only to cancer risk. MIR, one 

metric for assessing cancer risk, is the estimated 

risk were an individual exposed to the maximum 

level of a pollutant for a lifetime. 

24EPA’s responses to this and all other key 

recommendations of the SAB’s advisory on RTR 

risk assessment methodologies (which is available 

at: http://yosemite.epa.gov/sab/sabproduct.nsf/

4AB3966E263D943A8525771F00668381/$File/EPASAB-10-007-unsigned.pdf) are outlined in a memo 

to this rulemaking docket from David Guinnup 

entitled, EPA’s Actions in Response to the Key 

Recommendations of the SAB Review of RTR Risk 

Assessment Methodologies. 

[cancer] risk (MIR) 23 of approximately 

[1-in-10 thousand] [i.e., 100-in-1 

million].’’ 54 FR 38045, September 14, 

1989. If risks are unacceptable, the EPA 

must determine the emissions standards 

necessary to bring risks to an acceptable 

level without considering costs. In the 

second step of the process, the EPA 

considers whether the emissions 

standards provide an ample margin of 

safety ‘‘in consideration of all health 

information, including the number of 

persons at risk levels higher than 

approximately 1-in-1 million, as well as 

other relevant factors, including costs 

and economic impacts, technological 

feasibility, and other factors relevant to 

each particular decision.’’ Id. The EPA 

must promulgate tighter emission 

standards if necessary to provide an 

ample margin of safety. 

In past residual risk actions, the EPA 

considered a number of human health 

risk metrics associated with emissions 

from the categories under review, 

including the MIR, the number of 

persons in various risk ranges, cancer 

incidence, the maximum non-cancer HI 

and the maximum acute non-cancer 

hazard. See, e.g., 72 FR 25138, May 3, 

2007; 71 FR 42724, July 27, 2006. The 

EPA considered this health information 

for both actual and allowable emissions. 

See, e.g., 75 FR 65068, October 21, 2010, 

and 75 FR 80220, December 21, 2010). 

The EPA also discussed risk estimation 

uncertainties and considered the 

uncertainties in the determination of 

acceptable risk and ample margin of 

safety in these past actions. The EPA 

considered this same type of 

information in support of this action. 

The agency is considering these 

various measures of health information 

to inform our determinations of risk 

acceptability and ample margin of safety 

under CAA section 112(f). As explained 

in the Benzene NESHAP, ‘‘the first step 

of judgment on acceptability cannot be 

reduced to any single factor,’’ and thus 

‘‘[t]he Administrator believes that the 

acceptability of risk under [previous] 

section 112 is best judged on the basis 

of a broad set of health risk measures 

and information.’’ 54 FR 38046, 

September 14, 1989. Similarly, with 

regard to making the ample margin of 

safety determination, ‘‘the Agency again 

considers all of the health risk and other 

health information considered in the 

first step. Beyond that information, 

additional factors relating to the 

appropriate level of control will also be 

considered, including cost and 

economic impacts of controls, 

technological feasibility, uncertainties, 

and any other relevant factors.’’ Id. 

The Benzene NESHAP approach 

provides flexibility regarding factors the 

EPA may consider in making 

determinations and how the EPA may 

weigh those factors for each source 

category. In responding to comment on 

our policy under the Benzene NESHAP, 

the EPA explained that: 

[t]he policy chosen by the Administrator 

permits consideration of multiple measures 

of health risk. Not only can the MIR figure 

be considered, but also incidence, the 

presence of non-cancer health effects, and the 

uncertainties of the risk estimates. In this 

way, the effect on the most exposed 

individuals can be reviewed as well as the 

impact on the general public. These factors 

can then be weighed in each individual case. 

This approach complies with the Vinyl 

Chloride mandate that the Administrator 

ascertain an acceptable level of risk to the 

public by employing [her] expertise to assess 

available data. It also complies with the 

Congressional intent behind the CAA, which 

did not exclude the use of any particular 

measure of public health risk from the EPA’s 

consideration with respect to CAA section 

112 regulations, and thereby implicitly 

permits consideration of any and all 

measures of health risk which the 

Administrator, in [her] judgment, believes are 

appropriate to determining what will ‘protect 

the public health.’ 

See 54 FR at 38057, September 14, 1989. 

Thus, the level of the MIR is only one 

factor to be weighed in determining 

acceptability of risks. The Benzene 

NESHAP explained that ‘‘an MIR of 

approximately one in 10 thousand 

should ordinarily be the upper end of 

the range of acceptability. As risks 

increase above this benchmark, they 

become presumptively less acceptable 

under CAA section 112, and would be 

weighed with the other health risk 

measures and information in making an 

overall judgment on acceptability. Or, 

the Agency may find, in a particular 

case, that a risk that includes MIR less 

than the presumptively acceptable level 

is unacceptable in the light of other 

health risk factors.’’ Id. at 38045. 

Similarly, with regard to the ample 

margin of safety analysis, the EPA stated 

in the Benzene NESHAP that: ‘‘EPA 

believes the relative weight of the many 

factors that can be considered in 

selecting an ample margin of safety can 

only be determined for each specific 

source category. This occurs mainly 

because technological and economic 

factors (along with the health-related 

factors) vary from source category to 

source category.’’ Id. at 38061. We also 

consider the uncertainties associated 

with the various risk analyses, as 

discussed earlier in this preamble, in 

our determinations of acceptability and 

ample margin of safety. 

The EPA notes that it has not 

considered certain health information to 

date in making residual risk 

determinations. At this time, we do not 

attempt to quantify those HAP risks that 

may be associated with emissions from 

other facilities that do not include the 

source categories in question, mobile 

source emissions, natural source 

emissions, persistent environmental 

pollution or atmospheric transformation 

in the vicinity of the sources in these 

categories. 

The agency understands the potential 

importance of considering an 

individual’s total exposure to HAP in 

addition to considering exposure to 

HAP emissions from the source category 

and facility. We recognize that such 

consideration may be particularly 

important when assessing non-cancer 

risks, where pollutant-specific health 

reference levels (e.g., RfCs) are based on 

the assumption that thresholds exist for 

adverse health effects. For example, the 

agency recognizes that, although 

exposures attributable to emissions from 

a source category or facility alone may 

not indicate the potential for increased 

risk of adverse non-cancer health effects 

in a population, the exposures resulting 

from emissions from the facility in 

combination with emissions from all of 

the other sources (e.g., other facilities) to 

which an individual is exposed may be 

sufficient to result in increased risk of 

adverse non-cancer health effects. In 

May 2010, the SAB advised the EPA 

‘‘that RTR assessments will be most 

useful to decision makers and 

communities if results are presented in 

the broader context of aggregate and 

cumulative risks, including background 

concentrations and contributions from 

other sources in the area.’’ 24

In response to the SAB 

recommendations, the EPA is 

incorporating cumulative risk analyses 

into its RTR risk assessments, including 

those reflected in this proposal. The 

agency is: (1) Conducting facility-wide 

assessments, which include source 

category emission points as well as 

other emission points within the 

facilities; (2) considering sources in the 

same category whose emissions result in 

exposures to the same individuals; and 

(3) for some persistent and 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36900 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

25The EPA has authority under CAA section 

112(d)(2) and (d)(3) to set MACT standards for 

previously unregulated emission points. EPA also 

retains the discretion to revise a MACT standard 

under the authority of Section 112(d)(2) and (3), see 

Portland Cement Ass’n v. EPA, 665 F.3d 177, 189 

(D.C. Cir. 2011), such as when it identifies an error 

in the original standard. See also Medical Waste 

Institute v. EPA, 645 F. 3d at 426 (upholding EPA 

action establishing MACT floors, based on postcompliance data, when originally-established floors 

were improperly established). 

bioaccumulative pollutants, analyzing 

the ingestion route of exposure. In 

addition, the RTR risk assessments have 

always considered aggregate cancer risk 

from all carcinogens and aggregate noncancer hazard indices from all noncarcinogens affecting the same target 

organ system. 

Although we are interested in placing 

source category and facility-wide HAP 

risks in the context of total HAP risks 

from all sources combined in the 

vicinity of each source, we are 

concerned about the uncertainties of 

doing so. Because we have not 

conducted in-depth studies of risks due 

to emissions from sources other those at 

refineries subject to this RTR review, 

such estimates of total HAP risks would 

have significantly greater associated 

uncertainties than the source category or 

facility-wide estimates. Such aggregate 

or cumulative assessments would 

compound those uncertainties, making 

the assessments too unreliable. 

C. How did we perform the technology 

review? 

Our technology review focused on the 

identification and evaluation of 

developments in practices, processes 

and control technologies that have 

occurred since the MACT standards 

were promulgated. Where we identified 

such developments, in order to inform 

our decision of whether it is 

‘‘necessary’’ to revise the emissions 

standards, we analyzed the technical 

feasibility of applying these 

developments, and the estimated costs, 

energy implications, non-air 

environmental impacts, as well as 

considering the emission reductions. 

We also considered the appropriateness 

of applying controls to new sources 

versus retrofitting existing sources. 

Based on our analyses of the available 

data and information, we identified 

potential developments in practices, 

processes and control technologies. For 

this exercise, we considered any of the 

following to be a ‘‘development’’: 

• Any add-on control technology or 

other equipment that was not identified 

and considered during development of 

the original MACT standards. 

• Any improvements in add-on 

control technology or other equipment 

(that were identified and considered 

during development of the original 

MACT standards) that could result in 

additional emissions reduction. 

• Any work practice or operational 

procedure that was not identified or 

considered during development of the 

original MACT standards. 

• Any process change or pollution 

prevention alternative that could be 

broadly applied to the industry and that 

was not identified or considered during 

development of the original MACT 

standards. 

• Any significant changes in the cost 

(including cost effectiveness) of 

applying controls (including controls 

the EPA considered during the 

development of the original MACT 

standards). 

We reviewed a variety of data sources 

in our investigation of potential 

practices, processes or controls to 

consider. Among the sources we 

reviewed were the NESHAP for various 

industries that were promulgated since 

the MACT standards being reviewed in 

this action. We reviewed the regulatory 

requirements and/or technical analyses 

associated with these regulatory actions 

to identify any practices, processes and 

control technologies considered in these 

efforts that could be applied to emission 

sources subject to Refinery MACT 1 or 

2, as well as the costs, non-air impacts 

and energy implications associated with 

the use of these technologies. 

Additionally, we requested information 

from facilities as described in section 

II.C of this preamble. Finally, we 

reviewed information from other 

sources, such as state and/or local 

permitting agency databases and 

industry-supported databases. 

IV. Analytical Results and Proposed 

Decisions 

A. What actions are we taking pursuant 

to CAA sections 112(d)(2) and 

112(d)(3)? 

In this action, we are proposing the 

following revisions to the Refinery 

MACT 1 and 2 standards pursuant to 

CAA section 112(d)(2) and (3) 25: (1) 

Adding MACT standards for DCU 

decoking operations; (2) revising the 

CRU purge vent pressure exemption; (3) 

adding operational requirements for 

flares used as air pollution control 

devices (APCD) in Refinery MACT 1 

and 2; and (4) adding requirements and 

clarifications for vent control bypasses 

in Refinery MACT 1. The results and 

proposed decisions based on the 

analyses performed pursuant to CAA 

section 112(d)(2) and (3) are presented 

below. 

1. Delayed Coking Units 

a. Description of Delayed Coker Process 

Operations and Emissions 

We are proposing to establish MACT 

standards specific to the DCU pursuant 

to CAA section 112(d)(2) and (3). The 

DCU uses thermal cracking to upgrade 

heavy feedstocks and to produce 

petroleum coke. Unlike most other 

refinery operations that are continuous, 

the DCU operates in a semi-batch 

system. Most DCU consist of a large 

process heater, two or more coking 

drums, and a single product distillation 

column. The DCU feed is actually fed to 

the unit’s distillation column. Bottoms 

from the distillation column are heated 

to near cracking temperatures and the 

resulting heavy oil is fed to one of the 

coking drums. As the cracking reactions 

occur, coke is produced in the drum and 

begins to fill the drum with sponge-like 

solid coke material. During this process, 

the DCU is a closed system, with the 

produced gas streams piped to the unit’s 

distillation column for product 

recovery. 

When the first coke drum becomes 

filled with coke, the feed is diverted to 

the second coke drum and processing 

continues via the second coke drum. 

The full coke drum, which is no longer 

receiving oil feed, is taken through a 

number of steps, collectively referred to 

as decoking operations, to remove the 

coke from the drum and prepare the 

drum for subsequent oil feed processing. 

The decoking steps include: purging, 

cooling/quenching, venting, draining, 

deheading, and coke cutting. A 

description of these steps and the 

potential emissions from these activities 

are provided in the next several 

paragraphs. Once the coke is removed, 

the vessel is re-sealed (i.e., the drain 

valve is closed and the ‘‘head’’ is reattached), pressure tested (typically 

using steam), purged to remove oxygen, 

then slowly heated to processing 

temperatures so it can go back on-line. 

When the second coke drum becomes 

filled with coke, feed is diverted back to 

the first coke drum and the second 

drum is then decoked. In this manner, 

the DCU allows for continuous 

processing of oil even though the 

individual coke drums operate in 

cyclical batch fashion. 

The first step in decoking operations 

is to purge the coke drum with steam. 

This serves to cool the coke bed and to 

flush oil or reaction products from the 

coke bed. The steam purge is initially 

sent to the product distillation column 

and then diverted to the unit’s 

blowdown system. The blowdown 

system serves to condense the steam 

and other liquids entrained in the 


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steam. Nearly all DCU operate a ’’closed 

blowdown’’ system, such that 

uncondensed gases from the blowdown 

system are sent to the product 

distillation column or the facility’s light 

gas plant, recovered as fuel gas, or 

combusted in a flare. In an open 

blowdown system, these uncondensed 

gases would be vented directly to 

atmosphere. The DCU vent discharge to 

the blowdown system is specifically 

defined in Refinery MACT 1 as the 

‘‘delayed coker vent.’’ 

The next step in the decoking process 

is cooling/quenching the coke drum and 

its contents via the addition of water, 

commonly referred to as quench water, 

at the bottom of the coke drum. The 

water added to the vessel quickly turns 

to steam due to the high temperature of 

the coke bed. The water/steam helps to 

further cool the coke bed and ‘‘quench’’ 

any residual coking reactions that may 

still occur within the hot coke bed. As 

with the steam purge, steam off-gas from 

the cooling/quenching cycle is 

recovered in the unit’s blowdown 

system and this vent discharge is 

specifically defined in Refinery MACT 1 

as the ‘‘delayed coker vent.’’ 

After several hours, the coke drum is 

sufficiently cooled so that the water 

level in the drum can be raised to 

entirely cover the coke bed. Although 

water covers the coke bed, the upper 

portion of the coke bed may still be well 

above 212 degrees Fahrenheit (°F) and 

will continue to generate steam. In fact, 

since the coke drum vessel pressure is 

greater than atmospheric pressure, the 

equilibrium boiling point of water in the 

vessel is greater than 212 °F. Therefore, 

the water at the top of the coke drum is 

typically well above 212 °F 

(superheated water). As the coke drum 

and its contents continue to cool from 

the evaporative cooling effect of the 

steam generation, the steam generation 

rate and the pressure within the vessel 

will decrease. 

Owners or operators of DCU may use 

different indicators or set points to 

determine when the system has cooled 

sufficiently to move to the venting step; 

however, one of the most common 

indicators monitored is the pressure of 

the coke drum vessel (or steam vent line 

just above the coke drum, where steam 

exits the coke drum en route to the 

blowdown system). When the vessel has 

cooled sufficiently (e.g., when the coke 

drum vessel pressure reaches the 

desired set point), valves are opened to 

allow the steam generated in the coke 

drum to vent directly to the atmosphere 

rather than the closed blowdown 

system. This vent is commonly referred 

to as the ‘‘coker steam vent’’ and is 

typically the first direct atmospheric 

emission release during the decoking 

operations when an enclosed blowdown 

system is used. While this vent gas 

contains predominately steam, methane 

and ethane, a variety of HAP are also 

emitted with this steam. These HAP 

include light aromatics (e.g., benzene, 

toluene, and xylene) and light POM 

(predominately naphthalene and 2- 

methyl naphthalene). The level of HAP 

emitted from the DCU has been found 

to be a function of the quantity of steam 

generated (see the technical 

memorandum entitled Impacts 

Estimates for Delayed Coking Units in 

Docket ID Number EPA–HQ–OAR– 

2010–0682). 

In general, the next step in the 

decoking process is draining the water 

from the coke drum by opening a large 

valve at the bottom of the coke drum. 

The drain water typically falls from the 

coke drum onto a slanted concrete pad 

that directs the water to the coke pit 

area (where water and coke are collected 

and separated). Some DCU owners or 

operators initiate draining at the same 

time they initiate venting; other owners 

or operators may allow the vessel to 

vent for 20 or more minutes prior to 

initiating draining. While draining 

immediately may reduce the amount of 

steam exiting the unit via the stack, as 

explained below, it is not expected to 

alter the overall emissions from the unit. 

During the venting and draining 

process, the pressure of the system falls 

to atmospheric. Steam will be generated 

until the evaporative cooling effect of 

that steam generation cools the coker 

quench water to 212 °F. If draining is 

initiated immediately, some of the 

superheated water may drain from the 

DCU before being cooled. A portion of 

that drained water will then convert to 

steam during the draining process as 

that superheated water contacts the 

open atmosphere. Therefore, draining 

quickly is not expected to alter the total 

amount of steam generated from the unit 

nor alter the overall emissions from the 

unit. It will, however, alter the relative 

proportion of the emissions that are 

released via the vent versus the quench 

water drain area. 

The next step in the decoking process 

is ‘‘deheading’’ the coke drum. At the 

top of the coke drum is a large 3- to 5- 

foot diameter opening, which is sealed 

with a gasketed lid during normal 

operations. When the steam generation 

rate from the coke drum has sufficiently 

subsided, this gasketed lid is removed to 

allow access for a water drill that will 

be used to remove coke from the drum. 

The process of removing this lid is 

referred to as ‘‘deheading’’ the coke 

drum. Different DCU owners or 

operators may use different criteria for 

when to dehead the coke drum. If the 

coke drum is deheaded soon after 

venting is initiated, some steam and 

associated HAP emissions may be 

released from this opening. As with 

draining, it is anticipated that the total 

volume of steam generated will be a 

function of the temperature/pressure of 

the coke drum. Deheading the coke 

drum prior to the coke drum contents 

reaching 212 °F will generally mean that 

some of the steam will be released from 

the coke drum head opening. However, 

this will not alter the total amount of 

steam generated; it merely alters the 

location of the release (coke drum head 

opening versus steam vent). The HAP 

emissions from the deheading process 

are expected to be proportional to the 

amount of steam released in the same 

manner as the emissions from the steam 

vent. 

The final step of the decoking process 

is coke cutting. A high-pressure water 

jet is used to drill or cut the coke out 

of the vessel. The drilling water and 

coke slurry exits the coke drum via the 

drain opening and collects in the coke 

pit. Generally, the coke drum and its 

contents are sufficiently cooled so that 

this process is not expected to yield 

significant HAP emissions. However, if 

the other decoking steps are performed 

too quickly, hot spots may exist within 

the coke bed and HAP emissions may 

occur as water contacts these hot spots 

and additional steam and emissions are 

released. 

Once the coke is cut out of the drum, 

the drum is closed and prepared to go 

back on-line. This process includes 

pressurizing with steam to ensure there 

are no leaks (i.e., that the head is 

properly attached and sealed and the 

drain valve is fully closed). The vessel 

is then purged to remove any oxygen 

and heated by diverting the produced 

gas from the processing coke drum 

through the empty drum prior to 

sending it to the unit’s distillation 

column. A coke drum cycle is typically 

28 to 36 hours from start of feed to start 

of the next feed. 

b. How Delayed Coker Vents Are 

Addressed in Refinery MACT 1 

Delayed coker vents are specifically 

mentioned as an example within the 

first paragraph of the definition of 

‘‘miscellaneous process vent’’ in 40 CFR 

63.641 of Refinery MACT 1. However, 

the definition of ‘‘miscellaneous process 

vent’’ also excludes coking unit vents 

associated with coke drum depressuring 

(at or below a coke drum outlet pressure 

of 15 pounds per square inch gauge 

[psig]), deheading, draining, or decoking 

(coke cutting) or pressure testing after 

decoking. Refinery MACT 1 also 


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36902 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

26National Emission Standards for Hazardous 

Air Pollutants Petroleum Refineries—Background 

Information for Final Standards; EPA–453/R–95– 

015b. 

includes a definition of ‘‘delayed coker 

vent’’ in 40 CFR 63.641. This vent is 

typically intermittent in nature, and 

usually occurs only during the initiation 

of the depressuring cycle of the 

decoking operation when vapor from 

the coke drums cannot be sent to the 

fractionator column for product 

recovery, but instead is routed to the 

atmosphere through a closed blowdown 

system or directly to the atmosphere in 

an open blowdown system. The 

emissions from the decoking phases of 

DCU operations, which include coke 

drum deheading, draining, or decoking 

(coke cutting), are not considered to be 

delayed coker vents. 

The first paragraph of the definition of 

‘‘miscellaneous process vent’’ also 

includes blowdown condensers/

accumulators as an example of a 

miscellaneous process vent. Therefore, 

the DCU blowdown system is a 

miscellaneous process vent regardless of 

whether or not the blowdown system is 

associated with a DCU or another 

process unit. Further, the inclusion of 

the ‘‘delayed coker vent’’ as an example 

of a miscellaneous process vent makes 

it clear that the DCU’s blowdown 

system vent (if an open blowdown 

system is used) is considered a 

miscellaneous process vent. It is less 

clear from the regulatory text whether 

the direct venting of the coke drum to 

the atmosphere via the steam vent 

during the final depressurization is 

considered to be a ‘‘delayed coker vent’’ 

(i.e., whether direct venting to the 

atmosphere is equivalent to venting 

‘‘directly to the atmosphere in an open 

blowdown system’’). 

The regulatory text is clear that this 

steam vent is exempt from the definition 

of ‘‘miscellaneous process vent’’ when 

the pressure of the vessel is less than 15 

psig. It is also clear that the subsequent 

release points from the decoking 

operations (i.e., deheading, draining, 

and coke cutting) are excluded from 

both the definition of ‘‘delayed coker 

vent’’ and the definition of 

‘‘miscellaneous process vent.’’ Further, 

based on the statements in the 

background information document for 

the August 1995 final Refinery MACT 1 

rule,26 the 15 psig pressure limit for the 

direct venting of the DCU to the 

atmosphere was not established as a 

MACT floor control level; it was 

established to accommodate all DCU at 

whatever pressure they typically 

switched from venting to the closed 

blowdown system to venting directly to 

the atmosphere. Based on this 

information, as well as the data from the 

2011 Refinery ICR, refinery enforcement 

settlements and other information 

available, which indicate that all 

refineries depressurize the coke drum 

below 15 psig, we have determined that 

the direct atmospheric releases from the 

DCU decoking operations are currently 

unregulated emissions. These 

unregulated releases include emissions 

during atmospheric depressuring (i.e., 

the steam vent), deheading, draining, 

and coke cutting. 

c. Evaluation of MACT Emission 

Limitations for Delayed Coking Units 

We evaluated emissions and controls 

during DCU decoking operations in 

order to identify appropriate MACT 

emission limitations pursuant to CAA 

section 112(d)(2) and (3). Establishing a 

lower pressure set point at which a DCU 

owner or operator can switch from 

venting to an enclosed blowdown 

system to venting to the atmosphere is 

the control technique identified for 

reducing emissions from delayed coking 

operations. Essentially, there is a fixed 

quantity of steam that will be generated 

as the coke drum and its contents cool. 

The lower pressure set point will 

require the DCU to vent to the closed 

blowdown system longer, where the 

organic HAP can be recovered or 

controlled. This will result in fewer 

emissions released during the venting, 

draining and deheading process. 

We consider this control technique, 

which is a work practice standard, 

appropriate for the DCU for the reasons 

discussed below for each of the four 

possible emission points at the DCU: 

draining, deheading, coke cutting and 

the steam vent. For the first three steps, 

the emissions cannot be emitted through 

a conveyance designed and constructed 

to emit or capture such pollutant. For 

example, during draining, the drain 

water typically falls from the coke drum 

onto a slanted concrete pad that directs 

the water to an open coke pit area 

(where water and coke are collected and 

separated). When the coke drum is 

deheaded, the coke drum head must be 

removed to provide an accessible 

opening in the drum so the coke cutting 

equipment can be lowered into the 

drum. This opening cannot be sealed 

during coke cutting because the drilling 

shaft will occupy the opening and the 

shaft must be free to be lowered or 

raised during the coke cutting process. 

While the emissions from the fourth 

point, the DCU steam vent, are released 

via a conveyance designed and 

constructed to emit or capture such 

pollutant, as provided in CAA section 

112(h)(2)(B), it is not feasible to 

prescribe or enforce an emission 

standard for the DCU steam vent 

because the application of a 

measurement methodology for this 

source is not practicable due to 

technological and economic limitations. 

First, it is not practicable to use a 

measurement methodology for the DCU 

steam vent. The emissions from the vent 

typically contain 99 percent water, 

which interferes with common sample 

collection and analysis techniques. 

Also, the flow rate from this vent is not 

constant; rather, it decreases during the 

venting process as the pressure in the 

DCU coke drum approaches 

atmospheric pressure. Additionally, the 

venting time can be very short. As part 

of the ICR, we requested stack testing of 

eight DCU. After discussions with stack 

testing experts within the agency and 

with outside contractors used by 

industry to perform the tests, we 

concluded that sources with venting 

times less than 20 minutes would not be 

able to perform an emissions test that 

would yield valid results. Therefore, 

only two of the eight facilities actually 

performed the tests. We anticipate all 

units complying with the proposed 

standards for DCU steam vents would 

vent for less than 20 minutes. 

Second, it is not feasible to enforce an 

emission standard only on the steam 

vent because the timing of drainage and 

deheading can alter the portion of the 

decoking emissions that are released 

from the actual steam vent. If draining 

and deheading are initiated quickly after 

venting, this will reduce the emissions 

discharged from the vent (although as 

explained above, it does not reduce the 

emissions from the collective set of 

decoking operations release points). 

Consequently, due to the unique 

nature of DCU emissions, the difficulties 

associated with monitoring the DCU 

steam vent, and the inability to 

construct a conveyance to capture 

emissions from all decoking release 

points, we are proposing that it is 

appropriate to develop work practice 

standards in place of emission limits for 

the DCU. 

To establish the MACT floor, we then 

reviewed regulations, permits and 

consent decrees that require coke 

controls. Refinery NSPS Ja establishes a 

pressure limit of 5 psig prior to allowing 

the coke drum to be vented to the 

atmosphere. Based on a review of 

permit limits and consent decrees, we 

found that coke drum vessel pressure 

limits have been established (and 

achieved) as low as 2 psig. There are 75 

operating DCU according to the Refinery 

ICR responses, so the sixth percentile is 

represented by the fifth-best performing 

DCU. We identified eight DCU with 


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permit requirements or consent decrees 

specifying a coke drum venting pressure 

limit of 2 psig; we did not identify any 

permit or consent decree requirements 

more stringent than 2 psig. Refinery 

owners and operators were asked to 

provide the ‘‘typical coke drum pressure 

just prior to venting’’ for each DCU in 

their responses to the Refinery ICR, and 

the responses indicate that four DCU 

operate such that the typical venting 

pressure is 1 psig or less. However, this 

‘‘typical coke drum pressure’’ does not 

represent a not-to-be-exceeded pressure 

limit; it is expected that these units are 

operated this way to meet a pressure 

limit of 2 psig. We do not have 

information to indicate whether these 

facilities are always depressurized at 1 

psig or less. Moreover, there were only 

four units for which a typical venting 

pressure of 1 psig was identified and the 

MACT floor for existing sources is 

represented by the fifth-best operating 

DCU, not the best-performing unit. 

Therefore, we are proposing that the 

MACT floor for DCU decoking 

operations is to depressure at 2 psig or 

less prior to venting to the atmosphere 

for existing sources. We are also 

proposing that the MACT floor for new 

sources is 2 psig, since the bestperforming source is permitted to 

depressure at 2 psig or less. For 

additional details on the MACT floor 

analysis, see memorandum entitled 

MACT Analysis for Delayed Coking Unit 

Decoking Operations in Docket ID 

Number EPA–HQ–OAR–2010–0682. 

We then considered control options 

beyond the floor level of 2 psig to 

determine if additional emission 

reductions could be cost-effectively 

achieved. We considered establishing a 

venting pressure limit of 1 psig or less, 

since four facilities reported in the ICR 

that the typical coke drum pressure 

prior to depressurizing was 1 psig. 

There are several technical difficulties 

associated with establishing a pressure 

limit at this lower level. First, the lowest 

pressure at any point in a closed 

blowdown system is generally designed 

to be no lower than 0.5 psig. 

Consequently, the DCU compressor 

system would operate with an inlet 

pressure of no less than 0.5 psig. 

Second, there are several valves and 

significant piping (for cooling and 

condensing steam) between the DCU 

drum and the recovery compressor. 

There is an inherent pressure drop 

when a fluid flows through a pipe or 

valve. Two valves are used for all DCU 

lines to make sure that the unit is either 

blocked off from the processing fluids or 

blocked in so there are no product 

losses out the steam line during 

processing. Considering the need for 

two valves and piping needed in the 

cooling system, DCU designed for a 

minimal pressure loss will generally 

still have a 0.5 to 1 psig pressure drop 

between the DCU drum and the 

recovery compressor inlet, even for a 

new DCU designed to minimize this 

pressure drop. Finally, in order to meet 

a 1 psig pressure limit at all times, the 

DCU closed vent system would need to 

be designed to achieve a vessel pressure 

of approximately 0.5 psig. Given the 

above considerations, it is not 

technically feasible for new or existing 

DCU to routinely achieve a vessel 

pressure of 0.5 psig in order to comply 

with a never-to-be-exceeded drum 

vessel pressure of 1 psig. As noted 

previously, facilities that ‘‘typically’’ 

achieve vessel pressures of about 1 psig 

or less are expected to do so in order to 

meet a never-to-be-exceeded drum 

vessel pressure limit of 2 psig and they 

are not expected to be able to comply 

with a never-to-be-exceeded drum 

vessel pressure limit of 1 psig. 

We considered setting additional 

work practice standards regarding 

draining, deheading, and coke cutting. 

The decoking emissions can be released 

from a variety of locations, and the 2- 

psig-or-less limit for depressurizing the 

coke drum will effectively reduce the 

emissions from all of these emission 

points, provided that atmospheric 

venting via the DCU steam vent is the 

first step in the decoking process. 

However, it is possible to start draining 

water prior to opening the steam vent. 

We are concerned that owners or 

operators may adopt this practice as a 

means to reduce pressure in the coke 

drum prior to venting the drum to the 

atmosphere. Initiating water draining 

prior to reaching 2 psig would result in 

draining water that is hotter than it 

would be had the drum been 

sufficiently cooled (i.e., the pressure 

limit achieved) prior to draining the 

vessel, effectively diverting HAP 

emissions to the water drain area rather 

than capturing these HAP in the 

enclosed blowdown system, where they 

can be either recovered or controlled. 

Therefore, we are proposing that the 

coke drum must reach 2 psig or less 

prior to any decoking operations, which 

includes atmospheric venting, draining, 

deheading, and coke cutting. 

We could not identify any other 

emission reduction options that could 

lower the emissions from the DCU 

decoking operations. Since we could not 

identify a technically feasible control 

option beyond the MACT floor, we 

determined that the MACT floor 

pressure limit of 2 psig is MACT for 

existing sources. We also determined 

that the same technical limitations of 

going beyond the 2 psig pressure limit 

for existing sources exist for new 

sources; therefore we determined that 

the MACT floor pressure limit of 2 psig 

is MACT for new sources. We request 

comment on whether depressurizing to 

2 psig prior to venting to the atmosphere 

is the appropriate MACT floor and 

whether it is appropriate to include 

restrictions for the other three decoking 

operations draining, deheading and 

coke cutting, in the MACT 

requirements. We request comments on 

whether we have adequately interpreted 

the information that indicates that there 

is currently no applicable MACT floor 

for delayed coking. If Refinery MACT 1 

currently provided standards for DCU 

based on the MACT floor, we would 

evaluate whether it is necessary to 

revise such delayed coking standards 

under the risk and technology review 

requirements of the Act (i.e., CAA 

section 112(f) and 112(d)(6)) as 

discussed later in this preamble. 

Finally, we request comment and 

supporting information on any other 

practices that may be used to limit 

emissions during the decoking 

operations. 

d. Evaluation of Cost and Environmental 

Impacts of MACT Emission Limitations 

for Delayed Coking Units 

DCU that cannot currently meet the 2 

psig pressure limit would be expected to 

install a device (compressor or steam 

ejector system) to lower the DCU vessel 

pressure. In the Refinery NSPS Ja 

impact analysis, facilities not able to 

meet the pressure threshold were 

assumed to purchase and install a larger 

compressor to lower the blowdown 

system pressure. Other approaches to 

lowering blowdown system (and coke 

drum) pressure exist. Specifically, steam 

ejectors have been identified as a 

method to help existing units 

depressurize more fully in order to 

achieve a set vessel pressure or drum 

bed temperature. Upgrading the closed 

vent system to reduce pressure losses or 

to increase steam condensing capacity 

may also allow the DCU to depressurize 

more quickly while the emissions are 

still vented to the closed blowdown 

system. This is important because 

delays in the decoking operations may 

impact process feed rates. That is, if the 

decoking and drum preparation steps 

take too long, the feed rate to the other 

coke unit must be reduced to prevent 

overfilling one coke drum prior to being 

able to switch to the other coke drum. 

This issue is less critical for DCU that 

operate with 3 or 4 drums per 

distillation column, but a consistent 

increase in the decoking times across all 


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drums may still limit the capacity of the 

DCU at some petroleum refineries. 

For existing sources, we assumed all 

DCU that reported a ‘‘typical drum 

pressure prior to venting’’ of more than 

2 psig would install and operate a steam 

ejector system to reduce the coke drum 

pressure to 2 psig prior to venting to 

atmosphere or draining. 

The operating costs of the steam 

ejector system are offset, to some extent, 

by the additional recovered vapors. 

Vapors from the additional gases routed 

to the blowdown system contain high 

levels of methane (approximately 70 

percent by volume on a dry basis) based 

on DCU steam vent test data. If these 

vapors are directed to the closed 

blowdown system rather than to the 

atmosphere, generally the dry gas can be 

recovered in the refinery fuel gas system 

or light-ends gas plant. This recovered 

methane is expected to off-set natural 

gas purchases for the fuel gas system. 

For new sources, it is anticipated that 

the DCU’s closed vent system could be 

designed to achieve a 2 psig vessel 

pressure with no significant increase in 

capital or operating costs. Designing the 

system to vent at a lower pressure 

would also result in additional vapor 

recovery, which is expected to off-set 

any additional capital costs associated 

with the low pressure design closed 

vent system. 

The costs of complying with the 2 

psig coke drum threshold prior to 

venting or draining are summarized in 

Table 2 of this preamble. The costs are 

approximately $1,000 per ton of VOC 

reduced and approximately $5,000 per 

ton of organic HAP reduced when 

considering VOC and methane recovery 

credits. In addition to VOC and HAP 

reductions, the proposed control option 

will result in a reduction in methane 

emissions of 18,000 tpy or 343,000 

metric tonnes per year of carbon dioxide 

equivalents (CO2e), assuming a global 

warming potential of 21 for methane. 

TABLE 2—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL OPTION FOR DELAYED COKING UNITS AT

PETROLEUM REFINERIES

Control option Capital cost 

(million $) 

Annualized 

costs 

without recovery credits 

(million $/yr) 

Emissions 

reduction, 

VOC 

(tpy) 

Emissions 

reduction, 

HAP 

(tpy) 

Cost 

effectiveness ($/ton HAP) 

Total 

annualized 

costs with 

VOC recovery credit 

(million $/yr) 

Overall cost 

effectiveness with 

VOC recovery credit 

($/ton HAP) 

2 psig ......................................................................................... 52 10.2 4,250 850 12,000 3.98 4,700 

2. CRU Vents 

A CRU is designed to reform (i.e., 

change the chemical structure of) 

naphtha into higher-octane aromatics. 

Over time, coke deposits form on the 

reforming catalyst, which reduces the 

catalyst activity. When catalyst activity 

is reduced to a certain point, the catalyst 

is regenerated by burning the coke off of 

the catalyst. Prior to this coke burn-off 

process, the catalyst (or reactor vessel 

containing the catalyst) must be 

removed from active service and 

organics remaining on the catalyst (or in 

the reactor) must be purged from the 

system. This is generally accomplished 

by depressurizing the vessel to a certain 

vessel pressure, then re-pressurizing the 

vessel with nitrogen and depressurizing 

the vessel again. The re-pressurization 

and depressurization process is repeated 

several times until all organics have 

been purged from the system. The 

organic HAP emissions from this 

depressurization/purge cycle vent are 

typically controlled by directing the 

purge gas directly to the CRU process 

heater or venting the gas to a flare. 

Refinery MACT 2 requires a 98- 

percent reduction of organic HAP 

measured as total organic carbon (TOC) 

or non-methane TOC or an outlet 

concentration of 20 ppmv or less (dry 

basis, as hexane, corrected to 3-percent 

oxygen), whichever is less stringent, for 

this CRU depressurization/purge cycle 

vent (purging prior to coke-burn-off). 

The emission limits for organic HAP for 

the CRU do not apply to emissions from 

process vents during depressuring and 

purging operations when the reactor 

vent pressure is 5 psig or less. The 

Refinery MACT 2 requirements were 

based on the typical operation of CRU 

utilizing sequential pressurization and 

passive depressurization. The 5 psig 

pressure limit exclusion was provided 

based on state permit conditions, which 

recognized that depressurization to an 

APCD (without other active motive of 

flow) is limited by the back pressure of 

the control system, which is often a flare 

or process heater. Source testing 

information collected from the 2011 

Refinery ICR indicates that facilities 

have interpreted the rule to allow the 5 

psig pressure limit exclusion to be used 

by units using active purging techniques 

(such as continuous nitrogen purge or 

vacuum pump on the CRU reactor at 

low pressures) to discharge to the 

atmosphere without emission controls. 

The information collected indicates that 

HAP emissions from a continuous, 

active purging technique could result in 

emissions of HAP from CRU 

depressurization vents much higher 

than expected to be allowed under the 

Refinery MACT 2 requirements, which 

presumed sequential re-pressurization 

and purging cycles. The testing 

information received indicated that at 

one facility, the active purge vent had 

non-methane TOC concentrations of 700 

to 10,000 ppmv (dry basis, as hexane, 

corrected to 3-percent oxygen) 

compared to less than 10 ppmv for the 

typical passive purge vent tested. The 

annual HAP emissions for the CRU with 

the active purge vent were estimated to 

exceed 10 tpy, while a comparable unit 

using the cyclic re-pressurization and 

passive depressurization purge 

technique is projected to have HAP 

emissions of less than 0.1 tpy. 

Therefore, we are proposing to amend 

the exclusion in 40 CFR 63.1566(a)(4) to 

clarify the application of the 5 psig 

exclusion, consistent with the MACT 

floor under CAA section 112(d)(2) and 

(3). Specifically, we are limiting the 

vessel pressure limit exclusion to apply 

only to passive vessel depressurization. 

Units utilizing active purging 

techniques have a motive of flow that 

can be used to direct the purge gas to 

a control system, regardless of the CRU 

vessel pressure. If a CRU owner or 

operator uses active purging techniques 

(e.g., a continual nitrogen purge) or 

active vessel depressurization (e.g., 

vacuum pump), then the 98-percent 

reduction or 20 ppmv TOC emission 

limits would apply to these discharges 

regardless of the vessel pressure. 

3. Refinery Flares 

The EPA is proposing under CAA 

section 112(d)(2) and (3) to amend the 

operating and monitoring requirements 

for petroleum refinery flares. We have 

determined that the current 

requirements for flares are not adequate 

to ensure compliance with the Refinery 

MACT standards. In the development of 

Refinery MACT 1, the EPA determined 

that the average emission limitation 

achieved by the best-performing 12 


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27These documents can also be found at http:// 

www.epa.gov/ttn/atw/petref.html. 

percent of existing sources was 

established as the use of combustion 

controls for miscellaneous process 

vents. Further, the EPA stated that ‘‘data 

analyses conducted in developing 

previous NSPS and the [National 

Emission Standards for Organic 

Hazardous Air Pollutants (40 CFR part 

63, subparts F, G, and H)] HON 

determined that combustion controls 

can achieve 98-percent organic HAP 

reduction or an outlet organic HAP 

concentration of 20 ppmv for all vent 

streams’’ (59 FR 36139, July 15, 1994). 

The requirements applicable to flares at 

refineries are set forth in the General 

Provisions to 40 CFR part 63 and are 

cross-referenced in Refinery MACT 1 

and 2. In general, flares used as APCD 

were expected to achieve 98-percent 

HAP destruction efficiencies when 

designed and operated according to the 

requirements in the General Provisions. 

Recent studies on flare performance, 

however, indicate that these General 

Provisions requirements are inadequate 

to ensure proper performance of refinery 

flares, particularly when assist steam or 

assist air is used. Over the last decade, 

flare minimization efforts at petroleum 

refineries have led to an increasing 

number of flares operating at well below 

their design capacity, and while this 

effort has resulted in reduced flaring of 

gases at refineries, situations of overassisting with steam or air have become 

exacerbated, leading to the degradation 

of flare combustion efficiency. 

Therefore, these amendments are 

necessary to ensure that refineries that 

use flares as APCD meet the MACT 

standards at all times when controlling 

HAP emissions. 

Refinery MACT 1 and 2 require flares 

used as an APCD to meet the 

operational requirements set forth in the 

General Provisions at 40 CFR 63.11(b). 

These General Provisions requirements 

specify that flares shall be: (1) Steamassisted, air-assisted, or non-assisted; (2) 

operated at all times when emissions 

may be vented to them; (3) designed for 

and operated with no visible emissions 

(except for periods not to exceed a total 

of 5 minutes during any 2 consecutive 

hours); and (4) operated with the 

presence of a pilot flame at all times. 

The General Provisions also specify 

requirements for both the minimum 

heat content of gas combusted in the 

flare and maximum exit velocity at the 

flare tip. The General Provisions only 

specify monitoring requirements for the 

presence of the pilot flame and the 

operation of a flare with no visible 

emissions. For all other operating limits, 

Refinery MACT 1 and 2 require an 

initial performance evaluation to 

demonstrate compliance but there are 

no specific monitoring requirements to 

ensure continuous compliance. As 

noted previously, flare performance 

tests conducted over the past few years 

suggest that the current regulatory 

requirements are insufficient to ensure 

that refinery flares are operating 

consistently with the 98-percent HAP 

destruction efficiencies that we 

determined were the MACT floor. 

In 2012, the EPA compiled 

information and test data collected on 

flares and summarized its preliminary 

findings on operating parameters that 

affect flare combustion efficiency (see 

technical report, Parameters for 

Properly Designed and Operated Flares, 

in Docket ID Number EPA–HQ–OAR– 

2010–0682). The EPA submitted the 

report, along with a charge statement 

and a set of charge questions to an 

external peer review panel.27 The panel 

concurred with the EPA’s assessment 

that three primary factors affect flare 

performance: (1) The flow of the vent 

gas to the flare; (2) the amount of assist 

media (e.g., steam or air) added to the 

flare; and (3) the combustibility of the 

vent gas/assist media mixture in the 

combustion zone (i.e., the net heating 

value, lower flammability, and/or 

combustibles concentration) at the flare 

tip. 

Following is a discussion of 

requirements we are proposing for 

refinery flares, along with impacts and 

costs associated with these new 

requirements. Specifically, this action 

proposes that refinery flares operate 

pilot flame systems continuously and 

with automatic re-ignition systems and 

that refinery flares operate with no 

visible emissions. In addition, this 

action also consolidates requirements 

related to flare tip velocity and proposes 

new operational and monitoring 

requirements related to the combustion 

zone gas. Prior to these proposed 

amendments, Refinery MACT 1 and 2 

cross-reference the General Provisions 

requirements at 40 CFR 63.11(b) for the 

operational requirements for flares used 

as APCD. Rather than revising the 

General Provisions requirements for 

flares, which would impact dozens of 

different source categories, this proposal 

will specify all refinery flare operational 

and monitoring requirements 

specifically in Refinery MACT 1 and 

cross-reference these same requirements 

in Refinery MACT 2. All of the 

requirements for flares operating at 

petroleum refineries in this proposed 

rulemaking are intended to ensure 

compliance with the Refinery MACT 1 

and 2 standards when using a flare as 

an APCD. 

a. Pilot Flames 

Refinery MACT 1 and 2 reference the 

flare requirements in the General 

Provisions, which require a flare used as 

an APCD device to operate with a pilot 

flame present at all times. Pilot flames 

are proven to improve flare flame 

stability; even short durations of an 

extinguished pilot could cause a 

significant reduction in flare destruction 

efficiency. In this action, we are 

proposing to remove the cross-reference 

to the General Provisions and instead 

include the requirement that flares 

operate with a pilot flame at all times 

and be continuously monitored for 

using a thermocouple or any other 

equivalent device in Refinery MACT 1 

and 2. We are also proposing to amend 

Refinery MACT 1 and 2 to add a new 

operational requirement to use 

automatic relight systems for all flare 

pilot flames. An automatic relight 

system provides a quicker response time 

to relighting a snuffed-out flare 

compared to manual methods and 

thereby results in improved flare flame 

stability. In comparison, manual 

relighting is much more likely to result 

in a longer period where the pilot 

remains unlit. Because of safety issues 

with manual relighting, we anticipate 

that nearly all refinery flares are already 

equipped with an automated device to 

relight the pilot flame in the event it is 

extinguished. Also, due to the 

possibility that a delay in relighting the 

pilot could result in a flare not meeting 

the 98-percent destruction efficiency for 

the period when the pilot flame is out, 

we are proposing to amend Refinery 

MACT 1 and 2 to add this requirement 

to ensure that the pilot operates at all 

times. 

b. Visible Emissions 

Refinery MACT 1 and 2 reference the 

flare requirements in the General 

Provisions, which require a flare used as 

an APCD to operate with visible 

emissions for no more than 5 minutes in 

a 2-hour period. Owners or operators of 

these flares are required to conduct an 

initial performance demonstration for 

visible emissions using EPA Method 22 

of 40 CFR part 60, Appendix A–7. We 

are proposing to remove the crossreference to the General Provisions and 

include the limitation on visible 

emissions in Refinery MACT 1 and 2. In 

addition, we are proposing to amend 

Refinery MACT 1 and 2 to add a 

requirement that a visible emissions test 

be conducted each day and whenever 

visible emissions are observed from the 

flare. We are proposing that owners or 


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36906 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

operators of flares monitor visible 

emissions at a minimum of once per day 

using an observation period of 5 

minutes and EPA Method 22 of 40 CFR 

part 60, Appendix A–7. Additionally, 

any time there are visual emissions from 

the flare, we are proposing that another 

5-minute visible emissions observation 

period be performed using EPA Method 

22 of 40 CFR part 60, Appendix A–7, 

even if the minimum required daily 

visible emission monitoring has already 

been performed. For example, if an 

employee observes visual emissions or 

receives notification of such by the 

community, the owner or operator of the 

flare would be required to perform a 5- 

minute EPA Method 22 observation in 

order to check for compliance upon 

initial observation or notification of 

such event. We are also proposing that 

if visible emissions are observed for 

greater than one continuous minute 

during any of the required 5-minute 

observation periods, the monitoring 

period shall be extended to 2 hours. 

Industry representatives have 

suggested to the EPA that flare 

combustion efficiency is highest at the 

incipient smoke point (the point at 

which black smoke begins to form 

within the flame). They stated that the 

existing limit for visible emissions 

could be increased from 5 minutes to 10 

minutes in a 2-hour period to encourage 

operation near the incipient smoke 

point (see memorandum, Meeting 

Minutes for February 19, 2013, Meeting 

Between the U.S. EPA and 

Representatives from the Petroleum 

Refining Industry, in Docket ID Number 

EPA–HQ–OAR–2010–0682). While we 

agree that operating near the incipient 

smoke point results in good combustion 

at the flare tip, we disagree that the 

allowable period for visible emissions 

be increased from 5 to 10 minutes for a 

2-hour period. Smoking flares can 

contribute significantly to emissions of 

particulate matter 2.5 micrometers in 

diameter and smaller (PM2.5) emissions, 

and we are concerned that increasing 

the allowable period of visible 

emissions from 5 minutes to 10 minutes 

for every 2-hour period could result in 

an increase in the PM2.5 emissions from 

flares. 

As discussed later in this section, we 

are proposing additional operational 

and monitoring requirements for 

refinery flares which we expect will 

result in refineries installing equipment 

that can be used to fine-tune and control 

the amount of assist steam or air 

introduced at the flare tip such that 

combustion efficiency of the flare will 

be maximized. These monitoring and 

control systems will assist refinery flare 

owners or operators operating near the 

incipient smoke point without 

exceeding the visible emissions limit. 

While combustion efficiency may be 

highest at the incipient smoke point, it 

is not significantly higher than the 

combustion efficiency achieved by these 

proposed operating limits, discussed in 

section IV.A.3.d of this preamble. As 

seen in the performance curves for flares 

(see technical memorandum, Petroleum 

Refinery Sector Rule: Operating Limits 

for Flares, in Docket ID Number EPA– 

HQ–OAR–2010–0682), there is very 

limited improvement in flare 

performance beyond the performance 

achieved at these proposed operating 

limits. We solicit comments and data on 

appropriate periods of visible emissions 

that would encourage operation at the 

incipient smoke point while not 

significantly increasing PM2.5 emissions. 

c. Flare Tip Velocity 

The General Provisions at 40 CFR 

63.11(b) specify maximum flare tip 

velocities based on flare type (nonassisted, steam-assisted, or air-assisted) 

and the net heating value of the flare 

vent gas. These maximum flare tip 

velocities are required to ensure that the 

flame does not ‘‘lift off’’ the flare, which 

could cause flame instability and/or 

potentially result in a portion of the 

flare gas being released without proper 

combustion. We are proposing to 

remove the cross-reference to the 

General Provisions and consolidate the 

requirements for maximum flare tip 

velocity into Refinery MACT 1 and 2 as 

a single equation, irrespective of flare 

type (i.e., steam-assisted, air-assisted or 

non-assisted). Based on our analysis of 

the various studies for air-assisted 

flares, we identified air-assisted test 

runs with high flare tip velocities that 

had high combustion efficiencies (see 

technical memorandum, Petroleum 

Refinery Sector Rule: Evaluation of 

Flare Tip Velocity Requirements, in 

Docket ID Number EPA–HQ–OAR– 

2010–0682). These test runs exceeded 

the maximum flare tip velocity limits 

for air-assisted flares using the linear 

equation in 40 CFR 63.11(b)(8). When 

these test runs were compared with the 

test runs for non-assisted and steamassisted flares, the air-assisted flares 

appeared to have the same operating 

envelope as the non-assisted and steamassisted flares. Therefore, we are 

proposing that air-assisted flares at 

refineries use the same equation that 

non-assisted and steam-assisted flares 

currently use to establish the flare tip 

velocity operating limit. 

In developing these proposed flare tip 

velocity requirements, we considered 

whether any adjustments to these 

velocity equations were necessary. The 

flare tip velocity equations require the 

input of the net heating value of the 

vent gas going to the flare, as opposed 

to the net heating value of the gas 

mixture at the flare tip (i.e., the 

combustion zone gas). As discussed 

later in this section, we found that the 

performance of the flare was much more 

dependent on the net heating value of 

the gas mixture in the combustion zone 

than on the net heating value of only the 

vent gas going into the flare (excluding 

all assist media). We considered 

replacing the term in the velocity 

equation for the net heating value of the 

vent gas going into the flare with the net 

heating value of the gas mixture in the 

combustion zone. However, the steam 

addition rates were not reported for the 

tests conducted to evaluate flame 

stability as a function of flare tip 

velocity, so direct calculation of all the 

terms needed for calculating the net 

heating value in the combustion zone 

could not be made. At higher flare tip 

velocities, we expect that the steam 

assist rates would be small in 

comparison to the total vent gas flow 

rate, so there would not be a significant 

difference between the net heating value 

of the vent gas going into the flare and 

the combustion zone gas net heating 

value for the higher velocity flame 

stability tests. We request comment on 

the need and/or scientific reasons to use 

the flare vent gas net heating value 

versus the combustion zone net heating 

value when determining the maximum 

allowable flare tip velocity. 

In the 2012 flare peer review, we also 

discussed the effect of flame lift off and 

velocity on flare flame stability (see 

technical report, Parameters for 

Properly Designed and Operated Flares, 

in Docket ID Number EPA–HQ–OAR– 

2010–0682). In looking at ways of trying 

to prohibit flame instability, we 

examined the use of the Shore equation 

as a means to limit flare tip velocity. 

However, after receiving many 

comments on use of this equation from 

the peer reviewers, the uncertainty with 

how well the Shore equation models the 

large range of flare operation, and the 

limited dataset with which recent 

testing used high velocities (all recent 

test runs were performed at 10 feet per 

second or less), we determined that use 

of the existing velocity equation 

discussed above was still warranted. 

We are also proposing for Refinery 

MACT 1 and 2 to not include the special 

flare tip velocity equation in the General 

Provisions at 40 CFR 63.11(b)(6)(i)(A) 

for non-assisted flares with hydrogen 

content greater than 8 percent. This 

equation, which was developed based 

on limited data from a chemicals 

manufacturer, has very limited 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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applicability for petroleum refinery 

flares in that it only provides an 

alternative for non-assisted flares with 

large quantities of hydrogen. 

Approximately 90 percent of all refinery 

flares are either steam- or air-assisted. 

Furthermore, we are proposing 

compliance alternatives in this section 

that we believe provide a better way for 

flares at petroleum refineries with high 

hydrogen content to comply with the 

rule while ensuring proper destruction 

performance of the flare (see section 

IV.A.3.d of this preamble for additional 

details). Therefore, we are proposing to 

not include this special flare tip velocity 

equation as a compliance alternative for 

refinery flares. We request comment on 

the need to include this equation. If a 

commenter supports inclusion of this 

equation, we request that the 

commenter submit supporting 

documentation regarding the vent gas 

composition and flows and, if available, 

combustion efficiency determinations 

that indicate that this additional 

equation is needed and is appropriate 

for refinery flares. We also request 

documentation that the maximum 

allowable flare tip velocity predicted by 

this equation adequately ensures proper 

combustion efficiency. 

The General Provisions require an 

initial demonstration that a flare used as 

an APCD meets the applicable flare tip 

velocity requirement in 40 CFR 63.11(b). 

However, most refinery flares can have 

highly variable vent gas flows and a 

single initial demonstration is 

insufficient to demonstrate continuous 

compliance with the flare tip velocity 

requirement. Consequently, we are 

proposing to amend Refinery MACT 1 

and 2 to require continuous monitoring 

to determine flare tip velocity, 

calculated by monitoring the flare vent 

gas volumetric flow rate and dividing by 

the cross-sectional area of the flare tip. 

As an alternative to installing 

continuous volumetric flow rate 

monitors, we are proposing that the 

owner or operator may elect to install a 

pressure- and temperature-monitoring 

system and use engineering calculations 

to determine the flare tip velocity. 

d. Refinery Flare Operating and 

Monitoring Requirements 

The current requirements for flares in 

the General Provisions specify that the 

flare vent gas must meet a minimum net 

heating value of 200 British thermal 

units per standard cubic foot (Btu/scf) 

for non-assisted flares and 300 Btu/scf 

for air- and steam-assisted flares. 

Refinery MACT 1 and 2 reference these 

requirements, but neither the General 

Provisions nor Refinery MACT 1 and 2 

include specific monitoring 

requirements to monitor the net heating 

value of the vent gas. Moreover, recent 

flare testing results indicate that this 

parameter alone does not adequately 

address instances when the flare may be 

over-assisted since it only considers the 

gas being combusted in the flare and 

nothing else (e.g., no assist media). 

However, many industrial flares use 

steam or air as an assist medium to 

protect the design of the flare tip, 

promote turbulence for the mixing, 

induce air into the flame and operate 

with no visible emissions. Using 

excessive steam or air results in dilution 

and cooling of flared gases and can lead 

to operating a flare outside its stable 

flame envelope, reducing the 

destruction efficiency of the flare. In 

extreme cases, over-steaming or excess 

aeration can actually snuff out a flame 

and allow regulated material to be 

released into the atmosphere completely 

uncombusted. Since approximately 90 

percent of all flares at refineries are 

either steam- or air-assisted, it is critical 

that we ensure the assist media be 

accounted for in some form or fashion. 

Recent flare test data have shown that 

the best way to account for situations of 

over-assisting is to consider the 

properties of the mixture of all gases at 

the flare tip in the combustion zone 

when evaluating the ability to combust 

efficiently. As discussed in the 

introduction to this section, the external 

peer review panel concurred with our 

assessment that the combustion zone 

properties at the flare tip are critical 

parameters to know in determining 

whether a flare will achieve good 

combustion. The General Provisions, 

however, solely rely on the net heating 

value of the flare vent gas. 

We are proposing to add definitions of 

two key terms relevant to refinery flare 

performance. First, we are proposing to 

define ‘‘flare vent gas’’ to include all 

waste gas, sweep gas, purge gas and 

supplemental gas, but not include pilot 

gas or assist media. We are proposing 

this definition because information 

about ‘‘flare vent gas’’ (e.g., flow rate 

and composition) is one of the necessary 

inputs needed to evaluate the make-up 

of the combustion zone gas. To that end, 

we are also proposing to define the 

‘‘combustion zone gas’’ as flare vent gas 

plus the total steam-assist media and 

premix assist air that is supplied to the 

flare. 

Based on our review of the recent 

flare test data, we have determined that 

the following combustion zone 

operational limits can be used to 

determine good combustion: Net heating 

value (Btu/scf), lower flammability limit 

(LFL) or a total combustibles fraction 

(e.g., a simple carbon count). In this 

action, we are proposing these new 

operational limits, along with methods 

for determining these limits in the 

combustion zone at the flare tip for 

steam-assisted, air-assisted and nonassisted flares to ensure that there is 

enough combustible material readily 

available to achieve good combustion. 

For air-assisted flares, use of too much 

perimeter assist air can lead to poor 

flare performance. Based on our 

analysis, we found that including the 

flow rate of perimeter assist air in the 

calculation of combustion zone 

operational limits in itself does not 

identify all instances of excess aeration. 

The data suggest that the diameter of the 

flare tip, in concert with the amount of 

perimeter assist air, provides the inputs 

necessary to calculate whether or not 

this type of flare is over-assisted. 

Therefore, we are proposing that in 

addition to complying with combustion 

zone operational limits to ensure that 

there is enough combustible material 

available to adequately combust the gas 

and pass through the flammability 

region, air-assisted flares would also 

comply with an additional dilution 

parameter that factors in the flow rate of 

the flare vent gas, flow rates of all assist 

media (including perimeter assist air), 

and diameter of flare tip to ensure that 

degradation of flare performance from 

excess aeration does not occur. This 

dilution parameter is consistent with 

the combustion theory that the more 

‘‘time’’ the gas spends in the 

flammability region above the flare tip, 

the better it will combust. Also, since 

both the volume of the combustion zone 

(represented by the diameter here) and 

how quickly this gas is diluted to a 

point below the flammability region 

(represented by perimeter assist air flow 

rate) characterize this ‘‘time,’’ it makes 

sense that we propose such a term (see 

technical memorandum, Petroleum 

Refinery Sector Rule: Operating Limits 

for Flares, in Docket ID Number EPA– 

HQ–OAR–2010–0682). 

It should be noted that in the 2012 

flare peer review report, we considered 

a limit for perimeter assist air via the 

stoichiometric air ratio. This 

stoichiometric air ratio is the ratio of the 

actual mass flow rate of assist air to the 

theoretical stoichiometric mass flow rate 

of air (based on complete chemical 

combustion of fuel to carbon dioxide 

(CO2) and water) needed to combust the 

flare vent gas. However, we are not 

proposing to include this term as part of 

the calculation methodology, as we have 

determined that the dilution parameter 

discussed in this section better assures 

that air-assisted flare performance is not 

degraded due to excess aeration. 


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36908 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

The proposed rule allows the owner 

or operator flexibility to select the form 

of the combustion zone operational 

limit (i.e., net heating value, LFL, or 

total combustibles fraction) with which 

to comply in order to provide facilities 

the option of using monitors they may 

already have in place. The monitoring 

methods we are proposing take into 

account the combustible properties of 

all gas going to the flare (i.e., flare vent 

gas, assist gas, and premix air) that 

affects combustion efficiency, and they 

can be used to determine whether a flare 

has enough combustible material to 

achieve the desired level of control (and 

whether it is being over-assisted). These 

methods require the owner or operator 

to input the flow of the vent gas to the 

flare, the characteristics of the vent gas 

going to the flare (i.e., either a heat 

content (Btu/scf), LFL, or total 

combustible fuel content, depending on 

how the operational limit is expressed), 

and the flow of assist media added to 

the flare. 

To estimate the LFL, we are proposing 

to use a calculation method based on 

the Le Chatelier equation. The Le 

Chatelier calculation uses the reciprocal 

of the volume-weighted average over the 

LFL of the individual compounds in the 

gas mixture to estimate the LFL of the 

gas mixture. Although Le Chatelier’s 

equation was originally limited to 

binary mixtures of combustible gases, 

we are proposing a method that was 

developed by Karim, et al. (1985) and 

assumes a LFL of infinity for inert gases. 

We are also aware of other methods 

and/or adjustments that can be made to 

the Le Chatelier equation in order to 

calculate a more accurate estimate of the 

LFL of a gas mixture (see technical 

memorandum, Parameters for Properly 

Designed and Operated Flares, in 

Docket ID Number EPA–HQ–OAR– 

2010–0682). We are soliciting comment 

on the use of this proposed method. 

Recent data indicate that one set of 

operational limits may not be sufficient 

for all refinery flares. Flares that receive 

vent gas containing significant levels of 

both hydrogen and olefins often exhibit 

lower combustion efficiencies than 

flares that receive vent gas with only 

one (or none) of these compounds. 

Therefore, we are proposing more 

stringent operational limits for flares 

that simultaneously receive vent gas 

containing significant levels of both 

hydrogen and olefins (see technical 

memorandum, Petroleum Refinery 

Sector Rule: Operating Limits for Flares, 

in Docket ID Number EPA–HQ–OAR– 

2010–0682). Although the minimum net 

heating value in the combustion zone 

(i.e., Btu/scf) is a good indicator of 

combustion efficiency, as noted in the 

flare peer review report, the LFL and 

combustibles concentration (or total 

combustibles) in the combustion zone 

are also good indicators of flare 

combustion efficiency. For some gas 

mixtures, such as gases with high 

hydrogen content, the LFL or 

combustibles concentration in the 

combustion zone may be better 

indicators of performance than net 

heating value. Consequently, we are 

proposing operational limits expressed 

all three ways, along with associated 

monitoring requirements discussed later 

in this section. 

The three operating limits were 

established in such a way that each 

limit is protective on its own. As such, 

the owner or operator may elect to 

comply with any of the three alternative 

operating limits at any time, provided 

they use a monitoring system capable of 

determining compliance with each of 

the proposed alternative operating 

limits on which they rely (see technical 

memorandum, Petroleum Refinery 

Sector Rule: Operating Limits for Flares, 

in Docket ID Number EPA–HQ–OAR– 

2010–0682). For example, the owner or 

operator may elect to install monitoring 

for only one of the three alternative 

operating limits, in which case the 

owner or operator must comply with 

that selected operating limit at all times. 

If the owner or operator installs a 

system capable of monitoring for all 

three of the alternative operating limits, 

the owner or operator can choose which 

of the three operating limits the source 

will rely on to demonstrate compliance. 

A summary of the operating limits 

specified in this proposed rule is 

provided in Table 3 of this preamble. 

We are proposing that owners or 

operators of flares used as APCD would 

conduct an initial performance test to 

determine the values of the parameters 

to be monitored (e.g., the flow rate and 

heat content of the incoming flare vent 

gas, the assist media flow rate, and premix air flow rate, if applicable) in order 

to demonstrate continuous compliance 

with the operational limits in Table 3. 

We are proposing to require owners or 

operators to record and calculate 15- 

minute block average values for these 

parameters. Our rationale for selecting a 

15-minute block averaging period is 

provided in section IV.A.3.e of this 

preamble. 

TABLE 3—OPERATING LIMITS FOR FLARES IN THIS PROPOSED ACTION

Operating parameter a Operating limits: Flares without 

hydrogen-olefin interaction b

Operating limits: Flares with 

hydrogen-olefin interaction b

Combustion zone parameters for all flares 

NHVcz ................................... ≥270 Btu/scf .................................................................... ≥380 Btu/scf. 

LFLcz .................................... ≤0.15 volume fraction ...................................................... ≤0.11 volume fraction. 

Ccz ........................................ ≥0.18 volume fraction ...................................................... ≥0.23 volume fraction. 

Dilution parameters for flares using perimeter assist air 

NHVdil ................................... ≥22 Btu/ft2 ....................................................................... ≥32 Btu/ft2. 

LFLdil .................................... ≤2.2 volume fraction/ft ..................................................... ≤1.6 volume fraction/ft. 

Cdil ........................................ ≥0.012 volume fraction-ft ................................................ ≥0.015 volume fraction-ft. 

aThe operating parameters are: 

NHVcz = combustion zone net heating value. 

LFLcz = combustion zone lower flammability limit. 

Ccz = combustion zone combustibles concentration. 

NHVdil = net heating value dilution parameter. 

LFLdil = lower flammability limit dilution parameter. 

Cdil = combustibles concentration dilution parameter. b Hydrogen-Olefin interactions are assumed to be present when the concentration of hydrogen and olefins in the combustion zone exceed all 

three of the following criteria: 

(1) The concentration of hydrogen in the combustion zone is greater than 1.2 percent by volume. 

(2) The cumulative concentration of olefins in the combustion zone is greater than 2.5 percent by volume. 


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(3) The cumulative concentration of olefins in the combustion zone plus the concentration of hydrogen in the combustion zone is greater than 

7.4 percent by volume. 

Btu/ft2 = British thermal units per square foot. 

We are soliciting comment on the 

appropriateness of the operating limits 

and dilution parameters in Table 3 of 

this preamble and whether they ensure 

that refinery flares operate in a manner 

that that will ensure compliance with 

the MACT requirements for vents to 

achieve a 98-percent organic HAP 

reduction. 

Combustion zone gas monitoring 

alternatives. As discussed previously in 

this section, we are proposing to define 

the combustion zone gas as the mixture 

of gas at the flare tip consisting of the 

flare vent gas, the total steam-assist 

media and premix assist air. In order to 

demonstrate compliance with the three 

combustion zone parameter operating 

limits of net heating value, LFL and 

total combustibles fraction, the owner or 

operator would need to monitor four 

things: (1) Flow rate of the flare vent 

gas; (2) flow rate of total steam assist 

media; (3) flow rate of premix assist air 

and (4) specific characteristics 

associated with the flare vent gas (e.g., 

heat content, composition). In order to 

monitor the flow rates of the flare vent 

gas, total steam assist media, and 

premix assist air, we are proposing that 

refinery owners or operators use a 

continuous volumetric flow rate 

monitoring system or a pressure- and 

temperature-monitoring system with use 

of engineering calculations. We are also 

proposing use of either of these 

monitoring methods for purposes of 

determining the flow rate of perimeter 

assist air (for compliance with the 

dilution parameter). However, the one 

component that will determine how 

many combustion zone parameter 

operating limits an owner or operator 

can comply with is the specific type of 

monitor used to characterize the flare 

vent gas. 

Monitoring the individual component 

concentrations of the flare vent gas 

using an on-line gas chromatograph 

(GC) along with monitoring vent gas and 

assist gas flow rates will allow the 

owner or operator to determine 

compliance with any of the three 

proposed combustion zone operating 

limits and any of the three proposed 

dilution operating limits (if using airassisted flares). We considered requiring 

all refinery owners or operators of flares 

to only use a GC to monitor the flare 

vent gas composition but since facilities 

may have other non-GC monitors 

already in place (e.g., calorimeters), we 

are not proposing such a requirement at 

this time. However, use of a GC can 

improve refinery flare operation and 

management of resources. For example, 

use of a GC to characterize the flare vent 

gas can lead to product/cost savings for 

refiners because they could more readily 

identify and correct instances of product 

being unintentionally sent to a flare, 

either through a leaking pressure relief 

valve or other conveyance that is 

ultimately routed to the flare header 

system. In addition, an owner or 

operator that chooses to use a GC (in 

lieu of one of the other proposed 

monitoring alternatives) will be more 

likely to benefit from the ability to 

continuously fine-tune their operations 

(by reducing assist gas addition and/or 

supplemental gas to the flare) in order 

to meet any one of the three operating 

limits. Furthermore, some facilities are 

already required to use a GC to 

demonstrate compliance with state flare 

requirements. We are soliciting 

comment on the additional benefits that 

using a GC offers and whether it would 

be reasonable to require a GC on all 

refinery flares. 

As an alternative to a continuous 

compositional monitoring system, we 

are proposing to allow the use of grab 

samples along with engineering 

calculations to determine the individual 

component concentration. Like the online GC, the grab sampling option relies 

on compound speciation and is 

therefore flexible to use with any form 

of the operational limits we are 

proposing. The disadvantage of this 

option is that if a grab sample indicates 

non-compliance with the operational 

limits, the permitting authority could 

presume non-compliance from the time 

of the previous grab sample indicating 

compliance, which would include all 

15-minute periods in that time period. 

However, there are a number of 

situations where the refinery owner or 

operator may find this option 

advantageous. For example, some flares 

receive flows only from a specific 

process with a consistent composition 

and high heat content. In this case, the 

owner or operator may elect to actively 

adjust the assist gas flow rates using the 

expected vent gas composition and rely 

on the analysis of the grab sample to 

confirm the expected vent gas 

composition. This alternative may also 

be preferred for flares that are used 

infrequently (non-routine flow flares) or 

that have flare gas recovery systems 

designed and operated to recover 100 

percent of the flare gas under typical 

conditions. For these flares, flaring 

events may be so seldom that the 

refinery owner or operator may prefer 

the uncertainty in proactive control to 

the higher cost of continuous monitors 

that would seldom be used. 

As an alternative to performing a 

compositional analysis with use of a GC 

(through either on-line monitoring or 

analysis of the grab sample), we are 

proposing that owners or operators of 

flares may elect to install a device that 

directly monitors vent gas net heating 

value (i.e., a calorimeter). If the owner 

or operator elects this monitoring 

method, we are proposing that they 

must comply with the operating limits 

that are based on the net heating value 

operating limit. Similarly, we are also 

proposing that owners or operators of 

flares may elect to install a device that 

directly monitors the total hydrocarbon 

content of the flare vent gas (as a 

measure of the combustibles 

concentration). If the owner or operator 

elects this monitoring method, they 

must comply with the operating limits 

that are based on the combustibles 

concentration. 

e. Data Averaging Periods for Flare Gas 

Operating Limits 

We are proposing to use a 15-minute 

block averaging period for each 

proposed flare operating parameter 

(including flare tip velocity) to ensure 

that the flare is operated within the 

appropriate operating conditions. As 

flare vent gas flow rates and 

composition can change significantly 

over short periods of time, a short 

averaging time was considered to be the 

most appropriate for assessing proper 

flare performance. Furthermore, since 

flare destruction efficiencies can fall 

precipitously fast below the proposed 

operating limits, short time periods 

where the operating limits are not met 

could seriously impact the overall 

performance of the flare. With longer 

averaging times, there may be too much 

opportunity to mask these short periods 

of poor performance (i.e., to achieve the 

longer-term average operating limit 

while not achieving a high destruction 

efficiency over that time period because 

of short periods of poor performance). 

Moreover, a 15-minute averaging 

period is in line with the test data and 

the analysis used to establish the 

operating limits in this proposed rule. 

Ninety-three percent of the flare test 

runs used as a basis for establishing the 

proposed operating limits ranged in 

duration from 5 to 30 minutes, and 77 


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36910 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

percent of the runs ranged in duration 

from 5 to 20 minutes. The failure 

analysis (discussed in section IV.A.3.f of 

this preamble) considered minute-byminute test run data, but as there are 

limitations on how quickly 

compositional analyses can be 

conducted, many of the compositional 

data still reflect set values over 10- to 

15-minute time intervals. Because the 

GC compositional analyses generally 

require 10 to 15 minutes to conduct, 

shorter averaging times are not practical. 

To be consistent with the available test 

data and to ensure there are no short 

periods of significantly poor 

performance, we are proposing 15- 

minute block averaging times. 

Given the short averaging times for 

the operating limits, we are proposing 

special calculation methodologies to 

enable refinery owners or operators to 

use ‘‘feed forward’’ calculations to 

ensure compliance with the operating 

limits on a 15-minute block average. 

Specifically, the results of the 

compositional analysis determined just 

prior to a 15-minute block period are to 

be used for the next 15-minute block 

average. Owners or operators of flares 

will then know the vent gas properties 

for the upcoming 15-minute block 

period and can adjust assist gas flow 

rates relative to vent gas flow rates to 

comply with the proposed operating 

limits. 

Owners or operators of flares that 

elect to use grab sampling and 

engineering calculations to determine 

compliance must still assess compliance 

on a 15-minute block average. The 

composition of each grab sample is to be 

used for the duration of the episode or 

until the next grab sample is taken. We 

are soliciting comment on whether this 

approach is appropriate, and whether 

grab samples are needed on a more 

frequent basis to ensure compliance 

with the operating limits. 

f. Other Peer Review Considerations 

In an effort to better inform the 

proposed new requirements for refinery 

flares, in the spring of 2012 the EPA 

summarized its preliminary findings on 

operating parameters that affect flare 

combustion efficiency in a technical 

report and put this report out for a letter 

review. Based on the feedback received, 

the EPA considered many of the 

concerns peer reviewers expressed in 

their comments in the development of 

this proposal for refinery flares (see 

memorandum, Peer Review of 

‘‘Parameters for Properly Designed and 

Operated Flares’’, in Docket ID Number 

EPA–HQ–OAR–2010–0682). While the 

more substantive issues have been 

previously discussed in sections 

IV.A.3.a through e of this preamble, the 

following discussion addresses other 

peer review considerations that the EPA 

either discussed in the peer review 

technical document or considered from 

comments received by the peer review 

panel that played a role in the 

development of this proposal. 

Test data quality and analysis. For 

steam-assisted flares, we asked peer 

reviewers to comment on our criteria for 

excluding available flare test data from 

our analyses. In general, peer reviewers 

considered the EPA’s reasons for 

removing certain test data (prior to 

performing any final analysis) to be 

appropriate; however, one reviewer 

suggested the EPA complete an analysis 

of quality on the data before applying 

any criteria, and several reviewers 

commented on the level of scrutiny of 

the 10 data points specifically discussed 

in the technical report for not meeting 

the combustion zone LFL trend. These 

reviewers stated it appeared the EPA 

had scrutinized test data more if it were 

inconsistent with the LFL threshold 

conclusions made in the report. 

Although we felt it was appropriate to 

discuss specific test data not fitting the 

trend, we do agree with the reviewers 

that a more general and standard set of 

criteria should be applied to all test data 

prior to making any conclusion. In 

addition, other peer reviewers saw no 

reason why the EPA should exclude 0- 

percent combustion efficiency data 

points, or data points where smoking 

occurs, or single test runs when there 

was also a comparable average test run. 

Therefore, in response to these peer 

review comments, the EPA performed a 

validation and usability analysis on all 

available test data. This resulted in a 

change to the population of test data 

used in our final analysis (see technical 

memorandum, Flare Performance Data: 

Summary of Peer Review Comments and 

Additional Data Analysis for SteamAssisted Flares, in Docket ID Number 

EPA–HQ–OAR–2010–0682 for a more 

detailed discussion of the data quality 

and analysis). 

To help determine appropriate 

operating limits, several peer reviewers 

suggested the EPA perform a falsepositive-to-false-negative comparison 

(or failure type) analysis between the 

potential parameters discussed in the 

technical report as indicators of flare 

performance. The reviewers suggested 

that the EPA attempt to minimize the 

standard error of all false positives (i.e., 

poor observed combustion efficiency 

when the correlation would predict 

good combustion) and false negatives 

(i.e., good observed combustion 

efficiency when the correlation would 

predict poor combustion). In response to 

these comments, the EPA has conducted 

a failure analyses of these parameters 

which helped form the basis for the 

operating limits we are proposing for 

flares (see technical memorandum, 

Petroleum Refinery Sector Rule: 

Operating Limits for Flares, in Docket ID 

Number EPA–HQ–OAR–2010–0682). 

Some peer reviewers contended that it 

is appropriate for the EPA to round each 

established operating limit to the 

nearest whole number, because using a 

decimal implies far more accuracy and 

reliability than can be determined from 

the test data. Based on these comments, 

we have given more consideration to the 

number of significant figures used in the 

operating limits, and we are proposing 

to use two significant figures for the 

flare operating limits in these proposed 

amendments. 

Multiple peer reviewers performed 

additional analyses to try and determine 

the appropriateness of the limits raised 

in the technical report. Some peer 

reviewers tried to fit the data to a curve, 

others performed various failure 

analyses, while others looked at 

different metrics not discussed in the 

technical report (see memorandum, Peer 

Review of ‘‘Parameters for Properly 

Designed and Operated Flares’’, in 

Docket ID Number EPA–HQ–OAR– 

2010–0682). Based on the conclusions 

drawn from these various analyses, a 

range of combustion zone net heating 

value targets from 200 Btu/scf to 450 

Btu/scf were identified as metrics that 

would provide a high level of certainty 

regarding good combustion in flares 

(Note: 450 Btu/scf was the assumed to 

be approximately equivalent to a 

combustion zone LFL of 10 percent). We 

solicit comment on this range and the 

appropriateness for which the operating 

limits selected in this proposal will 

ensure compliance with the MACT 

requirements for vents at petroleum 

refineries. 

Effect of supplemental gas use. Most 

flares normally operate at a high 

turndown ratio, which means the actual 

flare gas flow rate is much lower than 

what the flare is designed to handle. In 

addition, steam-assisted flares have a 

manufacturers’ minimum steam 

requirement in order to protect the flare 

tip. A combination of high turndown 

ratio and minimum steam requirement 

will likely require some owners or 

operators to add supplemental gas to 

achieve one of the combustion zone gas 

operating limits we are proposing here 

(e.g., combustion zone combustibles 

concentration (Ccz) ≥ 18 volume percent; 

combustion zone lower flammability 

limit (LFLcz) ≤ 15 volume percent; or 

combustion zone net heating value 

(NHVcz) ≥ 270 Btu/scf). However, fineVerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2

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tuning the actual steam flow to the flare 

should significantly reduce the need for 

supplemental gas. We considered 

proposing a steam-to-vent gas ratio 

limitation on steam-assisted flares. 

However, a steam-to-vent gas ratio alone 

cannot fully address over-steaming 

because it would not account for the 

variability of chemical properties within 

the flare gas. We request that 

commenters on this issue provide 

supporting documentation on their 

potential to reduce steam as well as 

their use of supplemental gas to achieve 

the proposed operating limit(s), and 

how it could affect cost and potential 

emissions. We emphasize that the 

amount and cost of supplemental gas 

should be reflective of conditions after 

any excess steam use has been rectified. 

It would not be valuable to consider 

situations where large amounts of 

supplemental gas are added, while 

steam is simultaneously added far in 

excess of the amount recommended by 

the flare manufacturer or other guidance 

documents. 

In assessing the combustion zone gas 

and looking at all the gas at the flare tip, 

another potential source of added heat 

content comes from the gas being used 

as fuel to maintain a continuously lit 

pilot flame. However, since pilot gas is 

being used as fuel for a continuous 

ignition source and is burned to create 

a flame prior to (or at the periphery of) 

the combustion zone, this gas does not 

directly contribute to the heat content or 

flammability of the gas being sent to the 

flare to be controlled under Refinery 

MACT 1 or 2. In addition, in looking at 

available test data, the pilot gas flow 

rate is generally so small that it does not 

significantly impact the combustion 

zone properties at all. Furthermore, by 

leaving pilot gas out of the combustion 

zone operating limit calculations, the 

equations become simplified and a 

requirement to continuously monitor 

pilot gas flow rate can be avoided. 

Therefore, we are proposing that the 

owner or operator not factor in the pilot 

gas combustible component (or net 

heating value) contribution when 

determining any of the three proposed 

combustion zone gas operating limits 

(Ccz, LFLcz, or NHVcz). 

Effects of wind on flame performance. 

Several published studies have 

investigated the significance of wind on 

the fluid mechanics of a flare flame (see 

technical memorandum, Parameters for 

Properly Designed and Operated Flares, 

in Docket ID Number EPA–HQ–OAR– 

2010–0682). These studies were 

conducted in wind tunnels at crosswind 

velocities up to about 60 miles per hour 

(mph) and have illustrated that 

increased crosswind velocity can have a 

strong effect on flare flame dimensions 

and shape, causing the flame to become 

segmented or discontinuous, and wakedominated (i.e., where the flame is bent 

over on the downwind side of a flare 

pipe and is imbedded in the wake of the 

flare tip), which may lead to poor flare 

performance due to fuel stripping. 

However, the majority of this research is 

confined to laboratory studies on flares 

with effective diameters less than 3 

inches, which have been shown not to 

be representative of industrial-sized 

flares. Research that does include 

performance tests conducted on flares 

scalable to refinery flares (i.e., 3-inch, 4- 

inch, and 6-inch pipe flares) was 

conducted with flare tip velocities as 

low as 0.49 feet per second and 

crosswind velocities of about 26 mph 

and less; all tests resulted in good flare 

performance. Furthermore, there is no 

indication that crosswind velocities 

negatively impact flare performance in 

the recent flare performance tests. These 

tests were conducted on various sizes of 

industrial flares (i.e., effective diameters 

ranging between 12 and 54 inches) in 

winds of about 22 mph and less, and at 

relatively low flare tip velocities (i.e., 10 

feet per second or less). (See Parameters 

for Properly Designed and Operated 

Flares, in Docket ID Number EPA–HQ– 

OAR–2010–0682.) 

We are aware of flare operating 

parameters that consider crosswind 

velocity; however, using the available 

flare performance test data, we were 

unable to determine a clear correlation 

that would be appropriate for all 

refinery flares. For example, the 

momentum flux ratio (MFR) is a 

measure of momentum strength of the 

flare exit gas relative to the crosswind 

(i.e., the product of flare exit gas density 

and velocity squared divided by the 

product of air density and crosswind 

velocity squared). The plume buoyancy 

factor is the ratio of crosswind velocity 

to the flare exit gas velocity, and 

considers the area of the flare pipe. The 

power factor is the ratio of the power of 

the crosswind to the power of 

combustion of the flare gas. Because the 

available flare performance test data 

have relatively low flare tip velocities, 

and crosswind velocities were relatively 

constant during each test run, we are 

unable to examine these parameters to 

the fullest extent. 

In light of the data available from 

performance tests (Gogolek et al., 2010), 

we asked peer reviewers whether the 

MFR could be used in crosswind 

velocities greater than 22 mph at the 

flare tip to indicate wake-dominated 

flame situations. We also asked for 

comment on observations that in the 

absence of crosswind greater than 22 

mph, a low MFR does not necessarily 

indicate poor flare performance. Peer 

reviewers suggested that there are no 

data available from real industrial flares 

in winds greater than 22 mph to support 

that MFR could be used to identify 

wake-dominated flame situations. In 

addition, we received no further peer 

review comments that have caused us to 

reconsider the observation we made in 

the April 2012 technical report that in 

the absence of crosswind greater than 22 

mph, a low MFR does not necessarily 

indicate poor flare performance. We 

request comment with supporting data 

and rationale on any of these, or other 

parameters, as a measure of wind effects 

on flare combustion efficiency. 

We considered including observation 

requirements for detecting segmented or 

discontinuous wake-dominated flames, 

especially for winds greater than 22 

mph (where limited test data is 

available). However, owners or 

operators of flares cannot control the 

wind speed, and it would be 

detrimental to increase the quantity of 

flared gases in high crosswind 

conditions in efforts to improve the 

MFR and reduce wake-dominated flow 

conditions. Furthermore, there is no 

indication that crosswind velocities 

negatively impact flare performance in 

the recent flare performance tests. For 

these reasons, we are not proposing any 

flare operating parameter(s) to minimize 

wind effects on flare combustion 

efficiency. 

g. Impacts of the Flare Operating and 

Monitoring Requirements 

The EPA expects that the newly 

proposed requirements for refinery 

flares discussed in this section will 

affect all flares at petroleum refineries. 

Based on data received as a result of the 

Refinery ICR, we estimate that there are 

510 flares operating at petroleum 

refineries and that 285 of these receive 

flare vent gas flow on a regular basis 

(i.e., other than during periods of 

startup, shutdown, and malfunction). 

Costs were estimated for each flare for 

a given refinery, considering operational 

type (e.g., receive flare vent gas flow on 

a regular basis, use flare gas recovery 

systems to recover 100 percent of 

routine flare flow, handle events during 

startup, shutdown, or malfunction only, 

etc.) and current monitoring systems 

already installed on each individual 

flare. Costs for any additional 

monitoring systems needed were 

estimated based on installed costs 

received from petroleum refineries and, 

if installed costs were unavailable, costs 

were estimated based on vendorpurchased equipment. The baseline 

emission estimate and the emission 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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reductions achieved by the proposed 

rule were estimated based on current 

vent gas and steam flow data submitted 

by industry representatives. The results 

of the impact estimates are summarized 

in Table 4 of this preamble. We note 

that the requirements for refinery flares 

we are proposing in this action will 

ensure compliance with the Refinery 

MACT standards when flares are used 

as an APCD. As such, these proposed 

operational and monitoring 

requirements for flares at refineries have 

the potential to reduce excess emissions 

from flares by approximately 3,800 tpy 

of HAP, 33,000 tpy of VOC, and 327,000 

metric tonnes per year of CO2e. The 

VOC compounds are non-methane, nonethane total hydrocarbons. According to 

the Component 2 database from the 

Refinery ICR, there are approximately 

50 individual HAP compounds 

included in the emission inventory for 

flares, but many of these are emitted in 

trace quantities. A little more than half 

of the HAP emissions from flares are 

attributable to hexane, followed next by 

benzene, toluene, xylenes, and 1,3- 

butadiene. For more detail on the 

impact estimates, see the technical 

memorandum Petroleum Refinery 

Sector Rule: Flare Impact Estimates in 

Docket ID Number EPA–HQ–OAR– 

2010–0682. 

TABLE 4—NATIONWIDE COST IMPACTS OF PROPOSED AMENDMENTS TO ENSURE PROPER FLARE PERFORMANCE

Affected source 

Total capital 

investment 

(million $) 

Total 

annualized 

costs 

(million $/yr) 

Flare Monitoring ....................................................................................................................................................... 147 36.3 

4. Vent Control Bypasses 

a. Relief Valve Discharges 

Refinery MACT 1 recognized relief 

valve discharges to be the result of 

malfunctions. Relief valves are designed 

to remain closed during normal 

operation and only release as the result 

of unplanned and/or unpredictable 

events. A release from a relief valve 

usually occurs during an over 

pressurization of the system. However, 

emissions vented directly to the 

atmosphere by relief valves in organic 

HAP service contain HAP that are 

otherwise regulated under Refinery 

MACT 1. 

Refinery MACT 1 regulated relief 

valves through equipment leak 

provisions that applied only after the 

pressure relief occurred. In addition the 

rule followed the EPA’s then-practice of 

exempting startup, shutdown and 

malfunction (SSM) events from 

otherwise applicable emission 

standards. Consequently, with relief 

valve releases defined as unplanned and 

nonroutine and the result of 

malfunctions, Refinery MACT 1 did not 

restrict relief valve releases to the 

atmosphere but instead treated them the 

same as all malfunctions through the 

SSM exemption provision. 

In Sierra Club v. EPA, 551 F.3d 1019 

(D.C. Cir. 2008), the Court determined 

that the SSM exemption violates the 

CAA. See section IV.E of this preamble 

for additional discussion. To ensure this 

standard is consistent with that 

decision, these proposed amendments 

remove the malfunction exemption in 

Refinery MACT 1 and 2 and provide 

that emissions of HAP may not be 

discharged to the atmosphere from relief 

valves in organic HAP service. To 

ensure compliance with this 

amendment, we are also proposing to 

require that sources monitor relief 

valves using a system 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. Pressure release 

events from relief valves to the 

atmosphere have the potential to emit 

large quantities of HAP. Where a 

pressure release occurs, it is important 

to identify and mitigate it as quickly as 

possible. For purposes of estimating the 

costs of this requirement, we assumed 

that operators would install electronic 

monitors on each relief valve that vents 

to the atmosphere to identify and record 

the time and duration of each pressure 

release. However, we are proposing to 

allow owners and operators to use a 

range of methods to satisfy these 

requirements, including the use of a 

parameter monitoring system (that may 

already be in place) on the process 

operating pressure that is sufficient to 

indicate that a pressure release has 

occurred as well as record the time and 

duration of that pressure release. Based 

on our cost assumptions, the nationwide 

capital cost of installing these electronic 

monitors is $9.54 million and the 

annualized capital cost is $1.36 million 

per year. 

As defined in the Refinery MACT 

standards, relief valves are valves used 

only to release unplanned, nonroutine 

discharges. A relief valve discharge 

results from an operator error, a 

malfunction such as a power failure or 

equipment failure, or other unexpected 

cause that requires immediate venting of 

gas from process equipment in order to 

avoid safety hazards or equipment 

damage. Even so, to the extent that there 

are atmospheric HAP emissions from 

relief valves, we are required to follow 

the Sierra Club ruling to address those 

emissions in our rule, and we can no 

longer exempt them as permitted 

malfunction emissions as we did under 

Refinery MACT 1. Our information 

indicates that there are approximately 

12,000 pressure relief valves that vent to 

the atmosphere (based on the ICR 

responses) and that the majority of relief 

valves in the refining industry are not 

atmospheric, but instead are routed to 

flares (see letter from API, Docket Item 

Number EPA–HQ–OAR–2010–0682– 

0012). We request comment on our 

approach and on alternatives to our 

approach to regulating releases from 

pressure relief valves and also request 

commenters to provide information 

supporting any such comments. 

b. Bypass Lines 

For a closed vent system containing 

bypass lines that can divert the stream 

away from the APCD to the atmosphere, 

Refinery MACT 1 requires the owner or 

operator to either: (1) Install, maintain 

and operate a continuous parametric 

monitoring system (CPMS) for flow on 

the bypass line that is capable of 

detecting whether a vent stream flow is 

present at least once every hour, or (2) 

secure the bypass line valve in the nondiverting position with a car-seal or a 

lock-and-key type configuration. Under 

option 2, the owner or operator is also 

required to inspect the seal or closure 

mechanism at least once per month to 

verify the valve is maintained in the 

non-diverting position (see 40 CFR 

63.644(c) for more details). We are 

proposing under CAA section 112(d)(2) 

and (3) that the use of a bypass at any 

time to divert a Group 1 miscellaneous 

process vent is a violation of the 

emission standard, and to specify that if 

option 1 is chosen, the owner or 

operator would be required to install, 


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maintain and operate a CPMS for flow 

that is capable of recording the volume 

of gas that bypasses the APCD. The 

CMPS must be equipped with an 

automatic alarm system that will alert 

an operator immediately when flow is 

detected in the bypass line. We are 

proposing this revision because, as 

noted above, APCD are not to be 

bypassed because doing so could result 

in a release of regulated organic HAP to 

the atmosphere. In Sierra Club v. EPA, 

551 F.3d 1019 (D.C. Cir. 2008), the Court 

determined that standards under CAA 

section 112(d) must provide for 

compliance at all times and a release of 

uncontrolled HAP to the atmosphere is 

inconsistent with that requirement. 

c. In Situ Sampling Systems (Onstream 

Analyzers) 

The current Refinery MACT 1 

definition of ‘‘miscellaneous process 

vent’’ states that ‘‘in situ sampling 

systems (onstream analyzers)’’ are not 

miscellaneous process vents. 40 CFR 

63.641. For several reasons, we are 

proposing to remove ‘‘in situ sampling 

systems (onstream analyzers)’’ from the 

list of vents not considered 

miscellaneous process vents. First, the 

language used in this exclusion is 

inconsistent. We generally consider ‘‘in 

situ sampling systems’’ to be nonextractive samplers or in-line samplers. 

There are certain in situ sampling 

systems where the measurement is 

determined directly via a probe placed 

in the process stream line. Such 

sampling systems do not have an 

atmospheric vent, so excluding these 

from the definition of ‘‘miscellaneous 

process vent’’ is not meaningful. The 

parenthetical term ‘‘onstream analyzers’’ 

generally refers to sampling systems that 

feed directly to an analyzer located at 

the process unit, and has been 

interpreted to exclude the ‘‘onstream’’ 

analyzer’s vent from the definition of 

miscellaneous process vents. As these 

two terms do not consistently refer to 

the same type of analyzer, the provision 

is not clear. 

Second, we find that there is no 

technical reason to include analyzer 

vents in a list of vents not considered 

miscellaneous process vents. For 

extractive sampling systems and 

systems with purges, the equipment 

leak standards in Refinery MACT 1 

require that the material be returned to 

the process or controlled. Thus, the only 

potential emissions from any sampling 

system compliant with the Refinery 

MACT 1 equipment leak provisions 

would be from the analyzer’s ‘‘exhaust 

gas’’ vent. The parenthetical term 

‘‘onstream analyzers’’ indicates that the 

focus of the exemption is primarily on 

the analyzer (or analyzer vent) rather 

than the sampling system. This phrase 

has been interpreted to exclude the 

‘‘onstream’’ analyzer’s vent from the 

definition of miscellaneous process 

vents. Analyzer venting is expected to 

be routine (continuous or daily 

intermittent venting). 

We are proposing to delete this 

exclusion from the definition of 

‘‘miscellaneous process vent’’ and to 

require these vents to meet the 

standards applicable to miscellaneous 

process vents at all times. We expect 

most analyzer vents to be Group 2 

miscellaneous process vents because 

analyzer vents are not expected to 

exceed the 72 pounds per day (lb/day) 

emissions threshold for Group 1 

miscellaneous process vents. However, 

if there are larger analyzer vents that 

exceed the 72 lb/day emissions 

threshold for Group 1 miscellaneous 

process vents, these emission sources 

would need to be controlled as a Group 

1 miscellaneous process vent under this 

proposal. We solicit comment on the 

existence of any onstream analyzers that 

have VOC emissions greater than 72 lb/ 

day and why such vents are not 

amenable to control. 

d. Refinery Flares and Fuel Gas Systems 

The current definition of 

‘‘miscellaneous process vent’’ in 

Refinery MACT 1 states that ‘‘gaseous 

streams routed to a fuel gas system’’ are 

not miscellaneous process vents. 

Furthermore, the affected source subject 

to Refinery MACT 1 does not 

specifically include ‘‘emission points 

routed to a fuel gas system, as defined 

in § 63.641 of this subpart.’’ The EPA 

allowed these exemptions for streams 

routed to fuel gas systems because 

according to the 1994 preamble for 

Refinery MACT 1, ‘‘these vents are 

already controlled to the most stringent 

levels achievable’’ (59 FR 36141, July 

15, 1994). Since gaseous streams routed 

to a fuel gas system are eventually 

burned as fuel, typically in a boiler or 

process heater, these combustion 

controls burning the gaseous streams as 

fuel effectively achieve this most 

stringent level of control (i.e., 98- 

percent organic HAP reduction or an 

outlet organic HAP concentration of 20 

ppmv for all vent streams). However, 

there can be instances when gaseous 

streams from the fuel gas system that 

would otherwise be combusted in a 

boiler or process heater are instead 

routed to a flare (e.g., overpressure in 

the fuel gas system, used as flare sweep 

gas, used as flare purge gas). In cases 

where an emission source is required to 

be controlled in Refinery MACT 1 and 

2 but is routed to a fuel gas system, we 

are proposing that any flare receiving 

gases from that fuel gas system must 

comply with the flare operating and 

monitoring requirements discussed in 

section IV.A.3 of this preamble. 

B. What are the results and proposed 

decisions based on our technology 

review? 

1. Refinery MACT 1—40 CFR Part 63, 

Subpart CC 

Refinery MACT 1 sources include 

miscellaneous process vents, storage 

vessels, equipment leaks, gasoline 

loading racks, marine vessel loading 

operations, cooling towers/heat 

exchange systems, and wastewater. 

a. Miscellaneous Process Vents 

Many unit operations at petroleum 

refineries generate gaseous streams 

containing HAP. These streams may be 

routed to other unit operations for 

additional processing (e.g., a gas stream 

from a reactor that is routed to a 

distillation unit for separation) or they 

may be sent to a blowdown system or 

vented to the atmosphere. 

Miscellaneous process vents emit gases 

to the atmosphere, either directly or 

after passing through recovery and/or 

APCD. Under 40 CFR 63.643, the owner 

or operator must reduce organic HAP 

emissions from miscellaneous process 

vents using a flare that meets the 

equipment specifications in 40 CFR 

63.11 of the General Provisions (subpart 

A) or use APCD (e.g., thermal oxidizers, 

carbon adsorbers) to reduce organic 

HAP emissions by 98 weight-percent or 

to a concentration of 20 parts per 

million by volume (ppmv) dry basis, 

corrected to 3-percent oxygen. 

In the technology review, we did not 

identify any practices, processes or 

control technologies beyond those 

already required by Refinery MACT 1. 

Therefore, we are proposing that it is 

not necessary to revise Refinery MACT 

1 requirements for miscellaneous 

process vents pursuant to CAA section 

112(d)(6). 

b. Storage Vessels 

Storage vessels (also known as storage 

tanks) are used to store liquid and 

gaseous feedstocks for use in a process, 

as well as liquid and gaseous products 

coming from a process. Most storage 

vessels are designed for operation at 

atmospheric or near atmospheric 

pressures; high-pressure vessels are 

used to store compressed gases and 

liquefied gases. Atmospheric storage 

vessels are typically cylindrical with a 

vertical orientation, and they are 

constructed with either a fixed roof or 

a floating roof. Some, generally small, 


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atmospheric storage vessels are oriented 

horizontally. High pressure vessels are 

either spherical or horizontal cylinders. 

Section 63.646(a) requires certain 

existing and new storage vessels to 

comply with 40 CFR 63.119 through 40 

CFR 63.121 of the HON. Under 40 CFR 

63.119 through 63.121, storage vessels 

must be equipped with an internal 

floating roof with proper seals, an 

external floating roof with proper seals, 

an external floating roof converted to an 

internal floating roof with proper seals 

or a closed vent system routed to an 

APCD that reduces HAP emissions by 

95 percent. Storage vessels at existing 

sources that use floating roofs are not 

required under Refinery MACT 1 to 

install certain fitting controls included 

in 40 CFR 63.1119 of the HON (e.g., 

gaskets for automatic bleeder vents, slit 

fabric covers for sample wells, flexible 

fabric seals or gasketed sliding covers 

for guidepoles and gasketed covers for 

other roof openings). See 40 CFR 

63.646(c). 

In 2012, we conducted a general 

analysis to identify the latest 

developments in practices, processes 

and control technologies for storage 

vessels at chemical manufacturing 

facilities and petroleum refineries, and 

we estimated the impacts of applying 

those practices, processes and 

technologies to model storage vessels. 

(See Survey of Control Technology for 

Storage Vessels and Analysis of Impacts 

for Storage Vessel Control Options, 

January 20, 2012, Docket Item Number 

EPA–HQ–OAR–2010–0871–0027.) We 

used this analysis as a starting point for 

conducting the technology review for 

storage vessels at refineries. In this 

analysis, we identified fitting controls, 

particularly controls for floating roof 

guidepoles, and monitoring equipment 

(liquid level monitors and leak 

monitors) as developments in practices, 

processes and control technologies for 

storage vessels. In our refinery-specific 

review, we also noted that the Group 1 

storage vessel size and vapor pressure 

thresholds in Refinery MACT 1 were 

higher than those for storage vessels in 

MACT standards for other similar 

industries. Therefore, we also evaluated 

revising the Group 1 storage vessel 

thresholds as a development in 

practices for storage vessels in the 

refining industry. 

We used data from our 2011 ICR to 

evaluate the impacts of requiring the 

additional controls identified in the 

technology review for the petroleum 

refinery source category. The emission 

reduction options identified during the 

technology review are: (1) Requiring 

guidepole controls and other fitting 

controls for existing external or internal 

floating roof tanks as required in the 

Generic MACT for storage vessels (40 

CFR part 63, subpart WW) in 40 CFR 

63.1063; (2) option 1 plus revising the 

definition of Group 1 storage vessel to 

include smaller capacity storage vessels 

and/or storage vessels containing 

materials with lower vapor pressures 

and (3) option 2 plus requiring 

additional monitoring to prevent roof 

landings, liquid level overfills and to 

identify leaking vents and fittings from 

tanks. We identified options 1 and 2 as 

developments in practices, processes 

and control technologies because these 

options are required for similar tanks in 

some chemical manufacturing MACT 

standards and we believe they are 

technologically feasible for storage 

vessels at refineries (e.g., Generic 

MACT, the HON). Option 3 is also an 

improvement in practices because these 

monitoring methods have been required 

for refineries by other regulatory 

agencies. 

Under option 1, we considered the 

impacts of requiring improved deck 

fittings and controls for guidepoles as is 

required for other chemical 

manufacturing sources in the Generic 

MACT. Specifically, we considered 

these controls for storage vessels with 

existing internal or external floating roof 

tanks. This option also includes the 

inspection, recordkeeping, and 

reporting requirements set forth in the 

Generic MACT to account for the 

additional requirements for fitting 

controls. We are aware of recent waiver 

requests to EPA to allow in-service, topside inspections instead of the out-ofservice inspections required on a 10- 

year basis for internal floating roof tanks 

for facilities that are currently subject to 

40 CFR part 60, subpart Kb and Refinery 

MACT 1. The requirements of Generic 

MACT allow for this option if there is 

visual access to all the deck 

components. Under option 1, we 

considered the Generic MACT 

provisions for in-service, top-side 

inspection. We are requesting comment 

on whether or not these in-service 

inspections are adequate for identifying 

conditions that are indicative of deck, 

fitting, and rim seal failures; we are also 

requesting comment on methods to 

effectively accomplish top-side 

inspections. 

For option 2, we evaluated revising 

the definition of Group 1 storage vessels 

to include smaller capacity storage 

vessels and/or storage vessels with 

lower vapor pressure, such that these 

additional storage vessels would be 

subject to the Group 1 control 

requirements. For storage vessels at 

existing sources, Refinery MACT 1 

currently defines Group 1 storage 

vessels to be those with a capacity of 

177 cubic meters (46,760 gallons) or 

greater, and a true vapor pressure of 

10.4 kilopascals (1.5 pounds per square 

inch absolute (psia)) or greater. Under 

option 2, we evaluated the impacts of 

changing the definition of Group 1 

storage vessels to include storage vessels 

with a capacity of 151 cubic meters 

(40,000 gallons) or greater and a true 

vapor pressure of 5.2 kilopascals (0.75 

psia) or greater, and also evaluated 

including storage vessels with a 

capacity of 76 cubic meters (20,000 

gallons) or greater (but less than 151 

cubic meters), provided the true vapor 

pressure of the stored liquid is 13.1 

kilopascals (1.9 psia) or greater. These 

thresholds are consistent with storage 

vessel standards already required for the 

chemical industry (e.g., the HON). We 

believe the predominant effect of 

changing these thresholds will be fixed 

roof tanks at existing petroleum 

refineries shifting from Group 2 storage 

vessels to Group 1 storage vessels. These 

fixed roof tanks would thus need to be 

retrofitted with floating roofs or vented 

to an APCD in order to comply with the 

provisions for Group 1 storage vessels. 

We estimated the impacts of option 2 by 

assuming all uncontrolled fixed roof 

storage vessels that meet or exceed the 

proposed new applicability 

requirements for Group 1 storage vessels 

(based on the information collected in 

the Refinery ICR) would install an 

internal floating roof with a single rim 

seal and deck fittings to the existing 

fixed roof tank. The costs of these fixed 

roof retrofits were added to the costs 

determined for option 1 to determine 

the cost of option 2. 

Under option 3, we considered the 

impacts of including additional 

monitoring requirements for Group 1 

storage vessels (in addition to fitting 

controls and fixed roof retrofits 

considered under options 1 and 2). The 

monitoring requirements evaluated 

include monitoring of internal or 

external floating roof tanks with EPA 

Method 21 (of 40 CFR part 60, 

Appendix A–7) or optical gas imaging 

for fittings, and requiring the use of 

liquid level overfill warning monitors 

and roof landing warning monitors. 

These costs were estimated based on the 

total number of Group 1 storage vessels 

considering the change in the 

applicability thresholds included in 

option 2. For further details on the 

assumptions and methodologies used in 

this analysis, see the technical 

memorandum titled Impacts for Control 

Options for Storage Vessels at 

Petroleum Refineries, in Docket ID 

Number EPA–HQ–OAR–2010–0682. 


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28The VOC recovery credit is $560 per ton, based 

on $1.75/gal price for generic refinery product 

(gasoline/diesel fuel). (See the technical 

memorandum titled Impacts for Control Options for 

Storage Vessels at Petroleum Refineries, in Docket 

ID Number EPA–HQ–OAR–2010–0682 for more 

details.) 

Table 5 of this preamble presents the 

impacts for the three options 

considered. Although the options were 

considered cumulatively, the 

calculation of the incremental cost 

effectiveness allows us to assess the 

impacts of the incremental change 

between the options. As seen by the 

incremental cost effectiveness column 

in Table 5, both options 1 and 2 result 

in a net cost savings considering the 

VOC recovery credit for product not lost 

to the atmosphere from the storage 

vessel.28 We seek comment on the 

appropriateness of the VOC recovery 

credit we used. The incremental cost 

effectiveness for option 3 exceeds 

$60,000 per ton of HAP removed. We 

consider option 3 not to be cost effective 

and are not proposing to require this 

additional monitoring. 

Based on this analysis, we consider 

option 2 to be cost effective. We are, 

therefore, proposing to revise Refinery 

MACT 1 to cross-reference the 

corresponding storage vessel 

requirements in the Generic MACT 

(including requirements for guidepole 

controls and other fittings as well as 

inspection requirements), and to revise 

the definition of Group 1 storage vessels 

to include storage vessels with 

capacities greater than or equal to 

20,000 gallons but less than 40,000 

gallons if the maximum true vapor 

pressure is 1.9 psia or greater and to 

include storage tanks greater than 

40,000 gallons if the maximum true 

vapor pressure is 0.75 psia or greater. 

TABLE 5—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL OPTIONS FOR STORAGE VESSELS AT

PETROLEUM REFINERIES

Control option Capital cost 

(million $) 

Annualized costs without recovery cred- its (million $/yr) 

Emissions 

reduction, 

VOC 

(tpy) 

Emissions 

reduction, HAP 

(tpy) 

Cost effectiveness ($/ton HAP) 

Total annualized 

costs with VOC 

recovery 

credit (million $/yr) 

Overall cost 

effectiveness with VOC 

Rrcovery 

credit ($/ton HAP) 

Incremental 

cost effectiveness 

with VOC 

recovery 

credit ($/ton HAP) 

1 .................................................................................................................... 11.9 1.8 11,800 720 2,470 (4.8) (6,690) 

2 .................................................................................................................... 18.5 3.1 14,600 910 3,430 (5.0) (5,530) (1,140) 

3 .................................................................................................................... 36.4 9.6 16,000 1,000 9,580 0.56 560 61,500 

c. Equipment Leaks 

Equipment leaks are releases of 

process fluid or vapor from processing 

equipment, including pump and 

compressor seals, process valves, relief 

devices, open-ended valves and lines, 

flanges and other connectors, agitators 

and instrumentation systems. These 

releases occur primarily at the interface 

between connected components of 

equipment or in sealing mechanisms. 

Refinery MACT 1 requires the owner 

or operator of an existing source to 

comply with the equipment leak 

provisions in 40 CFR part 60, subpart 

VV (Standards of Performance for 

Equipment Leaks of VOC in the 

Synthetic Organic Chemicals 

Manufacturing Industry) for all 

equipment in organic HAP service. The 

term ‘‘in organic HAP service’’ means 

that a piece of equipment either 

contains or contacts a fluid (liquid or 

gas) that is at least 5 percent by weight 

of total organic HAP. Refinery MACT 1 

specifies that the owner or operator of 

a new source must comply with the 

HON, as modified by Refinery MACT 1. 

The provisions for both new and 

existing sources require inspection 

(either through instrument monitoring 

using EPA Method 21 of 40 CFR part 60, 

Appendix A–7, or other method such as 

visible inspection) and repair of leaking 

equipment. For existing sources, the 

leak definition under 40 CFR part 60, 

subpart VV triggers repair at an 

instrument reading of 10,000 parts per 

million (ppm) for all equipment 

monitored using EPA Method 21 of 40 

CFR part 60, Appendix A–7 (i.e., pumps 

and valves; instrument monitoring of 

equipment in heavy liquid service and 

connectors is optional). For new 

sources, the Refinery MACT 1-modified 

version of the HON triggers repair of 

leaks for pumps at 2,000 ppm and for 

valves at 1,000 ppm. Refinery MACT 1 

requires new and existing sources to 

install a cap, plug or blind flange, as 

appropriate, on open-ended valves or 

lines. Refinery MACT 1 does not require 

instrument monitoring of connectors for 

either new or existing sources. 

We conducted a general analysis to 

identify the latest developments in 

practices, processes and control 

technologies applicable to equipment 

leaks at chemical manufacturing 

facilities and petroleum refineries, and 

we estimated the impacts of applying 

the identified practices, processes and 

technologies to several model plants. 

(See Analysis of Emissions Reduction 

Techniques for Equipment Leaks, 

December 21, 2011, Docket Item 

Number EPA–HQ–OAR–2010–0869– 

0029.) We used this general analysis as 

a starting point for conducting the 

technology review for equipment leaks 

at refineries, but did not identify any 

developments beyond those in the 

general analysis. We estimated the 

impacts of applying the practices, 

processes and technologies identified in 

the general analysis to equipment leaks 

in petroleum refinery processes using 

the information we collected through 

the 2011 Refinery ICR. In general, leak 

detection and repair (LDAR) programs 

have been used by many industries for 

years to control emissions from 

equipment leaks. Over the years, repair 

methods have improved and owners 

and operators have become more 

proficient at implementing these 

programs. The specific developments 

identified include: (1) Requiring repair 

of leaks at a concentration of 500 ppm 

for valves and 2,000 ppm for pumps for 

new and existing sources (rather than 

10,000 ppm for valves and pumps at 

existing sources and 1,000 for valves at 

new sources); (2) requiring monitoring 

of connectors using EPA Method 21 (of 

40 CFR part 60, Appendix A–7) and 

repair of leaks for valves and pumps at 

a concentration of 500 ppm; and (3) 

allowing the use of optical gas imaging 

devices as an alternative method of 

monitoring. 

The first option we evaluated was to 

require repair based on a leak definition 

of 500 ppm for valves and a leak 

definition of 2,000 ppm for pumps at 

both new and existing sources. The 

nationwide costs and emission 

reduction impacts of applying those 

lower leak definitions to equipment 

leaks at petroleum refineries are shown 

in Table 6 of this preamble. For further 

details on the assumptions and 

methodologies used in this analysis, see 

the technical memorandum titled 

Impacts for Equipment Leaks at 

Petroleum Refineries, in Docket ID 

Number EPA–HQ–OAR–2010–0682. 


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The emissions reduction results in 

product not being lost by a leak; this 

additional product can be sold to 

generate revenue, referred to as a VOC 

recovery credit. Table 6 shows costs and 

cost effectiveness both with and without 

the VOC recovery credit. Based on the 

estimated organic HAP emission 

reductions of 24 tpy and the cost 

effectiveness of $14,100 per ton of 

organic HAP (including VOC recovery 

credit), we consider lowering the leak 

definition not to be a cost-effective 

option for reducing HAP emissions. We 

are, therefore, proposing that it is not 

necessary to revise Refinery MACT 1 

pursuant to CAA section 112(d)(6) to 

require repair of leaking valves at 500 

ppm or greater and repair of leaking 

pumps at 2,000 ppm or greater. 

TABLE 6—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF MONITORING AND REPAIR REQUIREMENTS AT

LOWER LEAK DEFINITIONS

[500 ppm for valves; 2,000 ppm for pumps] 

Capital cost 

(million $) 

Annualized costs 

without recovery credits (million $/yr) 

Emissions reduction, VOC 

(tpy) 

Emissions reduction, HAP 

(tpy) 

Cost effectiveness 

($/ton VOC) 

Cost effectiveness 

($/ton HAP) 

Total annualized 

costs with VOC 

recovery credit 

(million $/yr) 

Overall cost 

effectiveness 

with VOC 

recovery credit 

($/ton VOC) 

Overall cost 

effectiveness 

with VOC 

recovery credit 

($/ton HAP) 

1.22 ............................................... 0.53 342 24 1,550 22,100 0.34 987 14,100 

We note that we are aware that some 

owners and operators are required to 

repair leaking valves as low as 100 ppm 

and pumps as low as 500 ppm. 

However, we consider requiring repair 

of leaking valves at 500 ppm or greater 

and repair of leaking pumps at 2,000 

ppm or greater not to be cost effective. 

As documented in Analysis of 

Emissions Reduction Techniques for 

Equipment Leaks (December 21, 2011, 

in Docket ID Number EPA–HQ–OAR– 

2010–0869), the cost effectiveness for 

this option would be even higher than 

the values shown in Table 6 of this 

preamble. 

The second option we considered was 

connector monitoring and repair. 

Several standards applying to chemical 

manufacturing facilities, including the 

HON, include requirements for 

connector monitoring using EPA 

Method 21 (of 40 CFR part 60, 

Appendix A–7) and requirements for 

repair of any connector leaks above 500 

ppm VOC. Neither the Refinery MACT 

1 nor the NSPS for equipment leaks 

from refineries (40 CFR part 60, subpart 

GGG and 40 CFR part 60, subpart GGGa) 

currently require connector monitoring 

and repair (provisions are provided for 

connector monitoring in Refinery MACT 

1, but they are optional). We evaluated 

the costs and emissions reduction of 

requiring connector monitoring and 

repair requirements for equipment leaks 

at refineries. The nationwide costs and 

emission reduction impacts, both with 

and without VOC recovery credit, are 

shown in Table 7 of this preamble. For 

further details on the assumptions and 

methodologies used in this analysis, see 

the technical memorandum titled 

Impacts for Equipment Leaks at 

Petroleum Refineries, in Docket ID 

Number EPA–HQ–OAR–2010–0682. 

Based on the high annualized cost 

($13.9 million per year) and high cost 

effectiveness ($153,000 per ton of HAP) 

of connector monitoring and repair for 

equipment leaks at refineries, we are 

proposing that it is not necessary to 

revise Refinery MACT 1 pursuant to 

CAA section 112(d)(6) to require 

connector monitoring using EPA 

Method 21 (of 40 CFR part 60, 

Appendix A–7) and repair. 

TABLE 7—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF APPLYING MONITORING AND REPAIR

REQUIREMENTS TO CONNECTORS AT PETROLEUM REFINERIES

[500 ppm] 

Capital cost 

(million $) 

Annualized costs 

without recovery 

credits 

(million $/yr) 

Emissions 

reduction, VOC 

(tpy) 

Emissions 

reduction, HAP 

(tpy) 

Cost 

effectiveness 

($/ton VOC) 

Cost 

effectiveness 

($/ton HAP) 

Total annualized 

costs with VOC 

recovery credit 

(million $/yr) 

Overall cost 

effectiveness 

with VOC 

recovery credit 

($/ton VOC) 

Overall cost 

effectiveness 

with VOC 

recovery credit 

($/ton HAP) 

52.1 ............................................... 13.9 1,230 86 11,300 161,000 13.2 10,700 153,000 

Another development identified was 

to provide optical gas imaging 

provisions (including the required 

instrument specifications, monitoring 

frequency, and repair threshold) as an 

alternative monitoring option where 

instrument monitoring using EPA 

Method 21 of 40 CFR part 60, Appendix 

A–7, is required in Refinery MACT 1. 

Since Refinery MACT 1 was issued, 

there have been developments in LDAR 

work practices using remote sensing 

technology for detecting leaking 

equipment. In this method of detecting 

leaks, an operator scans equipment 

using a device or system specially 

designed to use one of several types of 

remote sensing techniques, including 

optical gas imaging of infrared 

wavelengths, differential absorption 

light detection and ranging (DIAL), and 

solar occultation flux. 

The most common remote sensing 

instrument is a passive system that 

creates an image based on the 

absorption of infrared wavelengths (also 

referred to as a ‘‘camera’’). A gas cloud 

containing certain hydrocarbons (i.e., 

leaks) will show up as black or white 

plumes (depending on the instrument 

settings and characteristics of the leak) 

on the optical gas imaging instrument 

screen. This type of instrument is the 

device on which our evaluation of 

optical gas imaging instruments is 

based, and the instrument to which we 

are referring when we use the term 

‘‘optical gas imaging instrument.’’ These 

optical gas imaging instruments can be 

used to identify specific pieces of 

equipment that are leaking. Other 

optical methods, such as DIAL and solar 

occultation flux, are used primarily to 

assess emissions downwind of a source. 

These methods cannot be used to 

identify specific leaking equipment; 

they would only measure the aggregate 

emissions from all equipment and any 

other source up-wind of the 

measurement location. While we did 

review these technologies as discussed 

further (see the discussion under 

fenceline monitoring, section IV.B.1.h of 

this preamble), we do not consider DIAL 

and solar occultation flux methods to be 

suitable alternatives to EPA Method 21 

for monitoring equipment leaks and are 

not considering them further in our 

technology review for equipment leaks. 


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We expect that all refinery streams 

‘‘in organic HAP service’’ will include at 

least one of the compounds visible with 

an optical gas imaging instrument, such 

as benzene, methane, propane or 

butane. Therefore, it is technically 

feasible to use an optical gas imaging 

instrument to detect leaks at petroleum 

refineries. The optical gas imaging 

device can monitor many more pieces of 

equipment than can be monitored using 

instrument monitoring over the same 

period of time, and we expect that 

specific requirements for using an 

optical gas imaging device to detect 

leaks without accompanying instrument 

monitoring could be an appropriate 

alternative to traditional leak detection 

methods (EPA Method 21, as specified 

in 40 CFR part 60, Appendix A–7). 

Owners and operators currently have 

the option to use the Alternative Work 

Practice To Detect Leaks From 

Equipment (AWP) at 40 CFR 63.11(c), 

(d) and (e). This AWP includes 

provisions for using optical gas imaging 

in combination with annual monitoring 

using EPA Method 21 of 40 CFR part 60, 

Appendix A–7. In this proposal, we are 

considering the use of optical gas 

imaging without an accompanying 

requirement to conduct annual 

monitoring using EPA Method 21, and 

developing a protocol for using optical 

gas imaging techniques. We anticipate 

proposing the protocol as Appendix K 

to 40 CFR part 60. Rather than 

specifying the exact instrument that 

must be used, this protocol would 

outline equipment specifications, 

calibration techniques, required 

performance criteria, procedures for 

conducting surveys and training 

requirements for optical gas imaging 

instrument operators. This protocol 

would also contain techniques to verify 

that the instrument selected can image 

the most prevalent chemical in the 

monitored process unit. Because field 

conditions greatly impact detection of 

the regulated material using optical gas 

imaging, the protocol would describe 

the impact these field conditions may 

have on readings, how to address them 

and instances when monitoring with 

this technique is inappropriate. Finally, 

the protocol would also address 

difficulties with identifying equipment 

and leaks in dense industrial areas. 

Pursuant to CAA section 112(d)(6), we 

are proposing to allow refineries to meet 

the LDAR requirements in Refinery 

MACT 1 by monitoring for leaks via 

optical gas imaging in place of EPA 

Method 21 (of 40 CFR part 60, 

Appendix A–7), using the monitoring 

requirements to be specified in 

Appendix K to 40 CFR part 60. When 

Appendix K is proposed, we will 

request comments on that appendix and 

how those requirements would apply 

for purposes of this proposed action. We 

will not take final action adopting use 

of Appendix K to 40 CFR part 60 for 

optical gas imaging for refineries subject 

to Refinery MACT 1 until such time as 

we have considered any comments on 

that protocol as it would apply to 

refineries. We do not yet know the exact 

requirements of Appendix K to 40 CFR 

part 60, and this cannot provide a 

reliable estimate of potential costs at 

this time. However, we have calculated 

an initial estimate of the potential costs 

and emission reduction impacts, 

assuming that Appendix K to 40 CFR 

part 60 is similar to the AWP without 

the annual monitoring using EPA 

Method 21 of 40 CFR part 60, Appendix 

A–7. For more information on these 

potential impacts, see the technical 

memorandum titled Impacts for 

Equipment Leaks at Petroleum 

Refineries, in Docket ID Number EPA– 

HQ–OAR–2010–0682. 

d. Gasoline Loading Racks 

Loading racks are the equipment used 

to fill gasoline cargo tanks, including 

loading arms, pumps, meters, shutoff 

valves, relief valves and other piping 

and valves. Emissions from loading 

racks may be released when gasoline 

loaded into cargo tanks displaces vapors 

inside these containers. Refinery MACT 

1 specifies that Group 1 gasoline loading 

racks at refineries must comply with the 

requirements of the National Emission 

Standards for Gasoline Distribution 

Facilities (Bulk Gasoline Terminals and 

Pipeline Breakout Stations) in 40 CFR 

part 63, subpart R. The standard 

specified in 40 CFR part 63, subpart R 

is an emission limit of 10 milligrams of 

total organic compounds per liter of 

gasoline loaded (mg/L). Additionally, 40 

CFR part 63, subpart R requires all tank 

trucks and railcars that are loaded with 

gasoline to undergo annual vapor 

tightness testing in accordance with 

EPA Method 27 of 40 CFR part 60, 

Appendix A–8. 

For our technology review of Group 1 

gasoline loading racks subject to 

Refinery MACT 1, we relied on two 

separate analyses. First, we previously 

conducted a technology review for 

gasoline distribution facilities (71 FR 

17353, April 6, 2006), in which no new 

control systems were identified. Second, 

more recently, we conducted a general 

analysis to identify any developments in 

practices, processes and control 

technologies for transfer operations at 

chemical manufacturing facilities and 

petroleum refineries. (See Survey of 

Control Technology for Transfer 

Operations and Analysis of Impacts for 

Transfer Operation Control Options, 

January 20, 2012, Docket Item Number 

EPA–HQ–OAR–2010–0871–0021.) We 

identified several developments as part 

of this analysis and evaluated the 

impacts of applying the developments 

to gasoline loading racks subject to 

Refinery MACT 1. We have not 

identified any developments beyond 

those in the second analysis. The 

identified developments include 

controlling loading racks above specific 

throughput thresholds by submerged 

loading and by venting displaced 

emissions from the transport vehicles 

through a closed vent system to an 

APCD that reduces organic regulated 

material emissions by at least 95 

percent. 

We evaluated the emissions projected 

using this control technique for a range 

of different gasoline vapor pressures (to 

consider the different seasonal 

formulations of gasoline). We 

determined that submerged loading in 

combination with 95-percent control of 

displaced vapors would allow emissions 

of 12 to 42 mg/L of gasoline loaded, 

depending on the vapor pressure of the 

gasoline (see Evaluation of the 

Stringency of Potential Standards for 

Gasoline Loading Racks at Petroleum 

Refineries in Docket ID Number EPA– 

HQ–OAR–2010–0682.) The current 

Refinery MACT 1 emission limit for 

gasoline loading is 10 mg/L of gasoline 

loaded. We did not identify any 

developments in practices, process and 

control technologies for gasoline loading 

racks that would reduce emissions 

beyond the levels already in Refinery 

MACT 1. Therefore, we are proposing 

that it is not necessary to revise Refinery 

MACT 1 requirements for gasoline 

loading racks pursuant to CAA section 

112(d)(6). 

e. Marine Vessel Loading Operations 

Marine vessel loading operations load 

and unload liquid commodities in bulk, 

such as crude oil, gasoline and other 

fuels, and naphtha. The cargo is 

pumped from the terminal’s large, 

above-ground storage tanks through a 

network of pipes and into a storage 

compartment (tank) on the vessel. The 

HAP emissions are the vapors that are 

displaced during the filling operation. 

Refinery MACT 1 specifies that marine 

tank vessel loading operations at 

refineries must comply with the 

requirements in 40 CFR part 63, subpart 

Y (National Emission Standards for 

Marine Tank Vessel Loading 

Operations, ‘‘Marine Vessel MACT’’). 

We previously completed a 

technology review of the Marine Vessel 

MACT (40 CFR part 63, subpart Y) and 

issued amendments to subpart Y in 


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2011 (76 FR 22595, Apr. 21, 2011). The 

analysis conducted for the marine vessel 

loading source category specifically 

considered loading of petroleum 

products such as conventional and 

reformulated gasoline. As such, the 

conclusions drawn from this analysis 

are directly applicable to marine vessel 

loading operations at petroleum 

refineries. We have not identified any 

developments beyond those addressed 

in that analysis. 

The Marine Vessel MACT required 

add-on APCD for loading operations 

with HAP emissions equal to or greater 

than 10 tpy of a single pollutant or 25 

tpy of cumulative pollutants (referred to 

as ‘‘10/25 tpy’’). In our technology 

review of the Marine Vessel MACT 

standards, we considered the use of 

add-on APCD for marine vessel loading 

operations with HAP emissions less 

than 10/25 tpy. We also evaluated the 

costs for lean oil absorption systems as 

add-on APCD under the Marine Vessel 

MACT technology review. Depending 

on the throughput of the vessel, costs 

ranged from $77,000 per ton HAP 

removed for barges to $510,000 per ton 

HAP removed for ships ($3,900 per ton 

VOC removed to $25,000 per ton VOC 

removed) (see Cost Effectiveness and 

Impacts of Lean Oil Absorption for 

Control of Hazardous Air Pollutants 

from Gasoline Loading—Promulgation 

in Docket Item Number EPA–HQ–OAR– 

2010–0600–0401). We consider 

requiring add-on APCD for these smaller 

marine vessel loading operations not to 

be cost effective. 

As part of the technology review of 40 

CFR part 63, subpart Y, we also 

considered requiring marine vessel 

loading operations with emissions less 

than 10/25 tpy and offshore operations 

to use submerged loading (also referred 

to as submerged filling). We did include 

this requirement in the Marine Vessel 

MACT. However, when we amended the 

Marine Vessel MACT, we specifically 

excluded marine vessel loading 

operations at petroleum refineries from 

these provisions, deferring the decisions 

to include this requirement until we 

performed the technology review for 

Refinery MACT 1. The submerged 

filling requirement in 40 CFR part 63, 

subpart Y cites the cargo filling line 

requirements developed by the Coast 

Guard in 46 CFR 153.282. We project 

that applying the submerged filling 

requirements to marine vessel loading 

operations at petroleum refineries will 

have no costs or actual emission 

reductions because marine vessels 

carrying bulk liquids, liquefied gases or 

compressed gas hazardous materials are 

already required by 46 CFR 153.282 to 

have compliant ‘‘submerged fill’’ cargo 

lines that also meet the requirements of 

the Marine Vessel MACT. While we do 

not anticipate that this requirement will 

affect actual emissions, it will lower the 

allowable emissions for these sources 

under Refinery MACT 1. Therefore, we 

are proposing, pursuant to CAA section 

112(d)(6), to amend 40 CFR part 63, 

subpart Y to delete the exclusion for 

marine vessel loading operations at 

petroleum refineries, which would 

require small marine vessel loading 

operations (i.e., operations with HAP 

emissions less than 10/25 tpy) and 

offshore marine vessel loading 

operations to use submerged filling 

based on the cargo filling line 

requirements in 46 CFR 153.282. 

f. Cooling Towers/Heat Exchange 

Systems 

Heat exchange systems include 

equipment necessary to cool heated 

non-contact cooling water prior to 

returning the cooling water to a heat 

exchanger or discharging the water to 

another process unit, waste management 

unit or to a receiving water body. Heat 

exchange systems are designed as 

closed-loop recirculation systems with 

cooling towers or once-through systems 

that do not recirculate the cooling water 

through a cooling tower. Heat 

exchangers in heat exchange systems are 

constructed with tubes designed to 

prevent contact between hot process 

fluids and cooling water. Heat 

exchangers occasionally develop leaks 

that allow process fluids to enter the 

cooling water. The volatile HAP and 

other volatile compounds in these 

process fluids are then emitted to the 

atmosphere due to stripping in a cooling 

tower or volatilization from a cooling 

water pond or receiving water body. 

We established MACT standards for 

heat exchange systems at refineries in 

2009 (see 74 FR 55686, October 28, 

2009, as amended at 75 FR 37731, June 

30, 2010). The EPA received a petition 

for reconsideration from the American 

Petroleum Institute (API) and granted 

reconsideration on certain issues. On 

June 20, 2013, we issued a final rule 

addressing the petition, clarifying rule 

provisions, and revising the monitoring 

provisions to provide additional 

flexibility (78 FR 37133). We are not 

aware of any developments in 

processes, practices or control 

technologies beyond those we recently 

considered in our analysis of emission 

reduction techniques for heat exchange 

systems, which can be found in the 

docket (Docket Item Number EPA–HQ– 

OAR–2003–0146–0229). Therefore, we 

are proposing that it is not necessary to 

revise Refinery MACT 1 requirements 

for heat exchange systems pursuant to 

CAA section 112(d)(6). 

g. Wastewater Treatment 

Wastewater collection includes 

components such as drains, manholes, 

trenches, junction boxes, sumps, lift 

stations and sewer lines. Wastewater 

treatment systems are divided into three 

categories: primary treatment 

operations, which include oil-water 

separators and equalization basins; 

secondary treatment systems, such as 

biological treatment units or steam 

strippers; and tertiary treatment 

systems, which further treat or filter 

wastewater prior to discharge to a 

receiving body of water or reuse in a 

process. 

Refinery MACT 1 requires wastewater 

streams at a new or existing refinery to 

comply with 40 CFR 61.340 through 

61.355 of the NESHAP for Benzene 

Waste Operations (BWON) in 40 CFR 

part 61, subpart FF. The BWON requires 

control of wastewater collection and 

treatment units for facilities with a total 

annual benzene quantity of greater than 

or equal to 10 megagrams per year (Mg/ 

yr). Individual waste streams at 

refineries with a total annual benzene 

quantity greater than or equal to 10 Mg/ 

yr are not required to adopt controls if 

the flow-weighted annual average 

benzene concentration is less than 10 

parts per million by weight (ppmw) or 

the flow rate is less than 0.02 liters per 

minute at the point of generation. The 

BWON requires affected waste streams 

to comply with one of several options 

for controlling benzene emissions from 

waste management units and for treating 

the wastes containing benzene (55 FR 

8346, March 7, 1990; 58 FR 3095, 

January 7, 1993). 

Although the BWON specifically 

regulates benzene only, benzene is 

considered a surrogate for organic HAP 

from wastewater treatment systems at 

petroleum refineries. Benzene is present 

in nearly all refinery process streams. It 

is an excellent surrogate for wastewater 

pollutants because its unique chemical 

properties cause it to partition into the 

wastewater more readily than most 

other organic chemicals present at 

petroleum refineries. We stated our 

rationale regarding the use of benzene as 

a surrogate for refinery HAP emissions 

from wastewater in the original 

preamble to Refinery MACT 1 (59 FR 

36133, July 15, 1994). 

We performed a technology review for 

wastewater treatment systems to 

identify different control technologies 

for reducing emissions from wastewater 

treatment systems. We also reviewed the 

current standards for wastewater 

treatment systems in different rules 


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including the HON, the proposed NSPS 

for wastewater systems at petroleum 

refineries, and the BWON (See 

Technology Review for Industrial 

Wastewater Collection and Treatment 

Operations at Petroleum Refineries, in 

Docket ID Number EPA–HQ–OAR– 

2010–0682.) We identified several 

developments in processes, practices 

and control technologies for wastewater 

treatment, and evaluated the cost and 

cost effectiveness of each of those 

developments: (1) requiring wastewater 

drain and tank controls at refineries 

with a total annual benzene (TAB) 

quantity of less than 10 Mg/yr; (2) 

requiring specific performance 

parameters for an enhanced biological 

unit (EBU) beyond those required in the 

BWON; and (3) requiring wastewater 

streams with a VOC content of 750 

ppmv or higher to be treated by steamstripping prior to any other treatment 

process for facilities with high organic 

loading rates (i.e., facilities with total 

annualized benzene quantity of 10 Mg/ 

yr or more). These options are, for the 

most part, independent of each other, so 

the costs and cost effectiveness of each 

option are considered separately. 

Option 1 was evaluated because 

refineries with a total annual benzene 

quantity of less than 10 Mg/yr are not 

required to install additional controls on 

their wastewater treatment system. 

Thus, these refineries are limiting the 

amount of benzene produced in 

wastewater streams to less than 10 Mg/ 

yr, which effectively limits their 

benzene emissions from wastewater to 

less than 10 Mg/yr. 

Option 2 is intended to improve the 

performance of wastewater treatment 

systems that use an EBU, and thereby 

achieve additional emission reductions. 

The BWON, as it applies under Refinery 

MACT 1, has limited operational 

requirements for an EBU. Available data 

suggest that these systems are generally 

effective for degrading benzene and 

other organic HAP; however, without 

specific performance or operational 

requirements, the effectiveness of the 

EBU to reduce emissions can be highly 

variable. Under option 2, more stringent 

operating requirements are considered 

for the EBU at refineries. 

Option 3 considers segregated 

treatment of wastewater streams with a 

volatile organic content of greater than 

750 ppmw, or high-strength wastewater 

streams, directly in a steam stripper (i.e., 

not allowing these streams to be mixed 

and treated in the EBU). Preliminary 

investigations revealed direct treatment 

of wastewater by steam-stripping is only 

cost effective for high-strength 

wastewater streams of sufficient 

quantities. For more detail regarding the 

impact analysis for these control 

options, see Technology Review for 

Industrial Wastewater Collection and 

Treatment Operations at Petroleum 

Refineries, in Docket ID Number EPA– 

HQ–OAR–2010–0682. 

Table 8 provides the nationwide 

impacts for the control options. Based 

on the costs and emission reductions for 

each of the options, we consider none 

of the options identified to be cost 

effective for reducing emissions from 

petroleum refinery wastewater 

treatment systems. We are proposing 

that it is not necessary to revise Refinery 

MACT 1 to require additional controls 

for wastewater treatment systems 

pursuant to CAA section 112(d)(6). 

TABLE 8—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL OPTIONS CONSIDERED FOR

WASTEWATER TREATMENT SYSTEMS AT PETROLEUM REFINERIES

Control option Capital cost 

(million $) 

Annualized costs 

(million $/yr) 

Emissions reduction, VOC 

(tpy) 

Emissions 

reduction, HAP 

(tpy) 

Cost 

effectiveness 

($/ton VOC) 

Cost 

effectiveness 

($/ton HAP) 

1 ....................................... 19.7 4.2 592 158 7,100 26,600 

2 ....................................... 223 28.6 2,060 549 13,900 52,100 

3 ....................................... 142 50.7 3,480 929 14,500 54,500 

h. Fugitive Emissions 

The EPA recognizes that, in many 

cases, it is impractical to directly 

measure emissions from fugitive 

emission sources at refineries. Direct 

measurement of fugitive emissions from 

sources such as wastewater collection 

and treatment operations, equipment 

leaks and storage vessels can be costly 

and difficult, especially if required to be 

deployed on all sources of fugitives 

within a refinery and certainly on a 

national scale. This is a major reason 

why fugitive emissions associated with 

refinery processes are generally 

estimated using factors and correlations 

rather than by direct measurement. For 

example, equipment leak emissions are 

estimated using factors and correlations 

between leak rates and concentrations 

from EPA Method 21 instrument 

monitoring. Fugitive emissions from 

wastewater collection and treatment are 

estimated based on process data, 

material balances and empirical 

correlations. Relying on these kinds of 

approaches introduces uncertainty into 

the emissions inventory for fugitive 

emission sources. 

For each of the individual fugitive 

emission points, we evaluated 

developments in processes, practices 

and control technologies for measuring 

and controlling fugitive emissions from 

these sources. For storage vessels, as 

discussed in section IV.B.1.b of this 

preamble, we are proposing to lower the 

size and vapor pressure threshold and to 

require additional fittings on tanks, 

similar to requirements for tanks in the 

chemical industry because we project a 

cost savings due to recovered product. 

However, we considered but are not 

proposing to require EPA Method 21 of 

40 CFR part 60, Appendix A–7 or 

optical gas imaging monitoring to 

identify fugitive emissions from each 

individual storage vessel. For 

equipment leaks, as discussed in section 

IV.B.1.c of this preamble, we considered 

lowering the leak definition for 

equipment at petroleum refineries from 

the current Refinery MACT 1 level of 

10,000 ppm for pumps and valves down 

to the 500 ppm definition that is used 

in all the other MACT standards 

applying to the chemical industry, as 

well as adding a requirement for 

connectors to be included in the LDAR 

program because we consider these 

more stringent LDAR requirements to be 

technically feasible for the petroleum 

refining industry. Nevertheless, we 

rejected these options under the 

technology review as not being cost 

effective, based on costs projected by 

using the industry-reported emissions 

inventories. We are, however, proposing 

to adopt the use of optical gas imaging 

devices following 40 CFR part 60, 

Appendix K as an alternative to using 

EPA Method 21, which will be an 

alternative available to petroleum 

refiners that could offer cost savings, 

once the monitoring protocol set forth in 

Appendix K is promulgated. For 

wastewater treatment systems, as 

discussed in section IV.B.1.g of this 


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36920 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

29McKay, J., M. Molyneux, G. Pizzella, V. 

Radojcic. Environmental Levels of Benzene at the 

preamble, we considered both lowering 

the threshold for refinery wastewater 

streams requiring control, as well as 

requiring refineries to comply with 

enhanced monitoring and operating 

limits for EBU, such as the requirements 

contained in most of the chemical sector 

MACT standards, because we consider 

these requirements to be technically 

feasible for the refining industry. 

However, like equipment leaks, we are 

rejecting further controls for wastewater 

because using the industry-reported 

emissions inventory, we determined 

that further wastewater requirements are 

not cost effective. 

Although we are not proposing to 

require a number of additional control 

options for fugitive emission sources 

because we determined them not cost 

effective, we remain concerned 

regarding the potential for high 

emissions from these fugitive sources 

due to the difficulties in monitoring 

actual emission levels. For example, the 

regulations require infrequent 

monitoring of storage tank floating roof 

seals (visual inspections are required 

annually and direct inspections of 

primary seals are required only when 

the vessel is emptied and degassed, or 

no less frequently than once every 5 

years for internal floating roofs or 10 

years for external floating roofs with 

secondary seals). Given these inspection 

frequencies, tears or failures in floating 

roof seals may exist for years prior to 

being noticed, resulting in much higher 

emissions than expected or estimated 

for these sources in the emissions 

inventory. Similarly, water seals, which 

are commonly used to control emissions 

from wastewater collection drain 

systems, may be difficult to monitor 

(e.g., some are underground so visible 

emissions tests cannot be performed) 

and are subject only to infrequent 

inspections. During hot, dry months, 

these water seals may dry out, leaving 

an open pathway of vapors to escape 

from the collection system to the 

atmosphere. Significant emission 

releases may occur from these ‘‘dry’’ 

drains, which could persist for long 

periods of time prior to the next 

required inspection. 

Because the requirements and 

decisions that we are proposing in this 

action are based upon the emissions 

inventory reported by facilities in 

response to the 2011 Refinery ICR, and 

considering the uncertainty with 

estimating emissions from fugitive 

emission sources, we believe that it is 

appropriate under CAA section 

112(d)(6) to require refiners to monitor, 

and if necessary, take corrective action 

to minimize fugitive emissions, to 

ensure that facilities appropriately 

manage emissions of HAP from fugitive 

sources. In other words, in this action, 

we are proposing a HAP concentration 

to be monitored in the ambient air 

around a refinery, that if exceeded, 

would trigger corrective action to 

minimize fugitive emissions. The 

fenceline concentration action level 

would be set at a level such that no 

facility in the category would need to 

undertake additional corrective 

measures if the facility’s estimate of 

emissions from fugitive emissions is 

consistent with the level of fugitive 

emissions actually emitted. On the other 

hand, if a facility’s estimate of fugitive 

HAP emissions was not accurate, the 

owner or operator may need to take 

some corrective action to minimize 

fugitive emissions. This approach 

would provide the owner or operator 

with the flexibility to determine how 

best to reduce HAP emissions to ensure 

levels remain below the fenceline 

concentration action level. The details 

of this proposed approach are set forth 

in more detail in the following 

discussions in this preamble section. 

In light of the impracticality of 

directly monitoring many of these 

fugitive emission sources on a regular 

basis, which would help ensure these 

fugitive sources are properly 

functioning to the extent practical, we 

evaluated a fenceline monitoring 

program under CAA section 112(d)(6). 

In this section, we evaluate the 

developments in processes, practices 

and control technologies for measuring 

and controlling fugitive emissions from 

the petroleum refinery as a whole 

through fenceline monitoring 

techniques. Fenceline monitoring will 

identify a significant increase in 

emissions in a timely manner (e.g., a 

large equipment leak or a significant 

tear in a storage vessel seal), which 

would allow corrective action measures 

to occur more rapidly than it would if 

a source relied solely on the traditional 

infrequent monitoring and inspection 

methods. Small increases in emissions 

are not likely to impact the fenceline 

concentration, so a fenceline monitoring 

approach will generally target larger 

emission sources that have the most 

impact on the ambient pollutant 

concentration near the refinery. 

Historically, improved information 

through measurement data has often led 

to emission reductions. However, 

without a specific emission limitation, 

there may be no incentive for owners or 

operators to act on the additional 

information. Therefore, as part of the 

fenceline monitoring approach, we seek 

to develop a not-to-be exceeded annual 

fenceline concentration, above which 

refinery owners or operators would be 

required to implement corrective action 

to reduce their fenceline concentration. 

We sought to develop a maximum 

fenceline concentration action level that 

is consistent with the emissions 

projected from fugitive sources 

compliant with the provisions of the 

refinery MACT standards as modified 

by the additional controls proposed in 

this action (e.g., additional fittings on 

storage vessels). 

This section details our technology 

review to identify developments in 

processes, practices and technologies for 

measuring air toxics at the fenceline of 

a facility. Upon selection of a specific 

fenceline monitoring method, we 

provide our rationale for the specific 

details regarding the fenceline 

monitoring approach, including 

requirements for siting the monitors, 

procedures for adjusting for background 

interferences, selection of the fenceline 

action level, and requirements for 

corrective action. 

Developments in monitoring 

technology and practices. The EPA 

reviewed the available literature and 

identified several different methods for 

measuring fugitive emissions around a 

petroleum refinery. These methods 

include: (1) Passive diffusive tube 

monitoring networks; (2) active 

monitoring station networks; (3) 

ultraviolet differential optical 

absorption spectroscopy (UV–DOAS) 

fenceline monitoring; (4) open-path 

Fourier transform infrared spectroscopy 

(FTIR); (5) DIAL monitoring; and (6) 

solar occultation flux monitoring. We 

considered these monitoring methods as 

developments in practices under CAA 

section 112(d)(6) for purposes of all 

fugitive emission sources at petroleum 

refineries. Each of these methods has its 

own strengths and weaknesses, which 

are discussed in the following 

paragraphs. 

Fenceline passive diffusive tube 

monitoring networks employ a series of 

diffusive tube samplers at set intervals 

along the fenceline to measure a timeintegrated ambient air concentration at 

each sampling location. A diffusive tube 

sampler consists of a small tube filled 

with an adsorbent, selected based on the 

pollutant(s) of interest, and capped with 

a specially designed cover with small 

holes that allow ambient air to diffuse 

into the tube at a small, fixed rate. 

Diffusive tube samplers have been 

demonstrated to be a cost-effective, 

accurate technique for measuring 

ambient concentrations of pollutants 

resulting from fugitive emissions in a 

number of studies.29 30 In addition, 


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Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36921 

Boundaries of Three European Refineries, prepared 

by the CONCAWE Air Quality Management Group’s 

Special Task Force on Benzene Monitoring at 

Refinery Fenceline (AQ/STF–45), Brussels, June 

1999. 

30Thoma, E.D., M.C. Miller, K.C. Chung, N.L. 

Parsons, B.C. Shine. 2011. Facility Fenceline 

Monitoring using Passive Sampling, J. Air & Waste 

Manage Assoc. 61: 834–842. 

31Thoma, et al., 2011. 

32 ‘‘Optical Remote Sensing for Emission 

Characterization from Non-Point Sources.’’ Final 

ORS Protocol, June 14, 2006. Available at: http:// 

www.epa.gov/ttn/emc/prelim/otm10.pdf. 

diffusive samplers are used in the 

European Union to monitor and 

maintain air quality, as described in 

European Union directives 2008/50/EC 

and Measurement Standard EN 14662– 

4:2005 for benzene. The International 

Organization for Standardization 

developed a standard method for 

diffusive sampling (ISO/FDIS 16017–2). 

In 2009, the EPA conducted a yearlong fenceline monitoring pilot project 

at Flint Hills West Refinery in Corpus 

Christi, Texas, to evaluate the viability 

and performance of passive diffusive 

sampling technology. Overall, we found 

the technology to be capable of 

providing cost effective, high spatialdensity long-term monitoring. This 

approach was found to be relatively 

robust and implementable by modestly 

trained personnel and provided useful 

information on overall concentration 

levels and source identification using 

simple upwind and downwind 

comparisons.31 Combined with on-site 

meteorological measurements, 2-week 

time-integrated passive monitoring has 

been shown to provide useful facility 

emission diagnostics. 

There are several drawbacks of timeintegrated sampling, including the lack 

of immediate feedback on the acquired 

data and the loss of short-term temporal 

information. Additionally, timeintegrated monitoring usually requires 

the collected sample to be transported to 

another location for analysis, leading to 

possible sample integrity problems (e.g., 

sample deterioration, loss of analytes, 

and contamination from the 

surrounding environment). However, 

time-integrated monitoring systems are 

generally lower-cost and require less 

labor than time-resolved monitoring 

systems. Furthermore, while passive 

diffusive tube monitoring employs timeintegrated sampling, these timeintegrated samples still represent much 

shorter time intervals (2 weeks) than 

many of the current source-specific 

monitoring and inspection requirements 

(annually or less frequently). 

Consequently, passive diffusive tube 

monitoring still allows earlier detection 

of significant fugitive emissions than 

conventional source-specific 

monitoring. 

Active monitoring station networks 

are similar to passive diffusive tube 

monitoring networks in that a series of 

discrete sampling sites are established; 

however, each sampling location uses a 

pump to actively draw ambient air at a 

known rate through an adsorption tube. 

Because of the higher sampling rate, 

adsorption tubes can be analyzed on a 

daily basis, providing additional time 

resolution compared to diffusive tube 

sampling systems. Alternatively, the 

active sampling system can directly feed 

an analyzer for even more time 

resolution. However, this direct analysis 

of ambient air generally has higher 

detection limits than when the organic 

vapors are collected and concentrated 

on an adsorption matrix prior to 

analysis. Active monitoring stations 

have been used for a variety of 

pollutants in a variety of settings and 

the methods are well-established. 

However, compared to the passive 

diffusive tube monitoring stations, the 

sampling system is more expensive, 

more labor-intensive, and generally 

requires highly-trained staff to operate. 

UV–DOAS fenceline monitoring is an 

‘‘open-path’’ technology. An 

electromagnetic energy source is used to 

emit a beam of electromagnetic energy 

(ultraviolet radiation) into the air 

towards a detection system some 

distance from the energy source 

(typically 100 to 500 meters). The 

electromagnetic energy beam interacts 

with components in the air in the open 

path between the energy source and the 

detector. The detector measures the 

disruptions in the energy beam to 

determine an average pollutant 

concentration across the open path 

length. Because the UV–DOAS system 

can monitor integrated concentrations 

over a fairly long path-length, fewer 

monitoring ‘‘stations’’ (energy source/

detector systems) would be needed to 

measure the ambient concentration 

around an entire refinery. However, 

each UV–DOAS monitoring system is 

more expensive than an active or 

passive monitoring station and generally 

requires significant instrumentation 

shelter to protect the energy source and 

analyzer when used for long-term 

(ongoing) measurements. Advantages of 

UV–DOAS systems include providing 

real-time measurement data with 

detection limits in the low parts per 

billion range for certain compounds. 

Fog or other visibility issues (e.g., dust 

storm, high pollen, wildfire smoke) will 

interfere with the measurements. UV– 

DOAS systems have been used for 

fenceline monitoring at several U.S. 

petroleum refineries and petrochemical 

plants. UV–DOAS monitoring systems 

are specifically included as one of the 

measurement techniques suitable under 

EPA’s Other Test Method 10 (OTM– 

10).32

Open-path FTIR is similar to UV– 

DOAS monitoring except that an 

infrared light source and detector 

system are used. Like the UV–DOAS 

monitoring approach, the open-path 

FTIR monitoring system will measure 

the average pollutant concentration 

across the open path length between the 

infrared source and detector. Path 

lengths and equipment costs for an 

open-path FTIR system are similar to 

those for a UV–DOAS system, and the 

open-path FTIR system provides realtime measurement data. The open-path 

FTIR system has spectral interferences 

with water vapor, CO and CO2, which 

can impact the lower detection limit for 

organic vapors. Open-path FTIR 

fenceline monitoring has also been used 

to measure ambient air concentrations 

around several petroleum refineries and 

petrochemical plants. Open-path FTIR 

is specifically included as a 

measurement technique in EPA’s OTM– 

10. Although open-path FTIR can be 

used to measure a larger number of 

compounds than UV–DOAS, the 

detection limit of open-path FTIR for 

benzene is higher than for UV–DOAS, as 

noted in OTM–10. In other words, openpath FTIR is not as sensitive to benzene 

levels as is UV–DOAS. As benzene is an 

important pollutant from fugitive 

sources at petroleum refineries and can 

often be used as a surrogate for other 

organic HAP emissions, this high 

detection limit for benzene is a 

significant disadvantage. Thus, for the 

purposes of measuring organic HAP 

from fugitive sources at the fenceline of 

a petroleum refinery, a UV–DOAS 

monitoring system is expected to be 

more sensitive than an open-path FTIR 

system. As the cost and operation of 

open-path FTIR and UV–DOAS systems 

are very comparable, the benzene 

detection limit issue is a significant 

differentiator between these two 

methods when considering fenceline 

monitoring to measure fugitives around 

a petroleum refinery. 

DIAL monitoring systems employ a 

pulsed laser beam across the 

measurement path. Small portions of 

the light are backscattered due to 

particles and aerosols in the 

measurement path. This backscattered 

light is collected through a telescope 

system adjacent to the laser and 

measured via a sensitive light detector. 

The timing of the received light 

provides a measure of the distance of 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36922 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

the emission plume. Two different 

wavelengths of light are pulsed in quick 

succession: one wavelength that is 

absorbed strongly by the pollutant of 

interest and one that is not absorbed. 

The difference in the returned signal 

strength between these two light pulses 

provides a measure of the concentration 

of the pollutant. Thus, a unique 

advantage of the DIAL monitoring 

system is that it can provide spatially 

resolved pollutant concentrations in two 

dimensions. Measurements can be made 

in a relatively short period of time, so 

the method also provides good time 

resolution. 

The DIAL monitoring system has been 

used in a variety of studies to measure 

emissions from petroleum refinery and 

petrochemical sources. It is typically 

used for specific, shorter-term studies 

(one to several weeks in duration). The 

equipment is expensive, has limited 

availability in the U.S., and requires 

highly trained professionals to operate. 

Although DIAL monitoring is included 

as an appropriate method for EPA’s 

OTM–10, there are no known long-term 

applications of this technology for the 

purpose of fenceline monitoring. Given 

the limited availability of the equipment 

and qualified personnel to operate the 

equipment, we do not consider DIAL 

monitoring to be technically feasible for 

the purposes of ongoing, long-term 

fenceline monitoring. 

The last fenceline monitoring method 

evaluated was solar occultation flux. 

Solar occultation flux uses the sun as 

the light source and uses an FTIR or UV 

detector to measure the average 

pollutant concentration across the 

measurement path. In this case, the 

measurement path is vertical. In order to 

measure the concentrations around an 

industrial source, the measurement 

device is installed in a specially 

equipped van, which is slowly driven 

along the perimeter of the facility. 

Measurement signal strength and a 

global positioning system (GPS) enables 

determination of pollutant 

concentrations along the perimeter of 

the site. This method provides more 

spatial resolution of the emissions than 

the UV–DOAS or open-path FTIR 

methods and is less expensive than a 

DIAL system. It has the advantage that 

only one monitoring system is needed 

per facility, assuming a mobile device is 

used. Disadvantages of this method 

include the need of full-time personnel 

to drive the equipment around the 

perimeter of the facility (or the need to 

buy a detector for each measurement 

location around the perimeter of the 

facility, if set locations are used), 

potential accessibility issues for some 

fenceline locations (e.g., no road near 

the fenceline), and the measurement 

method cannot be used at night or 

during cloudy periods. It would be 

possible to purchase numerous 

detection devices and establish fixed 

monitoring stations similar to the 

passive or active monitoring approaches 

described earlier, but this would be very 

expensive. Furthermore, any application 

of solar occultation flux is dependent on 

the sun, so this approach would mean 

significant periods each calendar day 

when the monitoring system would not 

be able to provide data. Based on our 

evaluation of this technology, we 

determined that this method is not a 

reasonable approach for monitoring 

fenceline concentrations of pollutants 

around a petroleum refinery on a longterm, ongoing basis. We are soliciting 

comment on the application of 

alternative monitoring techniques 

previously discussed for purposes of 

fenceline monitoring at refineries. 

Costs associated with fenceline 

monitoring alternatives. Based on our 

review of available monitoring methods, 

we determined that the following 

monitoring methods were technically 

feasible and appropriate for monitoring 

organic HAP from fugitive emission 

sources at the fenceline of a petroleum 

refinery on a long-term basis: (1) Passive 

diffusive tube monitoring networks; (2) 

active monitoring station networks; (3) 

UV–DOAS fenceline monitoring; and (4) 

open-path FTIR. While DIAL monitoring 

and solar occultation flux monitoring 

can be used for short-term studies, we 

determined that these methods were not 

appropriate for continuous monitoring 

at petroleum refineries. This section 

evaluates the costs of these technically 

feasible monitoring methods. As noted 

previously, the cost identified for the 

open-path monitoring methods (UV– 

DOAS and FTIR) are very similar. 

Therefore, we developed costs for only 

the UV–DOAS system because this 

method provides lower detection limits 

for pollutants of interest (specifically, 

benzene). 

Costs for the fenceline monitoring 

methods are dependent on the sampling 

frequency (for passive and active 

monitoring locations) and the number of 

monitoring locations needed based on 

the size and geometry of the facility. For 

the open-path methods, we estimated 

that four monitoring systems (along the 

east, west, north and south fencelines) 

would be needed, regardless of the size 

of the refinery. Some fencelines at larger 

refineries may be too long for a single 

open path length, but we did not vary 

the number of detectors needed for the 

open-path systems based on refinery 

size in order to provide a reasonable 

lower-cost estimate for the open-path 

monitoring option. For small petroleum 

refineries (less than 750 acres), we 

estimated 12 passive or active 

monitoring stations would be sufficient. 

For medium-sized refineries (750 to 

1,500 acres), we estimated 18 

monitoring stations would be required; 

for large refineries (greater than 1,500 

acres), we estimated that 24 monitoring 

stations would be needed. For the 

passive diffusive tube monitoring we 

assumed a 2-week sampling interval; for 

active monitoring stations, we assumed 

a daily sampling frequency. 

We estimated the first year 

installation and equipment costs for the 

passive tube monitoring system could 

cost up to $100,000 for larger refineries 

(i.e., 24 sampling locations). Annualized 

costs for ongoing monitoring are 

projected to be approximately $40,000 

per year, assuming the ongoing sample 

analyses are performed in-house. 

Capital costs for active sampling 

systems were estimated to be 

approximately twice that of the passive 

system for the larger refinery. Ongoing 

costs were more than 10 times higher, 

however, due to the daily sampling 

frequency. Equipment costs for a single 

UV–DOAS system were estimated to be 

about $100,000, so a complete fenceline 

monitoring system (four systems plus 

shelters) was estimated to cost more 

than $500,000. A refinery using this 

technology for two fenceline locations 

estimated the annualized cost of 

calibrating and maintaining these 

systems approaches $1-million per year. 

(See Fenceline Monitoring Technical 

Support Document, in Docket ID 

Number EPA–HQ–OAR–2010–0682). 

Table 9 provides the nationwide costs 

of the monitoring approaches as applied 

to all U.S. petroleum refineries. 


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TABLE 9—NATIONWIDE COST IMPACTS OF FENCELINE MONITORING OPTIONS AT PETROLEUM REFINERIES

Monitoring option Monitoring option description Capital cost 

(million $) 

Annual operating 

costs 

(million $/yr) 

Total annualized 

costs 

(million $/yr) 

1 ............................... Passive diffusive tube monitoring network ................................ 12.2 3.83 5.58 

2 ............................... Active sampling monitoring network .......................................... 20.6 30.2 33.1 

3 ............................... Open-path monitoring (UV–DOAS, FTIR) ................................. 71.0 35.5 45.6 

The primary goal of a fenceline 

monitoring network is to ensure that 

owners and operators properly monitor 

and manage fugitive HAP emissions. As 

explained further in this preamble 

section, we are proposing a 

concentration action level that was 

derived by modeling fenceline benzene 

concentrations (as a surrogate for HAP) 

at each facility after full compliance 

with the refinery MACT standards, as 

amended by this proposed action. As 

such, we are proposing a fenceline 

benzene concentration that all facilities 

in the category can meet, according to 

the emissions inventories reported in 

response to the 2011 Refinery ICR. 

Therefore, we do not project a HAP 

emission reduction that the fenceline 

monitoring network will achieve. 

However, if an owner or operator has 

underestimated the fugitive emissions 

from one or more sources, or if a leak 

develops or a tank seal or fitting fails, 

a fenceline monitoring system would 

provide for identification of such leaks 

much earlier than current monitoring 

requirements and, where emissions are 

beyond those projected from 

implementation of the MACT standards, 

would help ensure that such emissions 

are quickly addressed. We note that any 

costs for a fugitive monitoring system 

would be offset, to some extent, by 

product recovery since addressing these 

leaks more quickly than would 

otherwise occur based on the more 

infrequent monitoring required would 

reduce product losses. 

Based on the low cost and relative 

benefits of passive monitoring, which 

include the ability to generate timeintegrated concentration measurements 

at low detection limits, coupled with 

relative ease of deployment and 

analysis, the EPA is proposing to require 

refineries to deploy passive timeintegrated samplers at the fenceline. 

These samplers would monitor the level 

of fugitive emissions that reach the 

fenceline from all fugitive emission 

sources at the facility. The EPA is 

proposing to require fugitive emission 

reductions if fenceline concentrations 

exceed a specified concentration action 

level, as described further below. These 

proposed fenceline monitoring 

requirements complement the EPA’s 

proposal to allow the use of the optical 

gas imaging camera as described in 

Appendix K of 40 CFR part 60 as an 

alternative work practice for measuring 

emissions from equipment leaks, in lieu 

of monitoring with EPA Method 21 of 

40 CFR part 60, Appendix A–7 (see 

section IV.B.1.c of this preamble for 

further discussion). Both approaches 

utilize low-cost methods to help ensure 

that total fugitives from a facility are 

adequately controlled. 

Because there is no current EPA test 

method for passive diffusive tube 

monitoring, as part of this action we are 

proposing specific monitor citing and 

sample collection requirements as EPA 

Method 325A of 40 CFR part 63, 

Appendix A, and specific methods for 

analyzing the sorbent tube samples as 

EPA Method 325B of 40 CFR part 63, 

Appendix A. We are proposing to 

establish an ambient concentration of 

benzene at the fenceline that would 

trigger required corrective action. A 

brief summary of the proposed fenceline 

sampling requirements and our 

rationale for selecting the corrective 

action concentration levels are provided 

below. 

Siting, design and sampling 

requirements for fenceline monitors. 

The EPA is proposing that passive 

fenceline monitors collecting 2-week 

time-integrated samples be deployed to 

measure fenceline concentrations at 

refineries. We are proposing that 

refineries deploy passive samplers at 12 

to 24 points circling the refinery 

perimeter. A primary requirement for a 

fenceline monitoring system is that it 

provides adequate spatial coverage for 

determination of representative 

pollutant concentrations at the 

boundary of the facility or operation. In 

an ideal scenario, fenceline monitors 

would be placed so that any fugitive 

plume originating within the facility 

would have a high probability of 

intersecting one or more monitors, 

regardless of wind direction. This 

proposed monitoring program would 

require that monitors be placed at 15 to 

30 degree intervals along the perimeter 

of the refinery, depending on the size of 

the facility. For small refineries (less 

than 750 acres), monitors should be 

placed at 30 degree intervals, for a total 

of 12 locations; for facilities that are 

larger than 750 acres and less than 1,500 

acres, monitors should be placed at 20 

degree intervals, at 18 locations; and for 

facilities greater than 1,500 acres, 

monitors should be placed at 15 degree 

intervals, accounting for 24 locations. 

We have also established an alternative 

siting procedure where monitors can be 

placed every 2,000 feet along the 

fenceline of the refinery, which may be 

easier to implement, especially for 

irregularly-shaped facilities. In 

proposing these requirements for the 

number and location of required 

monitors, the EPA assumes that all 

portions of the facility are contiguous 

such that it is possible to define a single 

facility boundary or perimeter, although 

this perimeter may be irregular in shape. 

We request comment on how these 

monitoring requirements should be 

adapted for instances where one or more 

portions of the facility are not 

contiguous, and on the number and 

location of facilities for which special 

fenceline monitoring requirements to 

accommodate non-contiguous 

operations might apply. 

We are proposing that the highest 

concentration of benzene, as an annual 

rolling average measured at any 

individual monitor and adjusted for 

background (see below), would be 

compared against the concentration 

action level in order to determine if 

there are significant excess emissions of 

fugitive emissions that need to be 

addressed. Existing sources would be 

required to deploy samplers no later 

than 3 years after the effective date of 

the final rule; new sources would be 

required to deploy samplers by the 

effective date of the final rule or startup, 

whichever is later. Because the 

proposed concentration action level is 

composed of 1 year’s worth of data, we 

are proposing that refinery owners and 

operators would be required to 

demonstrate compliance with the 

concentration action level for the first 

time 1 year following the compliance 

date, and thereafter on a 1-year rolling 

annual average basis (i.e., considering 

results from the most recent 26 

consecutive 2-week sampling intervals 

and recalculating the average every 2 

weeks). 


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36924 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

Benzene as an appropriate target 

analyte. Passive diffusive tube monitors 

can be used to determine the ambient 

concentration of a large number of 

compounds. However, different sorbent 

materials are typically needed to collect 

compounds with significantly different 

properties. Rather than require multiple 

tubes per monitoring location and 

require a full analytical array of 

compounds to be determined, which 

would significantly increase the cost of 

the proposed fenceline monitoring 

program, we are proposing that the 

fenceline monitors be analyzed 

specifically for benzene. Refinery 

owners or operators may elect to do 

more detailed speciation of the 

emissions, which could help identify 

the process unit that may be 

contributing to a high fenceline 

concentration, but we are only 

establishing monitoring requirements 

and action level requirements for 

benzene. We consider benzene to be an 

excellent surrogate for organic HAP 

from fugitive sources for multiple 

reasons. First, benzene is ubiquitous at 

refineries, and is present in nearly all 

refinery process streams such that 

leaking components generally will leak 

benzene at some level (in addition to 

other compounds). Benzene is also 

present in crude oil and gasoline, so 

most storage tank emissions include 

benzene. As described previously in our 

discussion of wastewater treatment 

systems, benzene is also a very good 

surrogate for organic HAP emissions 

from wastewater and is already 

considered a surrogate for organic HAP 

emissions in the wastewater treatment 

system control requirements in Refinery 

MACT 1. Second, the primary releases 

of benzene occur at ground level as 

fugitive emissions from process 

equipment, storage vessels and 

wastewater collection and treatment 

systems, and the highest ambient 

benzene concentrations outside the 

facility will likely occur near the 

property boundary near ground level, so 

fugitive releases of benzene will be 

effectively detected at the ground-level 

monitoring sites. According to the 

emissions inventory we have relied on 

for this proposed action, 85 percent of 

benzene emissions from refineries result 

from ground-level fugitive emissions 

from equipment and wastewater 

collection and treatment (see the 

Component 2 database contained in 

Docket ID Number EPA–HQ–OAR– 

2010–0682). Finally, benzene is present 

in nearly all process streams. Therefore, 

the presence of benzene at the fenceline 

is also an indicator of other air toxics 

emitted from fugitive sources at 

refineries. 

For the reasons discussed above, we 

believe that benzene is the most 

appropriate pollutant to monitor. We 

believe that other compounds, such as 

PAH or naphthalene, would be less 

suitable indicators of total fugitive HAP 

for a couple of reasons. First, they are 

prevalent in stack emissions as well as 

fugitive emissions, so there is more 

potential for fenceline monitors to pick 

up contributions from non-fugitive 

sources. In contrast, almost all benzene 

comes from fugitive sources, so 

monitoring for benzene increases our 

confidence that the concentration 

detected at the fenceline is from 

fugitives. Second, as compared to 

benzene, these other compounds are 

expected to be present at lower 

concentrations and, therefore, would be 

more difficult to measure accurately 

using fenceline monitoring. We request 

comments on the suitability of selecting 

benzene or other HAP, including PAH 

or naphthalene, as the indicator to be 

monitored by fenceline samplers. We 

also request comment on whether it 

would be appropriate to require 

multiple HAP to be monitored at the 

fenceline considering the capital and 

annual cost for additional monitors, and 

if so, which pollutants should be 

monitored. 

Adjusting for background benzene 

concentrations. Under this proposed 

approach, absolute measurements along 

a facility fenceline cannot completely 

characterize which emissions are 

associated with the refinery and which 

are associated with other background 

sources. The EPA recognizes that 

sources outside the refinery boundaries 

may influence benzene levels monitored 

at the fenceline. Furthermore, 

background levels driven by local 

upwind sources are spatially variable. 

Both of these factors could result in 

inaccurate estimates of the actual 

contribution of fugitive emissions from 

the facility itself to the concentration 

measured at the fenceline. Many 

refineries and petrochemical industries 

are found side-by-side along waterways 

or transport corridors. With this spatial 

positioning, there is a possibility that 

the local upwind neighbors of a facility 

could cause different background levels 

on different sides of the facility. To 

account for background concentrations 

(i.e., to remove the influence of benzene 

emissions from sources outside the 

refinery on monitored fenceline values), 

we are proposing to adjust monitored 

fenceline values to account for 

background concentrations as described 

below. We solicit comments on 

alternative approaches for making these 

adjustments for background benzene. 

Fenceline-deployed passive samplers 

measure concentrations that originate 

from both the observed facility and from 

off-site sources. The relative 

contribution of the facility versus offsite source(s) to the measured 

concentration depends on the emission 

levels of the observed facility and offsite sources (including both near-field 

and remote sources), transporting wind 

direction and atmospheric dispersion. 

The ability to identify facility and offsite source contributions is reliant on 

the measurement scheme selected. The 

most basic (and lowest cost) approach 

involves different calculations using 2- 

week deployed samplers located only at 

the facility fenceline. Greater 

discrimination capability is found by 

adding passive samplers to specific 

areas of the facility, reducing the time 

duration of the passive samplers, and 

coupling measured meteorology 

information to the passive sampler 

analysis. Selective use of time-resolved 

monitoring or wind sector sampling 

approaches provides the highest source 

and background discrimination 

capability. The approach we are 

proposing seeks to remove off-site 

source contributions to the measured 

fenceline concentrations to the greatest 

extent possible using the most costeffective measurement solutions. 

The highest fenceline concentration 

(HFC) for each 2-week sampling period 

can be expressed as: 

HFC = Maximum × (MFC¥OSCi

) 

Where: 

HFC = highest fenceline concentration, 

corrected for background. 

MFCi = measured fenceline concentration for 

the sampling period at monitoring 

location i. 

OSCi = estimated off-site source contribution 

for the sampling period at monitoring 

location i. 

The off-site source contribution (OSC) 

consists of two primary components: (1) 

A slowly varying, spatially uniform 

background (UB) concentration and, in 

some cases, (2) potential near-field 

interfering sources. 

OSCi = UB + NFSi

Where: 

UB = uniform background concentration. 

NFSi = near-field interfering source 

concentration contribution at monitoring 

location i. 

In some deployment scenarios (such 

as spatially isolated facilities), the major 

off-site source component can be 

identified as background concentrations 

that are uniform across the facility 

fenceline and neighboring area. In this 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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scenario, a UB concentration level can 

be determined and subtracted from the 

measured fenceline concentrations for 

each sampling period. This can be 

accomplished through use of facilitymeasured or otherwise available, quality 

assured time-resolved (or wind sectorresolved) background monitoring data, 

or from placement of additional passive 

samplers at upwind locations away from 

the facility fenceline and other sources. 

In other scenarios, such as where 

other industrial sources or a highway 

are located nearby, background 

concentrations are likely not uniform. 

These outside sources would influence 

some, but not perhaps not all, fenceline 

monitors and, therefore, the true 

‘‘background’’ concentration would 

vary, depending where on the fenceline 

the measurement was taken. In this 

case, background is not uniform, and 

monitoring location-specific near-field 

interfering source (NFS) values would 

need to be determined. 

Due to the difficulties associated with 

determining location-specific NFS 

values, we are proposing to approximate 

OSC by using the lowest measured 

concentration (LMC) at the facility 

fenceline for that period. In this case, 

the HFC for the monitoring period, 

corrected for background, would be 

calculated as: 

HFC ≈ DC = HMC¥LMC 

Where: 

DC = concentration difference between the 

highest and lowest measured 

concentrations for the sampling period. 

HMC = highest measured fenceline 

concentration for the sampling period. 

LMC = lowest measured fenceline 

concentration for the sampling period. 

This alternative is directly applicable 

for all refinery locations and requires no 

additional, off-site, upwind monitors, 

the placement of which is impossible to 

prescribe a priori. Use of LMC provides 

a reasonable proxy for OSC in most 

cases, but can over- or underestimate 

OSC in some cases. In locations where 

there are few upwind source 

contributions and where wind direction 

is relatively consistent, upwind passive 

samples on the fenceline can provide a 

realistic approximation of the actual offsite background levels. As the 

meteorology becomes more complicated 

(e.g., mixed wind directions, higher 

percentage of calm winds), the LMC will 

reflect a progressively larger amount of 

emissions from the facility itself, so 

differential calculations may 

underestimate the true HFC for some 

monitoring periods (by inadvertently 

allowing some facility emissions to be 

subtracted as part of ‘‘background’’). On 

the other hand, if a near-field source 

impacts the highest measured 

concentration monitoring location 

significantly, but contributes little to the 

monitoring location with the LMC, the 

LMC differential calculation (i.e., DC) 

could lead to an artificially elevated 

assessment of the highest fenceline 

concentration, corrected for background. 

Based on our examination of previous 

fenceline monitoring results, we expect 

that the use of the LMC differential will 

provide an accurate method by which to 

determine HFC. Therefore, we are not 

proposing to limit the use of the LMC 

differential calculation in cases where 

there are no near-field sources and 

where mixed wind direction (or calm 

wind) is common. In these special cases, 

use of the UB concentration alone (no 

NFS term) may be more accurate than 

using LMC. We are seeking comment on 

how to identify conditions under which 

the LMC differential may underestimate 

the highest fenceline concentration, 

corrected for background, and the need 

to require facilities to determine and use 

UB rather than LMC in these cases. 

We also recognize that under different 

site-specific conditions, the NFS 

contribution may affect certain fenceline 

monitoring stations more than others, 

causing the LMC differential calculation 

to overestimate the facility’s 

contribution to the highest fenceline 

concentration. Therefore, we are also 

proposing to allow owners or operators 

of petroleum refineries to develop sitespecific monitoring plans to determine 

UB and NFSi. 

If standard 2-week passive fenceline 

data and site analysis indicate potential 

near-field off-site source interferences at 

a section of the refinery, the proposal 

allows the owner or operator to conduct 

additional sampling strategies to 

determine a local background (OSC 

term) for use in the HFC calculation. 

The owner or operator would be 

required to report the basis for this 

correction, including analyses used to 

identify the sources and contribution of 

benzene concentration to the passive 

sampler concentration, within 45 days 

of the date the owner or operator first 

measures an exceedance of the 

concentration action level. 

We envision that facilities would 

implement these additional strategies to 

refine fenceline concentration estimates 

only if appropriate given site-specific 

characteristics and only if HFC 

determined by the LMC approach is 

likely to exceed the concentration action 

level (see discussion below regarding 

this action level). Facilities with HFC 

below the concentration action level 

based on the simple LMC differential 

calculation would not be required to 

make any further demonstration of the 

influence of background sources on 

concentrations measured at the 

fenceline. For facilities where additional 

background adjustment is appropriate, 

optional strategies could include 

deployment of additional passive 

samplers at distances from the fenceline 

(toward and away from suspected NFS) 

and reducing the time intervals of 

passive deployments to increase time 

resolution and wind directioncomparison capability. In complex 

cases, such as two refineries sharing a 

common fenceline, wind-sector 

sampling or various forms of timeresolved monitoring may be required to 

ascertain the fenceline concentrations. 

We are proposing that owners or 

operators of petroleum refineries 

electing to determine monitoring 

location-specific NFS concentrations 

must prepare and submit a site-specific 

monitoring plan. The monitoring plan is 

required to identify specific near-field 

sources, identify the location and type 

of monitors used to determine UB and 

NFS concentrations, identify the 

monitoring location(s) for which the 

NFS concentrations would apply, and 

delineate the calculations to be used to 

determine monitoring location specific 

NFS concentrations (for those 

monitoring locations impacted by the 

near-field source). We are proposing 

that the site-specific monitoring plan 

must be submitted to the Administrator 

for approval and receive approval prior 

to its use for determining HFC values. 

The EPA requests comment on the 

most appropriate approach(es) for 

adjusting measured fenceline 

concentrations for background 

contributions, including (in complex 

cases) where meteorology is highly 

variable or where one or more near-field 

off-site sources affect the measured 

fenceline concentration (MFC) at a 

refinery. We are also seeking comment 

on the adequacy of the proposed 

requirements for developing and 

approving site-specific monitoring 

plans. 

Concentration action level. As 

mentioned above, the EPA is proposing 

to require refineries to take corrective 

action to reduce fugitive emissions if 

monitored fenceline concentrations 

exceed a specific concentration action 

level on a rolling annual average basis 

(recalculated every two weeks). We 

selected this proposed fenceline action 

level by modeling fenceline benzene 

concentrations using the emissions 

inventories reported in response to the 

2011 Refinery ICR, assuming that those 

reported emissions represented full 

compliance with all refinery MACT 

requirements, adjusted for additional 

control requirements we are proposing 


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in today’s action. Thus, if the reported 

inventories are accurate, all facilities 

should be able to meet the fenceline 

concentration action level. We 

estimated the long-term ambient postcontrol benzene concentrations at each 

petroleum refinery using the postcontrol emission inventory and EPA’s 

American Meteorological Society/EPA 

Regulatory Model dispersion modeling 

system (AERMOD). Concentrations were 

estimated by the model at a set of polar 

grid receptors centered on each facility, 

as well as surrounding census block 

centroid receptors extending from the 

facility outward to 50 km. For purposes 

of this modeling analysis, we assumed 

that the nearest off-site polar grid 

receptor was the best representation of 

each facility’s fenceline concentration in 

the post-control case, unless there was 

a census block centroid nearer to the 

fenceline than the nearest off-site polar 

grid receptor or an actual receptor was 

identified from review of the site map. 

In those instances, we estimated the 

fenceline concentration as the 

concentration at the census block 

centroid. Only receptors (either the 

polar or census block) that were 

estimated to be outside the facility 

fenceline were considered in 

determining the maximum benzene 

level for each facility. We note that this 

analysis does not correlate to any 

particular metric related to risk. The 

maximum post-control benzene 

concentration modeled at the fenceline 

for any facility is 9 micrograms per 

cubic meter (mg/m3) (annual average). 

(For further details of the analysis, see 

memo entitled Fenceline Ambient 

Benzene Concentrations Surrounding 

Petroleum Refineries in Docket ID 

Number EPA–HQ–OAR–2010–0682.) 

The facility inventories generally 

project emissions with the required 

fugitive controls working as designed 

(e.g., no tears in seals for storage vessel 

floating roofs and water in all water 

drain seals). If facility inventories are 

correct, annual average benzene 

concentrations would not exceed 9 mg/ 

m3 at the fenceline of any facility. 

Because the modeling approach 

considers only the emissions from the 

refinery, with no contribution from 

background or near-field sources, this 

concentration is comparable to the 

highest modeled fenceline 

concentration after correcting for 

background concentrations, as described 

previously. The EPA is proposing to set 

the standard at this concentration action 

level. We also note that this modeling 

effort evaluated the annual average 

benzene concentration at the fenceline, 

so that this action level applies to the 

annual average fenceline concentration 

measured at the facility. 

The EPA recognizes that, because it is 

difficult to directly measure emissions 

from fugitive sources, there is 

significant uncertainty in current 

emissions inventories for fugitives. 

Thus, there is the potential for benzene 

concentrations monitored at the 

fenceline to exceed modeled 

concentrations. However, given the 

absence of fenceline monitors at most 

facilities, there is very limited 

information available at present about 

fenceline concentrations and the extent 

to which they may exceed 

concentrations modeled from 

inventories. In the absence of additional 

data regarding the concentration of 

fugitive emissions of benzene at the 

fenceline, the EPA believes it is 

reasonable to rely on the maximum 

modeled fenceline value as the 

concentration action level. We are 

soliciting comment on alternative 

concentration action levels and other 

approaches for establishing the 

concentration action level. 

Due to differences in short-term 

meteorological conditions, short-term 

(i.e., two-week average) concentrations 

at the fenceline can vary greatly. Given 

the high variability in short-term 

fenceline concentrations and the 

difficulties and uncertainties associated 

with estimating a maximum 2-week 

fenceline concentration given a limited 

number of years of meteorological data 

used in the modeling exercise, we 

determined that it would be 

inappropriate and ineffective to propose 

a short-term concentration action level 

that would trigger corrective action 

based on a single 2-week sampling 

event. 

One objective for this monitoring 

program is to identify fugitive emission 

releases more quickly, so that corrective 

action can be implemented in a more 

timely fashion than might otherwise 

occur without the fenceline monitoring 

requirement. We believe the proposed 

fenceline monitoring approach and a 

rolling annual average concentration 

action limit (i.e., using results from the 

most recent 26 consecutive 2-week 

samples and recalculating the average 

every 2 weeks) will achieve this 

objective. The proposed fenceline 

monitoring will provide the refinery 

owner or operator with fenceline 

concentration information once every 2 

weeks. Therefore, the refinery owner or 

operator will be able to timely identify 

emissions leading to elevated fenceline 

concentrations. We anticipate that the 

refinery owners or operators will elect 

to identify and correct these sources 

early, in efforts to avoid exceeding the 

annual benzene concentration action 

level. 

An ‘‘exceedance’’ of the benzene 

concentration action level would occur 

when the rolling annual average highest 

fenceline concentration, corrected for 

background (determined as described 

previously), exceeds 9 mg/m3. Upon 

exceeding the concentration action 

level, we propose that refinery owners 

or operators would be required to 

conduct analyses to identify sources 

contributing to fenceline concentrations 

and take corrective action to reduce 

fugitive emissions to ensure fenceline 

benzene concentrations remain at or 

below 9 mg/m3 (rolling annual average). 

Corrective action requirements. As 

described previously, the EPA is 

proposing that the owner or operator 

analyze the samples and compare the 

rolling annual average fenceline 

concentration, corrected for background, 

to the concentration action level. This 

section summarizes the corrective 

action requirements in this proposed 

rule. First, we are proposing that the 

calculation of the rolling annual average 

fenceline concentration must be 

completed within 30 days after the 

completion of each sampling episode. If 

the rolling annual average fenceline 

benzene concentration, corrected for 

background, exceeds the proposed 

concentration action level (i.e., 9 mg/

m3), the facility must, within 5 days of 

comparing the rolling annual average 

concentration to the concentration 

action level, initiate a root cause 

analysis to determine the primary cause, 

and any other contributing cause(s), of 

the exceedance. The facility must 

complete the root cause analysis and 

implement corrective action within 45 

days of initiating the root cause 

analysis. We are not proposing specific 

controls or corrections that would be 

required when the concentration action 

level is exceeded because the cause of 

an exceedance could vary greatly from 

facility to facility and episode to 

episode, since many different sources 

emit fugitive emissions. Rather, we are 

proposing to allow facilities to 

determine, based on their own analysis 

of their operations, the action that must 

be taken to reduce air concentrations at 

the fenceline to levels at or below the 

concentration action level, representing 

full compliance with all refinery MACT 

requirements, adjusted for additional 

control requirements we are proposing 

in today’s action. 

If, upon completion of the corrective 

action described above, the owner or 

operator exceeds the action level for the 

next two-week sampling episode 

following the completion of a first set of 

corrective actions, the owner or operator 


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would be required to develop and 

submit to EPA a corrective action plan 

that would describe the corrective 

actions completed to date. This plan 

would include a schedule for 

implementation of emission reduction 

measures that the owner or operator can 

demonstrate is as soon as practical. This 

plan would be submitted to the 

Administrator for approval within 30 

days of an exceedance occurring during 

the next two-week sampling episode 

following the completion of the initial 

round of corrective action. The EPA 

would evaluate this plan based on the 

ambient concentrations measured, the 

sources identified as contributing to the 

high fenceline concentration, the 

potential emission reduction measures 

identified, and the emission reduction 

measures proposed to be implemented 

in light of the costs of the options 

considered and the reductions needed 

to reduce the ambient concentration 

below the action level threshold. To 

minimize burden on the state 

implementing agencies and provide 

additional resources for identifying 

potential emission sources, we are 

proposing not to delegate approval of 

this plan. The refinery owner or 

operator is not deemed out of 

compliance with the proposed 

concentration action level, provided 

that the appropriate corrective action 

measures are taken according to the 

time-frame detailed in an approved 

corrective action plan. 

The EPA requests comment on 

whether it is appropriate to establish a 

standard time frame for compliance 

with actions listed in a corrective action 

plan. We also request comment on 

whether the approval of the corrective 

action plan should be delegated to state, 

local and tribal governments. 

The EPA’s post-control dispersion 

modeling (described in section III.A of 

this preamble), which relies on reported 

emissions inventories from the 2011 

Refinery ICR, adjusted to reflect 

compliance with the existing refinery 

MACT standards as modified by the 

additional controls proposed in this 

rulemaking, indicates that fugitive 

emissions at all refineries are low 

enough to ensure that fenceline 

concentrations of benzene do not exceed 

the proposed concentration action level. 

Assuming the reported inventories and 

associated modeling are accurate, we 

expect that few, if any, facilities will 

need to engage in required corrective 

action. We do, however, expect that 

facilities may identify ‘‘poorperforming’’ sources (e.g., unusual 

leaks) from the fenceline monitoring 

data and, based on this additional 

information, will take action to reduce 

HAP emissions before they would have 

otherwise been aware of the issue 

through existing inspection and 

enforcement measures. 

By selecting a fenceline monitoring 

approach and by selecting benzene as 

the surrogate for organic HAP 

emissions, we believe that the proposed 

monitoring approach will effectively 

target refinery MACT-regulated fugitive 

emission sources. However, there may 

be instances where the fenceline 

concentration is impacted by a low-level 

miscellaneous process vent, heat 

exchange system or other similar source. 

As these sources are regulated under 

Refinery MACT 1 and the emissions 

from these sources were included in our 

post-control modeling file (from which 

the 9 mg/m3 fenceline concentration 

action level was developed), sources 

would not be able to avoid taking 

corrective action by claiming the 

exceedance of the fenceline 

concentration was from one of these 

emission points rather than from 

fugitive emission sources. 

There may be instances in which the 

high fenceline concentration is 

impacted by a non-refinery emission 

source. The most likely instance of this 

would be leaks from HON equipment or 

HON storage vessels co-located at the 

refinery. However, we consider the 

fenceline monitoring requirement to be 

specific to refinery emission sources. 

Therefore, we are proposing to allow 

refinery owners or operators to develop 

site-specific monitoring plans to 

determine the impact of these nonRefinery emission sources on the 

ambient benzene concentration 

measured at the fenceline. This 

monitoring plan would be identical to 

those used by refinery owners or 

operators that elect to determine 

monitoring location-specific NFS values 

for nearby off-site sources. In this case, 

however, the NFS is actually within the 

refinery fenceline. Upon approval and 

implementation of the monitoring plan, 

the refinery owner or operator would 

determine the highest fenceline 

concentration corrected for background; 

the background correction in this case 

includes a correction for the co-located 

non-Refinery emission source(s). 

The EPA requests comment on 

whether the corrective action 

requirements should be limited to 

exceedances of the fenceline 

concentration solely from refinery 

emission sources and whether a refinery 

owner or operator should be allowed to 

exceed the annual average fenceline 

concentration action level if they can 

demonstrate the exceedance of the 

action level is due to a non-refinery 

emissions source. We also request 

comment on the requirements proposed 

for refinery owners or operators to 

demonstrate that the exceedance is 

caused by a non-refinery emissions 

source. Specifically, we request 

comment on whether the ‘‘near-field 

source’’ correction is appropriate for onsite sources and whether there are other 

methods by which refinery owners or 

operators with co-located, non-refinery 

emission sources can demonstrate that 

their benzene concentrations do not 

exceed the proposed fenceline 

concentration action level. 

Additional requirements of the 

fenceline monitoring program. We are 

proposing that fenceline data at each 

monitor location be reported 

electronically for each semiannual 

period’s worth of sampling periods (i.e., 

13 to 14 2-week sampling periods per 

semiannual period). These data would 

be reported within 45 days of the end 

of each semiannual period, and will be 

made available to the public through the 

EPA’s electronic reporting and data 

retrieval portal, in keeping with the 

EPA’s efforts to streamline and reduce 

reporting burden and to move away 

from hard copy submittals of data where 

feasible. 

We are proposing to require the 

reporting of raw fenceline monitoring 

data, and not just the HFC, on a 

semiannual basis; considering the fact 

that the fenceline monitoring standard 

is a new approach for fugitive emissions 

control, and it involves the use of new 

methods, both analytical and siting 

methods, this information is necessary 

for the EPA to evaluate whether this 

standard has been implemented 

correctly. Further, the information 

provided by the raw data, such as the 

need for additional or less monitoring 

sites, the range of measured 

concentrations, the influence of 

background sources, and the ability to 

collect and compare data from all 

refineries, will inform us of further 

improvements we can make to the 

fenceline standard, monitoring and 

analytical methods, approaches for 

estimating refinery fugitive emissions, 

and guidance that may be helpful to 

improve implementation of the 

fenceline monitoring approach. We seek 

comment on suggestions for other ways 

we can monitor and improve the 

fenceline monitoring requirement. 

We are proposing that facilities be 

required to conduct fenceline 

monitoring on a continuous basis, in 

accordance with the specific methods 

described above, even if benzene 

concentrations, as measured at the 

fenceline, routinely are substantially 

lower than the concentration action 

level. In light of the low annual 


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monitoring and reporting costs 

associated with the fenceline monitors 

(as described in the next section), and 

the importance of the fenceline 

monitors as a means of ensuring the 

control of fugitives achieves the 

expected emission levels, we believe it 

is appropriate to require collection of 

fenceline monitoring data on a 

continuous basis. However, the EPA 

recognizes that fugitive benzene 

emissions from some facilities may be 

so low as to make it improbable that 

exceedances of the concentration action 

level would ever occur. 

In the interest of reducing the cost 

burden on facilities to comply with this 

rule, the EPA solicits comment on 

approaches for reducing or eliminating 

fenceline monitoring requirements for 

facilities that consistently measure 

fenceline concentrations below the 

concentration action level, and the 

measurement level that should be used 

to provide such relief. Such an approach 

would be consistent with graduated 

requirements for valve leak monitoring 

in Refinery MACT 1 and other 

equipment leak standards, where the 

frequency of required monitoring varies 

depending on the percent of leaking 

valves identified during the previous 

monitoring period (see, for example, 40 

CFR 63.648(c) and 40 CFR 63.168(d)). 

The EPA requests comment on the 

minimum time period facilities should 

be required to conduct fenceline 

monitoring; the level of performance, in 

terms of monitored fenceline 

concentrations, that would enable a 

facility to discontinue use of fenceline 

monitors or reduce the frequency of data 

collection and reporting; and any 

adjustments to the optical gas imaging 

camera requirements that would be 

necessary in conjunction with such 

changes to the fenceline monitoring 

requirements. 

i. Delayed Coking Units 

As noted in section IV.A of this 

preamble, we are soliciting comments 

on the need to establish MACT 

standards for DCU under CAA section 

112(d)(2) and (3). Even if we were to 

assume that there is already an 

applicable MACT standard for DCU, a 

technology review of this emission 

source, as prescribed under CAA section 

112(d)(6), would lead us to propose a 

depressurization limit of 2 psig because 

of technology advancements since the 

MACT standards were originally issued 

and because it is cost effective. Industry 

representatives have pointed out that 

Refinery NSPS Ja requires DCU at new 

and modified sources to depressure to 5 

psig, and they have indicated that EPA 

should not require a lower 

depressurization limit under a CAA 

section 112(d)(6) technology review. 

Further, industry representatives also 

provided summary-level information 

(available in Docket ID Number EPA– 

HQ–OAR–2010–0682 as correspondence 

from API entitled Coker Vent Potential 

Release Limit Preliminary Emission, 

Cost and Cost Effectiveness Estimates) 

on costs to depressure to 5 psig versus 

2 psig. While the cost information does 

not show large differences for any 

particular facility to depressure at 5 psig 

versus 2 psig, the information does 

show a large range in potential costs 

between refineries. At this time, we do 

not have the detailed, refinery-specific 

cost breakdowns to compare against our 

cost assumptions, which were derived 

from data obtained for a facility that did 

install the necessary equipment to meet 

a 2 psig limit. We also do not have 

detailed information on the design and 

operation of the DCU in industry’s cost 

study to evaluate whether there are any 

differences that would warrant 

subcategories. We solicit information on 

designs, operational factors, detailed 

costs and emissions data for DCU, and 

we specifically solicit comments on 

what should be the appropriate DCU 

depressurization limit if we were to 

adopt such a requirement pursuant to 

CAA section 112(d)(6) rather than 

pursuant to CAA section 112(d)(2) and 

(3). 

2. Refinery MACT 2—40 CFR Part 63, 

Subpart UUU 

The Refinery MACT 2 source category 

regulates HAP emissions from FCCU, 

CRU and SRU process vents. Criteria 

pollutant emissions from FCCU and 

SRU are regulated under 40 CFR part 60, 

subparts J and Ja (Refinery NSPS J and 

Refinery NSPS Ja, respectively). We 

conducted a technology review of 

Refinery NSPS J emission limits from 

2005 to 2008 and promulgated new 

standards for FCCU and SRU (among 

other sources) in Refinery NSPS Ja on 

June 24, 2008 (73 FR 35838). Our 

current technology review of Refinery 

MACT 2 relies upon, but is not limited 

to, consideration of this recent 

technology review of Refinery NSPS J 

for FCCU and SRU. 

a. FCCU Process Vent 

The FCCU has one large atmospheric 

vent, the coke burn-off exhaust stream 

for the unit’s catalyst regenerator. HAP 

emissions from this FCCU process vent 

include metal HAP associated with 

entrained catalyst particles and organic 

HAP, mostly by-products of incomplete 

combustion from the coke burn-off 

process. As the control technologies 

associated with each of these classes of 

pollutants are very different, the 

controls associated with each of these 

classes of pollutants are considered 

separately. 

Metal HAP emission controls. The 

current Refinery MACT 2 includes 

several different compliance options, 

some based on PM as a surrogate for 

total metal HAP and some based on 

nickel (Ni) as a surrogate for total metal 

HAP. Refinery NSPS J was the basis of 

the PM emission limits and the metal 

HAP MACT floor in Refinery MACT 2. 

Refinery NSPS J limits PM from FCCU 

catalyst regeneration vents to 1.0 gram 

particulate matter per kilogram (g PM/ 

kg) of coke burn-off, with an additional 

incremental PM allowance for liquid or 

solid fuel burned in an incinerator, 

waste heat boiler, or similar device. 

Refinery MACT 2 states that FCCU 

subject to Refinery NSPS J PM emission 

limits are required to demonstrate 

compliance with Refinery NSPS J PM 

emission limits as specified in Refinery 

NSPS J. As provided in Refinery NSPS 

J, ongoing compliance with the PM 

emission limits is determined by 

compliance with a 30-percent opacity 

limit, except for one 6-minute average 

per hour not to exceed 60-percent 

opacity. FCCU not subject to Refinery 

NSPS J may elect to comply with the 

FCCU PM provisions in Refinery NSPS 

J. Alternatively, they may comply with 

a 1.0 g PM/kg of coke burn-off emission 

limit in Refinery MACT 2 (with no 

provision for an additional incremental 

PM allowance for liquid or solid fuel 

burned in an incinerator, waste heat 

boiler, or similar device). Compliance 

with this limit in Refinery MACT 2 is 

demonstrated by either a 1-hour average 

site-specific opacity limit using a 

continuous opacity monitoring system 

(COMS) or APCD-specific daily average 

operating limits using CPMS. 

Refinery MACT 2 also includes two 

emission limit alternatives that use Ni, 

rather than PM, as the surrogate for 

metal HAP. The first of these Ni 

alternatives is a mass emission limit of 

13 grams Ni per hour; the second nickel 

alternative is an emission limit of 1.0 

milligrams Ni per kilogram of coke 

burn-off. Compliance with the Ni 

emission limits in Refinery MACT 2 is 

demonstrated by either a daily average 

site-specific Ni operating limit (using a 

COMS and weekly determination of Ni 

concentration on equilibrium FCCU 

catalyst), or APCD-specific daily average 

operating limits using CPMS and 

monthly average Ni concentration 

operating limit for the equilibrium 

FCCU catalyst. 

Under Refinery MACT 2, an initial 

performance demonstration (source test) 

is required to show that FCCU is 


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compliant with the emission limits 

selected by the refinery owner or 

operator. No additional performance test 

is required for facilities already 

complying with Refinery NSPS J. The 

performance test is a one-time 

requirement; additional performance 

tests are only required if the owner or 

operator elects to establish new 

operating limits, or to modify the FCCU 

or control system in such a manner that 

could affect the control system’s 

performance. 

Under the review for Refinery NSPS 

J, we conducted a literature review as 

well as a review of the EPA’s refinery 

settlements and state and local 

regulations affecting refineries to 

identify developments in practices, 

processes and control technologies to 

reduce PM emissions from refinery 

sources (see Summary of Data Gathering 

Efforts: Emission Control and Emission 

Reduction Activities, August 19, 2005, 

and Review of PM Emission Sources at 

Refineries, December 20, 2005, Docket 

Item Number EPA–HQ–OAR–2007– 

0011–0042). At that time, we identified 

regulations for PM from FCCU that were 

more stringent than the Refinery NSPS 

J requirements for PM, and we 

promulgated more stringent PM limits 

in Refinery NSPS Ja. Refinery NSPS Ja 

limits PM from FCCU catalyst 

regeneration vents to 1.0 g PM/kg of 

coke burn-off for modified or 

reconstructed FCCU, with no 

incremental allowance for PMassociated liquid or solid fuels burned 

in a post-combustion device. 

Furthermore, an emission limit of 0.5 g 

PM/kg of coke burn-off was established 

for FCCU constructed after May 14, 

2007. 

In addition, the Refinery NSPS J 

review identified improvements in 

APCD monitoring practices, which were 

included in the Refinery NSPS Ja 

standards. Refinery NSPS J includes a 

30-percent opacity limit as the only 

ongoing monitoring requirements for 

PM from the FCCU. This 30-percent 

opacity limit has shown to be lenient 

and high in comparison to recent federal 

rules that have included more stringent 

opacity limits (e.g., 40 CFR part 60, 

subpart Db with 20-percent opacity), 

and recent state and local agency rules 

that omit opacity limits altogether in 

favor of operating limits for the 

emission control systems. Based on the 

Refinery NSPS J review, Refinery NSPS 

Ja does not include an opacity limit, but 

includes updated and more appropriate 

monitoring approaches, such as 

requiring bag leak detectors (BLD) for 

fabric filter control systems, and 

requiring CPMS for electrostatic 

precipitators (ESP) and wet scrubbers. 

Additionally, Refinery NSPS Ja includes 

an option to measure PM emissions 

directly using a PM CEMS. For this 

monitoring alternative, a direct PM 

concentration limit (equivalent to the 

conventional FCCU PM emission limit 

in terms of g PM/kg of coke burn-off) is 

included in the rule. Finally, in our 

review for Refinery NSPS J, we noted 

that, even with improved monitoring 

methods, periodic source testing is 

needed to verify the performance of the 

control system as it ages. In Refinery 

NSPS Ja, annual performance 

demonstrations are required for affected 

FCCU. The Refinery NSPS Ja standards 

for PM from FCCU reflect the latest 

developments in practices, processes 

and control technologies. In our current 

review of Refinery MACT 2, we did not 

identify any other developments in 

practices, processes or control 

technologies since we promulgated 

Refinery NSPS Ja in 2008. 

The conclusions of the technology 

review conducted for the Refinery NSPS 

J PM emission limits are directly 

applicable to Refinery MACT 2; the 

initial Refinery MACT 2 rule recognized 

this by providing that compliance with 

Refinery NSPS J would also be 

compliance with Refinery MACT 2. We 

considered the impacts of proposing to 

revise Refinery MACT 2 to incorporate 

the developments in monitoring 

practices and control technologies 

reflected in the Refinery NSPS Ja limits 

and monitoring provisions. 

As noted above, Refinery NSPS Ja 

includes a limit of 0.5 g PM/kg of coke 

burn-off for newly constructed sources. 

There would be no costs associated with 

requiring the lower emission limit of 0.5 

g PM/kg of coke burn-off for Refinery 

MACT 2 new sources under CAA 

section 112(d)(6) because these sources 

would already be required to comply 

with that limit under Refinery NSPS Ja. 

Therefore, we are proposing that it is 

necessary pursuant to CAA section 

112(d)(6) to revise Refinery MACT 2 to 

incorporate the Refinery NSPS Ja PM 

limit for new sources. 

We are also proposing to establish 

emission limits and monitoring 

requirements in Refinery MACT 2 that 

are consistent with those in Refinery 

NSPS Ja. This option would not impose 

any additional cost on sources already 

subject to Refinery NSPS Ja. We note 

that for facilities subject to Refinery 

NSPS J, this would not lead to 

duplicative or conflicting monitoring 

requirements because Refinery NSPS J 

already includes a provision that allows 

affected facilities subject to Refinery 

NSPS J to instead comply with the 

provisions in Refinery NSPS Ja (see 40 

CFR 60.100(e)). 

In addition, in conjunction with our 

proposal to revise Refinery MACT 2 to 

include the more stringent requirements 

in Refinery NSPS Ja, we are proposing 

to remove the less stringent compliance 

option of meeting the requirements of 

Refinery NSPS J. As described 

previously, Refinery NSPS J includes an 

incremental PM emissions allowance for 

post-combustion devices and relies on a 

30-percent opacity limit that is outdated 

and has been demonstrated to be 

ineffective at identifying exceedances of 

the 1.0 g PM/kg coke burn-off emissions 

limit. 

We also reviewed the compliance 

monitoring requirements for the 

Refinery MACT 2 PM and Ni-based 

emission limits. As described 

previously, Refinery MACT 2 includes 

operating limits based on APCD 

operating parameters or site-specific 

opacity limits. There are differences 

between the monitoring approaches in 

Refinery MACT 2 for these limits and 

Refinery NSPS Ja monitoring 

approaches for the NSPS PM limit, so 

we evaluated whether it is necessary, 

pursuant to CAA section 112(d)(6), to 

revise the monitoring provisions in 

Refinery MACT 2 consistent with the 

requirements in Refinery NSPS Ja. 

The first significant difference is in 

the averaging times used for the 

different operating limits. Refinery 

NSPS Ja requires a 3-hour rolling 

average for the operating limits for 

parametric monitoring systems; Refinery 

MACT 2 includes daily averaging of the 

operating limits. Typically, the 

averaging time for operating limits is 

based on the duration of the 

performance test used to establish those 

operating limits. As the performance 

test duration is 3 hours (three 1-hour 

test runs) and compliance with the PM 

(or Ni) emission limit is based on the 

average emissions during this 3-hour 

period, the most appropriate averaging 

period for these operating limits is 3 

hours. Using a daily average could allow 

poor performance (i.e., control 

equipment for shorter periods (e.g., 3- 

hour averages that are higher than the 

PM emissions limit in Refinery NSPS 

Ja). For example, assume an operating 

limit developed from a performance test 

has a value of 1 and that values 

exceeding this level would suggest that 

the control system is not operating as 

well as during the performance test (i.e., 

potentially exceeding the PM emission 

limit). If the control system is run for 18 

hours operating at a level of 0.9 and 6 

hours at a level of 1.2, the unit would 

be in compliance with the daily 

operating limit even though the unit 

may have 6 consecutive hours during 

which the operating limit was exceeded. 


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Reducing the averaging time does not 

impact the types of monitors required; 

it merely requires the owner or operator 

of the unit to pay more careful attention 

to the APCD operating parameters. We 

are proposing that it is necessary, 

pursuant to CAA section 112(d)(6), to 

incorporate the use of 3-hour averages 

rather than daily averages for parameter 

operating limits in Refinery MACT 2 for 

both the PM and Ni limits, because this 

is a cost-effective development in 

monitoring practice. 

The site-specific opacity operating 

limit for PM in Refinery MACT 2 (for 

units not electing to comply with 

Refinery NSPS J) has a 1-hour averaging 

period, but the Ni operating limits 

(which use opacity monitoring) have a 

24-hour averaging period. These 

averaging periods are inconsistent with 

the duration of the performance test, 

which is over a 3-hour period. We are 

proposing, pursuant to CAA section 

112(d)(6), to incorporate the use of 3- 

hour averages for the site-specific 

opacity operating limit and the Ni 

operating limits rather than daily 

averages because this is a cost-effective 

development in monitoring practice. 

We also compared the APCD-specific 

operating parameters used in Refinery 

MACT 2 to those that we promulgated 

for Refinery NSPS Ja. The Refinery 

NSPS Ja rule includes monitoring 

approaches that are not included in 

Refinery MACT 2. These include the 

option of using PM CEMS and requiring 

BLD for fabric filter control systems. 

Adding a PM CEMS as an option for 

demonstrating compliance with the 

Refinery MACT 2 PM limit (similar to 

what is provided in Refinery NSPS Ja) 

would not impact the costs of 

complying with Refinery MACT 2 

because sources can choose whether or 

not to adopt this monitoring method. 

With respect to BLD, there is only one 

refinery that currently uses a baghouse 

(fabric filter) to control emissions from 

its FCCU (although one additional unit 

has indicated that it has plans to install 

a fabric filter control within the next 

few years). Under the existing 

requirements in Refinery MACT 2 

(assuming that the FCCU currently 

operating with a fabric filter has not 

elected to comply with the Refinery 

NSPS J PM emission limit option), it is 

required to comply with a site-specific 

opacity operating limit. For new, 

reconstructed, or modified FCCU, 

Refinery NSPS Ja requires use of BLD. 

While we generally consider the BLD to 

be superior to opacity monitors for 

ensuring fabric filter control systems are 

operating efficiently, it is difficult to 

determine what, if any, increment in 

assurance that the unit is properly 

controlled would be achieved by 

requiring the one facility currently 

operating a fabric filter control system 

and complying with a site-specific 

opacity operating limit to switch from a 

COMS to BLD. Therefore, we are 

proposing that it is not necessary to 

require the one existing FCCU with a 

fabric filter control system to switch 

from COMS to a BLD system because 

this would require additional 

monitoring equipment (with additional 

costs) and little to no associated 

increase in assurance that the unit is 

properly controlled. Although we are 

not proposing to require existing 

sources using a fabric filter to use BLD, 

we are proposing to include BLD as an 

option to COMS; owners or operators of 

FCCU using fabric filter-type control 

systems at existing sources can elect 

(but are not required) to use BLD in lieu 

of COMS and the site-specific opacity 

operating limit. 

The Refinery NSPS Ja monitoring 

requirements for ESP include CPMS for 

monitoring and recording the total 

power and the secondary current to the 

entire system. The current MACT 

requires monitoring voltage and 

secondary current or monitoring only 

the total power to the APCD. While 

these monitoring requirements are 

similar, we consider that the Refinery 

NSPS Ja requirements will provide 

improved operation of the ESP. As the 

monitors required to measure these 

parameters are a routine part of ESP 

installations, we project no additional 

costs for monitoring equipment. We 

expect that a new performance test 

would be needed to ensure that both 

total power and secondary current are 

recorded during the source test. As 

discussed later in this section, we are 

proposing to require ongoing 

performance tests regardless of the 

monitoring option, so we are not 

projecting any additional costs specific 

to revising the monitoring requirements 

for ESP. Because the Refinery NSPS Ja 

monitoring and operating requirements 

for ESP are expected to provide 

improved performance of the APCD 

with no incremental costs, we propose 

that it is necessary, pursuant to CAA 

section 112(d)(6), to incorporate the 

total power and the secondary current 

operating limits into Refinery MACT 2. 

Refinery NSPS Ja provides a specific 

monitoring alternative to pressure drop 

for jet ejector-type wet scrubbers or any 

other type of wet scrubbers equipped 

with atomizing spray nozzles. Owners 

or operators of FCCU controlled by 

these types of wet scrubbers can elect to 

perform daily checks of the air or water 

pressure to the spray nozzle rather than 

monitor pressure. Refinery MACT 2 

currently excludes these types of control 

systems from monitoring pressure drop 

but includes no specific monitoring to 

ensure the jet ejectors or atomizing 

spray nozzle systems are properly 

operating. Since proper functioning of 

the jet ejectors or atomizing spray 

nozzles is critical to ensuring these 

control systems operate at the level 

contemplated by the MACT, some 

monitoring/inspection requirement of 

these components is necessary to ensure 

compliance with the FCCU PM or Ni 

emission limit. The owner or operator of 

a jet ejector-type wet scrubber or other 

type of wet scrubber equipped with 

atomizing spray nozzles should be 

performing routine checks of these 

systems, such as the daily checks of the 

air or water pressure to the spray 

nozzles, as required in Refinery NSPS 

Ja. These daily checks are consistent 

with good operational practices for wet 

scrubbers and should not add 

significant burden to the FCCU wet 

scrubber owner or operator. For these 

reasons, we propose it is necessary to 

require owners or operators of a jet 

ejector-type wet scrubber or other type 

of wet scrubber equipped with 

atomizing spray nozzles to perform 

daily checks of the air or water pressure 

to the spray nozzles pursuant to CAA 

section 112(d)(6). 

Finally, in our action promulgating 

Refinery NSPS Ja, we noted that, even 

with improved monitoring methods, 

periodic source testing is needed to 

verify the performance of the control 

system as it ages. In Refinery NSPS Ja, 

annual performance demonstrations are 

required for new sources. FCCU subject 

to Refinery MACT 2 as new sources 

would also be subject to Refinery NSPS 

Ja and would have to comply with the 

annual testing requirements in Refinery 

NSPS Ja. However, Refinery MACT 2 

does not include periodic performance 

tests for any FCCU. We considered 

adding an annual testing requirement 

for FCCU subject to Refinery MACT 2. 

The annual nationwide cost burden 

exceeds $1 million per year and we 

project only modest improvement in 

control performance resulting from the 

performance demonstrations. We 

considered requiring FCCU performance 

tests once every 5 years (i.e., once per 

title V permit period). The nationwide 

annual cost of this additional testing 

requirement for FCCU is projected to be, 

on average, $213,000 per year. We 

consider this to be a reasonable 

minimum frequency for which affected 

sources should demonstrate direct 

compliance with the FCCU emission 

limits and that this cost is reasonable. 

Therefore, we propose that it is 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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necessary, pursuant to CAA section 

112(d)(6), to require a performance test 

once every 5 years for all FCCU under 

to Refinery MACT 2. 

Organic HAP. Refinery MACT 2 uses 

CO as a surrogate for organic HAP and 

establishes an emission limit of 500 

ppmv CO (dry basis). Some FCCU, 

referred to as complete-combustion 

FCCU, employ excess oxygen in the 

FCCU regenerator and are able to meet 

this emission limit without the need for 

a post-combustion device. Other FCCU, 

referred to as partial-combustion FCCU, 

do not supply enough air/oxygen for 

complete combustion of the coke to CO2

and, therefore, produce a significant 

quantity of CO in the regenerator 

exhaust. Partial-combustion FCCU are 

typically followed by a post-combustion 

unit, commonly referred to as a CO 

boiler, to burn the CO in the regenerator 

exhaust in order to meet the 500 ppmv 

CO limit (and to recover useful heat 

from the exhaust stream). 

In our review of Refinery NSPS J, we 

conducted a review of state and local 

regulations affecting refineries to 

identify control strategies to reduce CO 

emissions or VOC emissions from 

refinery sources (see Review of VOC 

Emission Sources at Refineries, 

December 14, 2005, Docket Item 

Number EPA–HQ–OAR–2007–0011– 

0043). We also conducted a review of 

federal, state and local regulations 

affecting refineries to identify control 

strategies to reduce CO emissions from 

refinery sources (see Review of CO 

Emission Sources at Refineries, 

December 22, 2005, Docket Item 

Number EPA–HQ–OAR–2007–0011– 

0044). We did not identify any 

developments in practices, processes 

and control technologies to reduce CO 

or VOC emissions from FCCU as part of 

the review of Refinery NSPS J, and we 

have not identified any developments in 

practices, processes and control 

technologies for FCCU that would 

reduce organic HAP since promulgation 

of Refinery MACT 2. We are proposing 

that it is not necessary to revise the 

regulatory provisions for organic HAP in 

the current MACT standards for FCCU, 

pursuant to CAA section 112(d)(6). 

Inorganic HAP. As mentioned 

previously, Refinery MACT 2 includes a 

CO emission limit of 500 ppmv. 

Although this limit is expressly 

provided as a limit addressing organic 

HAP emissions, this emission limit is 

also expected to limit the emissions of 

oxidizable inorganic HAP, such as HCN. 

That is, the CO concentration limit was 

developed as an indicator of complete 

combustion for all oxidizable pollutants 

typically found in exhaust gas from the 

FCCU regenerator operated in partial 

burn mode. We note that HCN 

concentrations in FCCU regenerator 

exhaust with high CO levels also have 

high HCN concentrations and that HCN 

concentrations in the regenerator 

exhaust from complete-combustion 

FCCU (those meeting the 500 ppmv CO 

limit without the need for a postcombustion device) are much lower 

than those from partial burn FCCU prior 

to a post-combustion device. Thus, we 

consider that the CO emission limit also 

acts as a surrogate for the control of 

oxidizable inorganic HAP, such as HCN. 

The source test data from the ICR 

effort revealed that HCN emissions from 

FCCU are greater than previous tests 

indicated, particularly for completecombustion FCCU. The increase in HCN 

emissions was observed at units meeting 

lower NOX emission limits, which have 

recently been required by consent 

decrees, state and local requirements 

and Refinery NSPS Ja. The higher HCN 

emissions from complete-combustion 

FCCU appear to be directly related to 

operational changes made in efforts to 

meet these lower NOX emission limits 

(e.g., reduced excess oxygen levels in 

the regenerator and reduced regenerator 

bed temperatures). These higher HCN 

emissions were only observed in 

complete-combustion FCCU; FCCU that 

operated in partial burn mode followed 

by a CO boiler or similar postcombustion device had significantly 

lower HCN emissions subsequent to the 

post-combustion device. 

Based on our review of the available 

ICR data and the technologies used in 

practice, we considered establishing 

specific emission limits for HCN. In 

order to comply with emission limits for 

HCN, owners or operators of completecombustion FCCU would either have to 

operate their FCCU regenerator at 

slightly higher temperatures and excess 

oxygen concentrations (to limit the 

formation of HCN in the regenerator) or 

employ a post-combustion device or 

thermal oxidizer to destroy HCN 

exhausted from the FCCU regenerator. 

However, each of these options comes 

with significant secondary energy and 

environmental impacts. First, both of 

these control strategies would yield a 

significant increase in NOX emissions. 

We anticipate that most FCCU owners 

or operators would have to install a 

selective catalytic reduction (SCR) 

system to meet their NOX emission 

limits, if applicable. Operation of the 

SCR would have energy impacts and 

may have additional secondary PM2.5

impacts (associated with ammonia slip 

from the SCR). We expect that 

modifying the regenerator operating 

characteristics is the most cost-effective 

option, although installing and using a 

thermal oxidizer may be necessary, 

depending on the operational 

characteristics of the regenerator and the 

HCN control requirement. Using a 

thermal oxidizer to treat FCCU 

regenerator exhaust, a gas stream that 

has limited heating value (due to the 

already low CO concentrations) would 

be much more expensive and would 

have additional energy and secondary 

impacts associated with the auxiliary 

fuel needed for the device, as compared 

to modifying regenerator operating 

conditions. 

We first performed a screening 

analysis of the impacts of making only 

operational changes to the FCCU with 

the highest HCN concentrations. If this 

control option is not cost effective for 

these FCCU, it would not be cost 

effective for units that have lower HCN 

concentrations and lower HCN 

emissions. Similarly, if operating 

changes in the FCCU regenerator alone 

are not cost effective, then we can 

assume that installing a thermal 

oxidizer to achieve this same level of 

HCN emission reductions would also 

not be cost effective. We calculated the 

cost of changing the regenerator 

parameters and adding an SCR for the 

FCCU with the highest HCN emissions 

rate reported in the ICR, which is an 

annual emissions rate of 460 tpy. This 

is also the largest FCCU in operation in 

the United States and its territories. 

Based on the size of this unit, we project 

that an SCR would be expected to cost 

approximately $13-million and have 

annualized costs of approximately $4.0- 

million/yr. Thus, if the HCN emissions 

can be reduced by 95 percent, the cost 

effectiveness would be approximately 

$9,000 per ton of HCN. A smaller FCCU 

had similar HCN concentrations and 

annual HCN emissions of 141 tpy. Based 

on the size of this unit, we project an 

SCR would be expected to cost 

approximately $7-million and have 

annualized costs of approximately $1.5- 

million/yr. Assuming a 95-percent 

reduction in HCN emissions, the cost 

effectiveness would be approximately 

$11,000 per ton of HCN. The secondhighest emitting FCCU was larger than 

this unit, but had lower HCN 

concentrations. This third unit had 

emissions of 184 tpy. Based on the size 

of this unit, we expect that an SCR 

would cost approximately $9-million 

and have annualized costs of 

approximately $2.2-million/yr. 

Assuming a 95-percent reduction in 

HCN emissions, the cost effectiveness 

would be approximately $12,600 per ton 

of HCN. 

These costs are for the FCCU with the 

largest HCN emissions and the lowest 

control cost (assuming operational 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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changes alone are insufficient to 

significantly reduce HCN emissions), 

and the average cost effectiveness for 

these units exceeds $10,000 per ton 

HCN emissions reduced. Based on the 

economies of scale and considering 

lower HCN concentrations for all other 

units, the costs per ton of HCN removed 

for a nationwide standard would be 

higher. If a post-combustion device is 

needed to achieve a specific HCN 

emissions limit, the costs would be even 

higher. 

Based on the cost, secondary energy 

and secondary environmental impacts 

of an HCN emission limit beyond that 

achieved by the CO emission limit as a 

surrogate for HCN, we are proposing, at 

this time, that it is not necessary, 

pursuant to CAA section 112(d)(6), to 

revise the MACT standard to establish a 

separate HCN standard. As our 

understanding of the mechanisms of 

HCN and NOX formation improves and 

as catalyst additives evolve, it may be 

possible to achieve both low NOX and 

low HCN emissions without the use of 

an SCR and/or post-combustion 

controls. However, at this time our test 

data indicate an inverse correlation 

between these two pollutants. The three 

facilities with the highest HCN 

concentrations were the facilities with 

the lowest NOX concentrations, all of 

which were below 20 ppmv (dry basis, 

0-percent excess air) during the 

performance tests. While a 20 ppmv 

NOX limit may be achievable, we 

anticipate that further reducing the NOX

new source performance limits for 

FCCU would either increase PM2.5

secondary emissions (via the use of an 

SCR and its associated ammonia slip) or 

further increase HCN emissions (if 

combustion controls are used). 

b. CRU Process Vents 

A CRU is designed to reform (i.e., 

change the chemical structure of) 

naphtha into higher-octane aromatics. 

The reforming process uses a platinum 

or bimetal (e.g., platinum and rhenium) 

catalyst material. Small amounts of coke 

deposit on the catalyst during the 

catalytic reaction and this coke is 

burned off the catalyst to regenerate 

catalyst activity. There are three types of 

CRU classified by differences in how the 

units are designed and operated to effect 

reforming catalyst regeneration. Semiregenerative reforming is characterized 

by shutting down the reforming unit at 

specified intervals, or at the operator’s 

convenience, for in situ catalyst 

regeneration. Semi-regenerative CRU 

typically regenerate catalyst once every 

8 to 18 months, with the regeneration 

cycle lasting approximately 2 weeks. 

Cyclic-regeneration reforming is 

characterized by continuous or 

continual reforming operation with 

periodic (but frequent) regeneration of 

catalyst in situ by isolating one of the 

reactors in the series, regenerating the 

catalyst, then returning the reactor to 

the reforming operation. The 

regeneration of the catalyst in a single 

reactor may occur numerous times per 

year (e.g., once a month), and the 

regeneration of each reactor may take 3 

to 5 days to complete. Continuousregeneration reforming units use moving 

catalyst bed reactors situated vertically 

(which is why they are often referred to 

as platforming units). Catalyst flows 

down the series of reactors. At the 

bottom of the last reactor, catalyst is 

continually isolated and sent to a 

special regenerator. After regeneration, 

the regenerated catalyst is continually 

fed to the first (top) reactor. Thus, 

continuous-regeneration reforming units 

are characterized by continuousreforming operation along with 

continuous-regeneration operation. 

The catalytic reforming reaction is 

performed in a closed reactor system; 

there are no emissions associated with 

the processing portion of the CRU. 

There is a series of emission points 

associated with the CRU catalyst 

regenerator. Regardless of the type of 

CRU used, there is a series of steps 

conducted to effect catalyst 

regeneration. These steps are: (1) Initial 

depressurization/purge; (2) coke burnoff; (3) catalyst rejuvenation; and 

(4) reduction/final purge. The primary 

emissions during the depressurization/

purge cycle are organic HAP. Inorganic 

HAP, predominately HCl and chlorine, 

are emitted during the coke burn-off and 

rejuvenation cycles. The reduction 

purge is mostly inert materials (nitrogen 

and/or hydrogen). Refinery MACT 2 

contains organic HAP emission limits 

for the depressurization/purge cycle 

(purging prior to coke-burn-off) and 

inorganic HAP emission limits for the 

coke burn-off and catalyst rejuvenation 

cycles. Our technology review, 

summarized below, considers each of 

these emission limits separately. For 

additional details on the technology 

review for CRU, see Technology Review 

Memorandum for Catalytic Reforming 

Units at Petroleum Refineries in Docket 

ID Number EPA–HQ–OAR–2010–0682. 

Organic HAP. Refinery MACT 2 

requires the owner or operator to 

comply with either a 98-percent 

reduction of TOC or non-methane TOC, 

or an outlet concentration of 20 ppmv 

or less (dry basis, as hexane, corrected 

to 3-percent oxygen). The emission 

limits for organic HAP for the CRU do 

not apply to emissions from process 

vents during depressuring and purging 

operations when the reactor vent 

pressure is 5 psig or less. Control 

technologies used include directing the 

purge gas directly to the CRU process 

heater to be burned, recovering the gas 

to the facility’s fuel gas system, or 

venting to a flare or other APCD. The 

pressure limit exclusion was provided 

to allow atmospheric venting of the 

emissions when the pressure of the 

vessel fell below that needed to 

passively direct the purge gas to the 

APCD (most commonly the CRU process 

heater or flare). 

We did not identify any developments 

in practices, processes and control 

technologies for reducing organic HAP 

emissions from CRU. However, as noted 

in section IV.A.2 of this preamble, we 

are proposing to amend the pressure 

limit exclusion pursuant to CAA 

sections 112(d)(2) and (3) to clarify that 

this limit only applies during passive 

vessel depressuring. Also, as described 

in section IV.A.3 of this preamble, we 

are proposing revisions to Refinery 

MACT 1 and 2, pursuant to CAA 

sections 112(d)(2) and (3), to ensure 

flares used as APCD meet the required 

destruction efficiency, which includes 

flares used to control the organic HAP 

emissions from the CRU 

depressurization/purge vent streams. 

Inorganic HAP. Refinery MACT 2 uses 

HCl as a surrogate for inorganic HAP 

during the coke burn-off and 

rejuvenation cycles. Refinery MACT 2 

requires owners or operators of existing 

semi-regenerative CRU to reduce 

uncontrolled emissions of HCl by 92- 

percent by weight or to a concentration 

of 30 ppmv (dry basis, corrected to 3- 

percent oxygen) during the coke burnoff and rejuvenation cycles. Owners or 

operators of new semi-regenerative 

CRU, new or existing cyclic CRU, or 

new or existing continuous CRU are 

required to reduce uncontrolled 

emissions of HCl by 97-percent by 

weight or to a concentration of 10 ppmv 

(dry basis, corrected to 3-percent 

oxygen) during the coke burn-off and 

rejuvenation cycles. Technologies used 

to achieve these limits include caustic 

spray injection, wet scrubbers, and solid 

adsorption systems. We conducted a 

technology review for CRU by reviewing 

the ICR responses and scientific 

literature. We did not identify any 

developments in practices, processes 

and control technologies for reducing 

inorganic HAP emissions from CRU. We 

are proposing that it is not necessary to 

revise the current inorganic HAP MACT 

standards for CRU, pursuant to CAA 

section 112(d)(6). 


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c. SRU Process Vents 

Most sulfur recovery plants at 

petroleum refineries use the Claus 

reaction to produce elemental sulfur. In 

the Claus reaction, two moles of 

hydrogen sulfide (H2S) react with one 

mole of SO2 in a catalytic reactor to 

form elemental sulfur and water vapor. 

Prior to the Claus reactors, one-third of 

the H2S in the sour gas feed to the sulfur 

plant must be oxidized to SO2 to have 

the correct proportion of H2S and SO2

for the Claus reaction. This oxidation 

step is performed in the ‘‘Claus burner.’’ 

The remaining gas stream, after the 

elemental sulfur is condensed, is 

referred to as ‘‘tail gas.’’ HAP emissions 

in tail gas from sulfur recovery plants 

are predominately COS and CS2, which 

are primarily formed as side reactions of 

the Claus process. 

Refinery MACT 2 contains HAP 

standards for SRU that were based on 

the Refinery NSPS J SO2 and reduced 

sulfur compounds emission limits. 

Refinery NSPS J includes an emission 

limit of 300 ppmv reduced sulfur 

compounds for a reduction control 

system not followed by an incinerator, 

and an emission limit of 250 ppmv SO2

(dry basis, 0-percent excess air) for 

oxidative control systems or reductive 

control systems followed by 

incineration. These Refinery NSPS J 

limits apply only to Claus sulfur 

recovery plants with a sulfur recovery 

capacity greater than 20 long tons per 

day (LTD). These emission limits 

effectively required sulfur recovery 

plants to achieve 99.9-percent sulfur 

recovery. 

Refinery MACT 2 defines SRU as a 

process unit that recovers elemental 

sulfur from gases that contain reduced 

sulfur compounds and other pollutants, 

usually by a vapor-phase catalytic 

reaction of sulfur dioxide and hydrogen 

sulfide (see 40 CFR 63.1579). This 

definition specifically excludes sulfur 

recovery processes that do not recover 

elemental sulfur, such as the LO–CAT II 

process, but does not necessarily limit 

applicability to Claus SRU. Refinery 

MACT 2 requires owners or operators of 

an SRU that is subject to Refinery NSPS 

J to meet the Refinery NSPS J limits. 

Owners or operators of an SRU that is 

not subject to Refinery NSPS J can elect 

to meet the emission limits in Refinery 

NSPS J or meet a reduced sulfur 

compound limit of 300 ppmv (dry basis, 

0-percent excess air) regardless of the 

type of control system or the presence 

of an incinerator. Unlike Refinery NSPS 

J, Refinery MACT 2 does not have a 

capacity applicability limit, so this 300 

ppmv reduced sulfur compound limit is 

applicable to all SRU (as that term is 

defined), regardless of size. 

Upon completion of our technology 

review for Refinery NSPS J, we 

promulgated Refinery NSPS Ja, which 

includes new provisions for the sulfur 

recovery plant. First, Refinery NSPS Ja 

limits are now applicable to all sulfur 

recovery plants, not just Claus sulfur 

recovery plants. Second, emission limits 

were added for sulfur recovery plants 

with a capacity of 20 LTD or less, to 

require new, small sulfur recovery 

plants to achieve a target sulfur recovery 

efficiency of 99-percent. These limits 

are a factor of 10 higher than the 

emission limits for larger sulfur 

recovery plants (i.e., 3,000 ppmv 

reduced sulfur compounds for a 

reduction control system not followed 

by an incinerator and 2,500 ppmv SO2

for oxidative control systems or 

reductive control systems followed by 

incineration). Refinery NSPS J did not 

include emission limits for these 

smaller sulfur recovery plants. Third, 

new correlations were introduced to 

provide equivalent emission limits for 

systems that use oxygen-enriched air in 

their Claus burner. 

The technology review conducted for 

Refinery NSPS J focused on SO2

emissions. Under our current 

technology review for Refinery MACT 2, 

we considered the developments in 

practices, processes or control 

technologies identified in the Refinery 

NSPS J technology review as they 

pertain to HAP emissions and the 

existing Refinery MACT 2 requirements. 

We considered the new Refinery 

NSPS Ja limits for small sulfur recovery 

plants. While Refinery NSPS Ja 

establishes criteria pollutant emission 

limits for these smaller sulfur recovery 

plants that were previously unregulated 

for such emissions, these sources are 

already covered under Refinery MACT 

2. Refinery MACT 2 requires these SRU 

to meet a 300 ppmv reduced sulfur 

compound limit, which is more 

stringent than the 3,000 ppmv limit 

established in Refinery NSPS Ja. 

We also considered the new 

correlations in Refinery NSPS Ja for 

SRU that use oxygen-enriched air in 

their Claus burner. In the technology 

review under Refinery NSPS J, we 

identified a change in practice in the 

operation of certain Claus SRU. At the 

time we promulgated Refinery MACT 2, 

we assumed that all units were using 

ambient air in the Claus burner, and we 

established the same emission limits as 

in Refinery NSPS J. Now, however, we 

understand that some facilities are using 

oxygen-enriched air. This practice 

lowers the amount of inert gases 

introduced into the SRU and improves 

operational performance and reliability 

of the sulfur recovery plant. Air is 

approximately 20.9 percent by volume 

oxygen and 79.1-percent inert gases 

(predominately nitrogen with 1-percent 

argon and other inert gases). The inert 

gases introduced in the Claus burner 

become a significant portion of the 

overall tail gas flow. When oxygen 

enrichment is used in the Claus burner, 

there are fewer inert gases in the tail gas 

and a lower overall tail gas flow rate. 

The same molar flow rate of reduced 

sulfur compounds will be present in the 

tail gas, but without the additional flow 

of inerts from the ambient air, the 

concentration of the reduced sulfur 

compounds (or SO2) in the tail gas is 

higher. 

In developing Refinery NSPS Ja, we 

included a correlation equation that 

facilities can use to adjust the 

concentration limit based on the 

enriched-oxygen concentration used in 

the Claus burner. This equation is 

designed to allow the same mass of 

emissions for these units as is allowed 

for units using only ambient air. That is, 

the emission equation establishes a 

concentration limit for units using 

oxygen enrichment so that the mass 

emissions from the unit do not exceed 

the mass emissions allowed under the 

250 ppmv SO2 (or 300 ppmv reduced 

sulfur compounds) emissions limits in 

Refinery NSPS J and in Refinery MACT 

2. The new equation in Refinery NSPS 

Ja for large sulfur recovery plants (those 

with sulfur recovery greater than 20 

LTD) provides an equivalent mass 

emissions rate of reduced sulfur HAP 

from the SRU as is currently required in 

Refinery MACT 2 while allowing a 

practice that improves the operational 

reliability of the unit. There are no costs 

to providing this option for units using 

oxygen-enriched air because: (1) It is an 

option that the owner or operator can 

elect to meet instead of the xisting 250 

ppmv SO2 emissions limit and (2) 

owners or operators of SRU that use 

oxygen-enriched air are expected to 

already routinely monitor the inlet air 

oxygen concentration for operational 

purposes. Therefore, we are proposing 

that it is necessary, pursuant to CAA 

section 112(d)(6), to amend Refinery 

MACT 2 sulfur recovery requirements to 

include this equation that addresses the 

use of oxygen-enriched air as a 

development in practice in SRU process 

operations. 

The emission limits for large sulfur 

recovery plants (those with sulfur 

recovery greater than 20 LTD) in 

Refinery NSPS Ja are equivalent to those 

in Refinery MACT 2. We are proposing 

to allow owners or operators subject to 

Refinery NSPS Ja limits for sulfur 


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recovery plants with a capacity greater 

than 20 LTD to comply with Refinery 

NSPS Ja as a means of complying with 

Refinery MACT 2. 

We have not identified any additional 

developments in practices, processes or 

control technologies for HAP from SRU 

since development of Refinery NSPS Ja. 

C. What are the results of the risk 

assessment and analyses? 

1. Inhalation Risk Assessment Results 

Table 10 of this preamble provides an 

overall summary of the results of the 

inhalation risk assessment. 

TABLE 10—PETROLEUM REFINING SOURCE SECTOR INHALATION RISK ASSESSMENT RESULTS

Maximum individual cancer risk 

(-in-1 million) a

Estimated population at 

increased risk levels of cancer 

Estimated annual 

cancer incidence 

(cases per year) 

Maximum chronic non-cancer 

TOSHI b

Maximum screening acute 

non-cancer HQ c

Actual Emissions 

60 ................................................. ≥ 1-in-1 million: 5,000,000 ...........

≥ 10-in-1 million: 100,000 ............

≥ 100-in-1 million: 0 .....................

0.3 0.9 HQREL = 5 

(Nickel Compounds). 

Allowable Emissions d

100 ............................................... ≥ 1-in-1 million: 7,000,000 e ........

≥ 10-in-1 million: Greater than 

90,000 e.

≥ 100-in-1 million: 0 .....................

0.6 1 — 

aEstimated maximum individual excess lifetime cancer risk due to HAP emissions from the source category. 

b Maximum TOSHI. The target organ with the highest TOSHI for the Petroleum Refining source sector is the thyroid system for actual emissions and the neurological system for allowable emissions. cThe maximum off-site HQ acute value of 5 is driven by emissions of nickel from CCU. See section III.A.3 of this preamble for explanation of 

acute dose-response values. Acute assessments are not performed on allowable emissions because of a lack of detailed hourly emissions data. 

However, because of the conservative nature of the actual annual to actual hourly emissions rate multiplier, allowable acute risk estimates will be 

comparable to actual acute estimates. dThe development of allowable emission estimates can be found in the memo entitled Refinery Risk Estimates for Modeled ‘‘Allowable’’ Emissions, which can be found in Docket ID Number EPA–HQ–OAR–2010–0682. ePopulation risks from allowable emissions were only calculated for the model plant emissions (REM) approach. For the 138 facilities modeled 

using the modeled plant approach the population risks greater than 10-in-1 million was estimated to be 90,000. If we consider the second approach to determining allowable emissions (combined the results of the actual and REM emissions estimates) we estimate that the allowable 

population risks greater than 10-in-1 million would be greater than 90,000 people. Further, the number of people above 1-in-1 million would also 

be higher than the 7,000,000 estimated using the REM model. 

The inhalation risk modeling 

performed to estimate risks based on 

actual emissions relied primarily on 

emissions data from the ICR, updated 

based on our quality assurance review 

as described in section III.A.1 of this 

preamble. 

The results of the chronic baseline 

inhalation cancer risk assessment 

indicate that, based on estimates of 

current actual emissions, the maximum 

individual lifetime cancer risk (MIR) 

posed by the refinery source category is 

60-in-1 million, with benzene and 

naphthalene emissions from equipment 

leaks and storage tanks accounting for 

98 percent of the MIR risk. The total 

estimated cancer incidence from 

refinery emission sources based on 

actual emission levels is 0.3 excess 

cancer cases per year or one case in 

every 3.3 years, with emissions of 

naphthalene, benzene, and 2- 

methylnaphthalene contributing 22 

percent, 21 percent and 13 percent, 

respectively, to this cancer incidence. In 

addition, we note that approximately 

100,000 people are estimated to have 

cancer risks greater than 10-in-1 million, 

and approximately 5,000,000 people are 

estimated to have risks greater than 1- 

in-1 million as a result of actual 

emissions from these source categories. 

When considering the MACT-allowable 

emissions, the maximum individual 

lifetime cancer risk is estimated to be up 

to 100-in-1 million, driven by emissions 

of benzene and naphthalene from 

refinery fugitives (e.g., storage tanks, 

equipment leaks and wastewater) and 

the estimated cancer incidence is 

estimated to be 0.6 excess cancer cases 

per year or one excess case in every 1.5 

years. Greater than 90,000 people were 

estimated to have cancer risks above 10- 

in-1 million and approximately 

7,000,000 people were estimated to have 

cancer risks above 1-in-1 million 

considering allowable emissions from 

all petroleum refineries. 

The maximum modeled chronic noncancer HI (TOSHI) value for the source 

sector based on actual emissions was 

estimated to be less than 1. When 

considering MACT-allowable emissions, 

the maximum chronic non-cancer 

TOSHI value was estimated to be about 

1. 

2. Acute Risk Results 

Our screening analysis for worst-case 

acute impacts based on actual emissions 

indicates the potential for five 

pollutants—acetaldehyde, acrolein, 

arsenic, benzene and nickel—to exceed 

an HQ value of 1, with an estimated 

worst-case maximum HQ of 5 for nickel 

based on the REL values. This REL 

occurred at a facility reporting nickel 

emissions from the FCCU vent. One 

hundred thirty-six of the 142 petroleum 

refineries had an estimated worst-case 

HQ less than or equal to 1 for all HAP; 

except for the one facility that had an 

estimated REL of 5, the remaining 5 

refineries with an REL above 1 had an 

estimated worst-case HQ less than or 

equal to 3. 

To better characterize the potential 

health risks associated with estimated 

worst-case acute exposures to HAP, and 

in response to a key recommendation 

from the SAB’s peer review of EPA’s 

RTR risk assessment methodologies, we 

examine a wider range of available acute 

health metrics than we do for our 

chronic risk assessments. This is in 

acknowledgement that there are 

generally more data gaps and 

inconsistencies in acute reference 

values than there are in chronic 

reference values. By definition, the 

acute CalEPA REL represents a healthVerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00056 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2

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33 29 CFR 1910.1028, Benzene. 

34ACGIH (2001) Benzene. In Documentation of 

the TLVs® and BEIs® with Other Worldwide 

Occupational Exposure Values. ACGIH, 1300 

Kemper Meadow Drive, Cincinnati, OH 45240 

(ISBN: 978–1–882417–74–1) and available online at 

http://www.acgih.org. 

35The ACGIH definition of a TLV–STEL states 

that ‘‘Exposures above the TLV–TWA up to the 

TLV–STEL should be less than 15 minutes, should 

occur no more than four times per day, and there 

should be at least 60 minutes between successive 

exposures in this range.’’ 

36NIOSH. Occupational Safety and Health 

Guideline for Benzene; http://www.cdc.gov/niosh/

docs/81-123/pdfs/0049.pdf. 

37Burger, J. 2002. Daily consumption of wild fish 

and game: Exposures of high end recreationists. 

International Journal of Environmental Health 

Research 12:343–354. 

38U.S. EPA. Exposure Factors Handbook 2011 

Edition (Final). U.S. Environmental Protection 

Agency, Washington, DC, EPA/600/R–09/052F, 

2011. 

protective level of exposure, with no 

risk anticipated below those levels, even 

for repeated exposures; however, the 

health risk from higher-level exposures 

is unknown. Therefore, when a CalEPA 

REL is exceeded and an AEGL–1 or 

ERPG–1 level is available (i.e., levels at 

which mild effects are anticipated in the 

general public for a single exposure), we 

have used them as a second comparative 

measure. Historically, comparisons of 

the estimated maximum off-site 1-hour 

exposure levels have not been typically 

made to occupational levels for the 

purpose of characterizing public health 

risks in RTR assessments. This is 

because occupational ceiling values are 

not generally considered protective for 

the general public since they are 

designed to protect the worker 

population (presumed healthy adults) 

for short-duration increases in exposure 

(less than 15 minutes). As a result, for 

most chemicals, the 15-minute 

occupational ceiling values are set at 

levels higher than a 1-hour AEGL–1, 

making comparisons to them irrelevant 

unless the AEGL–1 or ERPG–1 levels are 

also exceeded. Such is not the case 

when comparing the available acute 

inhalation health effect reference values 

for some of the pollutants considered in 

this analysis. 

The worst-case maximum estimated 

1-hour exposure to acetaldehyde outside 

the facility fence line for the source 

categories is 1 mg/m3. This estimated 

worst-case exposure exceeds the 1-hour 

REL by a factor of 2 (HQREL=2) and is 

well below the 1-hour AEGL–1 

(HQAEGL–1=0.01) and the ERPG–1 

(HQERPG–1=0.05). 

The worst-case maximum estimated 

1-hour exposure to acrolein outside the 

facility fence line for the source 

categories is 0.005 mg/m3. This 

estimated worst-case exposure exceeds 

the 1-hour REL by a factor of 2 

(HQREL=2) and is below the 1-hour 

AEGL–1 (HQAEGL–1=0.1) and the ERPG– 

1 (HQERPG–1=0.04). 

The worst-case maximum estimated 

1-hour exposure to nickel compounds 

outside the facility fence line for the 

source categories is 0.001 mg/m3. This 

estimated worst-case exposure exceeds 

the 1-hour REL by a factor of 5 

(HQREL=5). There are no AEGL, ERPG or 

short-term occupational values for 

nickel to use as comparison to the acute 

1-hour REL value. 

The worst-case maximum estimated 

1-hour exposure to arsenic compounds 

outside the facility fence line for the 

source categories is 0.0004 mg/m3. This 

estimated worst-case exposure exceeds 

the 1-hour REL by a factor of 2 

(HQREL=2). There are no AEGL, ERPG or 

short-term occupational values for 

arsenic to use as comparison to the 

acute 1-hour REL value. 

The maximum estimated 1-hour 

exposure to benzene outside the facility 

fence line is 2.7 mg/m3. This estimated 

exposure exceeds the REL by a factor of 

2 (HQREL=2), but is significantly below 

both the 1-hour ERPG–1 and AEGL–1 

value (HQ ERPG–1 (or AEGL–1) = 0.02). 

This exposure estimate neither exceeds 

the AEGL–1/ERPG–1 values, nor does it 

exceed workplace ceiling level 

guidelines designed to protect the 

worker population for short-duration 

exposure (less than 15 minutes) to 

benzene, as discussed below. The 

occupational short-term exposure limit 

(STEL) standard for benzene developed 

by the Occupational Safety and Health 

Administration is 16 mg/m3, ‘‘as 

averaged over any 15-minute period.’’ 33

Occupational guideline STEL for 

exposures to benzene have also been 

developed by the American Conference 

of Governmental Industrial Hygienists 

(ACGIH) 34 for less than 15 minutes 35

(ACGIH threshold limit value (TLV)– 

STEL value of 8.0 mg/m3), and by the 

National Institute for Occupational 

Safety and Health (NIOSH) 36 ‘‘for any 

15 minute period in a work day’’ 

(NIOSH REL–STEL of 3.2 mg/m3). These 

shorter duration occupational values 

indicate potential concerns regarding 

health effects at exposure levels below 

the 1-hour AEGL–1 value. 

All other HAP and facilities modeled 

had worst-case acute HQ values less 

than 1, indicating that the HAP 

emissions are believed to be without 

appreciable risk of acute health effects. 

In characterizing the potential for acute 

non-cancer risks of concern, it is 

important to remember the upward bias 

of these exposure estimates (e.g., worstcase meteorology coinciding with a 

person located at the point of maximum 

concentration during the hour) and to 

consider the results along with the 

conservative estimates used to develop 

hourly emissions as described earlier, as 

well as the screening methodology. 

Refer to the memo in the docket for this 

rulemaking (Docket ID Number EPA– 

HQ–OAR–2010–0682, Derivation of 

hourly emission rates for petroleum 

refinery emission sources used in the 

acute risk analysis) for a detailed 

description of how the hourly emissions 

were developed for this source sector. 

3. Multipathway Risk Screening Results 

Results of the worst-case Tier I 

screening analysis indicate that PB– 

HAP emissions (based on estimates of 

actual emissions) from several facilities 

in this source sector exceed the 

screening emission rates for POM 

(PAH), CDDF, mercury compounds, and 

cadmium compounds. For the 

compounds and facilities that did not 

screen out at Tier I, we conducted a Tier 

II screen. The Tier II screen replaces 

some of the assumptions used in Tier I 

with site-specific data, including the 

land use around the facilities, the 

location of fishable lakes, and local 

wind direction and speed. The Tier II 

screen continues to rely on high-end 

assumptions about consumption of local 

fish and locally grown or raised foods 

(adult female angler at 99th 

consumption for fish 37 and 90th 

percentile for consumption of locally 

grown or raised foods 38) and uses an 

assumption that the same individual 

consumes each of these foods in high 

end quantities (i.e., that an individual 

has high end ingestion rates for each 

food). The result of this analysis was the 

development of site-specific emission 

screening levels for POM, CDDF, 

mercury compounds, and cadmium 

compounds. It is important to note that, 

even with the inclusion of some sitespecific information in the Tier II 

analysis, the multi-pathway screening 

analysis is a still a very conservative, 

health-protective assessment (e.g., 

upper-bound consumption of local fish, 

locally grown, and/or raised foods) and 

in all likelihood will yield results that 

serve as an upper-bound multi-pathway 

risk associated with a facility. 

While the screening analysis is not 

designed to produce a quantitative risk 

result, the factor by which the emissions 

exceed the screening value serves as a 

rough gauge of the ‘‘upper-limit’’ risks 

we would expect from a facility. Thus, 

for example, if a facility emitted a PB– 

HAP carcinogen at a level 2 times the 

screening value, we can say with a high 

degree of confidence that the actual 

maximum cancer risks will be less than 


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2-in-1 million. Likewise, if a facility 

emitted a noncancer PB–HAP at a level 

2 times the screening level, the 

maximum noncancer risks would 

represent a HQ less than 2. The high 

degree of confidence comes from the 

fact that the screens are developed using 

the very conservative (health-protective) 

assumptions that we describe above. 

Based on the Tier II screening 

analysis, one facility emits cadmium 

compounds above the Tier II screening 

level and exceeds that level by about a 

factor of 2. Twenty-three facilities emit 

CDDF as 2,3,7,8-tetrachlorodibenzo-pdioxin toxicity equivalent (TEQ) above 

the Tier II screening level, and the 

facility with the highest emissions of 

dioxins exceeds the Tier II screening 

level by about a factor of 40. No 

facilities emit mercury compounds 

above the Tier II screening levels. Fortyfour facilities emit POM as 

benzo(a)pyrene TEQ above the Tier II 

screening level, and the facility with the 

highest emissions of POM as 

benzo(a)pyrene TEQ exceeds its 

screening level by a factor of 30. 

Polychlorinated biphenyls (PCB) are 

PB–HAP that do not currently have 

multi-pathway screening values and so 

are not evaluated for potential noninhalation risks. These HAP, however, 

are not emitted in appreciable quantities 

(0.001 tpy) from refinery operations, and 

we do not believe they contribute to 

multi-pathway risks for this source 

category. 

Results of the analysis for lead 

indicate that the maximum annual offsite ambient lead concentration was 

only 2 percent of the NAAQS for lead, 

and even if the total annual emissions 

occurred during a 3-month period, the 

maximum 3-month rolling average 

concentrations would still be less than 

8 percent of the NAAQS, indicating that 

there is no concern for multi-pathway 

risks due to lead emissions. 

4. Refined Multipathway Case Study 

To gain a better understanding of the 

uncertainty associated with the 

multipathway Tier I and II screening 

analysis, a refined multipathway case 

study using the TRIM.Fate model was 

conducted for a single petroleum 

refinery. The site, a refinery in St. John 

the Baptist Parish, Louisiana, was 

selected based upon its close proximity 

to nearby lakes and farms as well as 

having one of the highest potential 

multipathway risks for PAH based on 

the Tier II analysis. The refined analysis 

for this facility showed that the Tier II 

screen for each pollutant over-predicted 

the potential risk when compared to the 

refined analysis results. For this site, the 

Tier II screen for mercury indicated that 

mercury emissions were 3 times lower 

than the screening value, indicating a 

potential maximum HQ for mercury of 

0.3. In the refined analysis, the potential 

HQ was 0.04 or about 7 times lower 

than that predicted by the Tier II screen. 

For cadmium emissions, the Tier II 

screen for this facility indicated that 

cadmium emissions were about 20 times 

lower than the screening value, 

indicating a potential maximum HQ for 

mercury of 0.05. The results of the 

refined analysis for the selected site in 

Louisiana show a maximum cadmium 

HQ of 0.02 or about 3 times lower than 

that predicted by the Tier II screen. For 

PAH emissions, the site selected for the 

refined analysis had PAH emissions 20 

times the PAH Tier II screening value, 

indicating a potential cancer risk of 20- 

in-1 million. When the more refined 

analysis was conducted for this site, the 

potential cancer risks were estimated to 

be 2-in-1 million or about 14 times 

lower than predicted by the Tier II 

analysis. Finally, for the facility selected 

for the refined assessment, the 

emissions of CDDF as 2,3,7,8- 

tetrachlorodibenzo-p-dioxin TEQ are 5 

times higher than the dioxin Tier II 

screening value, indicating a potential 

maximum cancer risk of 5–in-1 million. 

In the refined assessment, the cancer 

risk from dioxins was estimated to be 2- 

in-1 million, about one-third of the 

estimate from the Tier II screen. 

Overall, the refined analysis predicts 

a potential lifetime cancer risk of 4-in1 million to the maximum most exposed 

individual (MIR). The non-cancer HQ is 

predicted to be well below 1 for all 

target organs. The chronic inhalation 

cancer risk assessment estimated 

inhalation cancer risk around this same 

facility to be approximately 10-in-1 

million, due in large part to emissions 

of naphthalene and 2- 

methylnaphthalene (both nonpersistent, bioaccumulative, and toxic 

(PBT) HAP). Thus, although highly 

unlikely, if around this facility the 

person with the highest chronic 

inhalation cancer risk is also the same 

person with the highest individual 

multipathway cancer risk, then the 

combined, worst-case MIR for that 

facility could theoretically be 10-in-1 

million (risk estimates are expressed as 

1 significant figure). 

While this refined assessment was 

performed on only a single facility, the 

results of this single refined analysis 

indicate that if refined analyses were 

performed for other sites, the risk 

estimates would consistently be lower 

than those estimated by the Tier II 

analysis. In addition, the risks predicted 

by the multipathway analyses at most 

facilities are considerably lower than 

the risk estimates predicted by the 

inhalation assessment, indicating that 

the inhalation risk results are in all 

likelihood the primary factor in our 

residual risk determination for this 

source category. 

Further details on the site-specific 

case study can be found in Appendix 10 

of the Draft Residual Risk Assessment 

for the Petroleum Refining Source 

Sector, which is available in Docket ID 

Number EPA–HQ–OAR–2010–0682. 

5. Environmental Risk Screening Results 

As described in the Draft Residual 

Risk Assessment for the Petroleum 

Refining Source Sector, which is 

available in Docket ID Number EPA– 

HQ–OAR–2010–0682, we conducted an 

environmental risk screening 

assessment for the petroleum refineries 

source category. In the Tier I screening 

analysis for PB–HAP (other than lead, 

which was evaluated differently, as 

noted in section III.A.6 of this 

preamble), the individual modeled Tier 

I concentrations for one facility in the 

source category exceeded some of the 

ecological benchmarks for mercury. In 

addition, Tier I modeled concentrations 

for four facilities exceeded sediment 

and soil ecological benchmarks for PAH. 

Therefore, we conducted a Tier II 

assessment. 

In the Tier II screening analysis for 

PB–HAP, none of the individual 

modeled concentrations for any facility 

in the source category exceeded any of 

the ecological benchmarks (either the 

LOAEL or NOAEL). 

For lead compounds, we did not 

estimate any exceedances of the 

secondary lead NAAQS. Therefore, we 

did not conduct further assessment for 

lead compounds. 

For acid gases, the average modeled 

concentration around each facility (i.e., 

the average concentration of all off-site 

data points in the modeling domain) did 

not exceed any ecological benchmark. In 

addition, for both HCL and HF, each 

individual concentration (i.e., each offsite data point in the modeling domain) 

was below the ecological benchmarks 

for all facilities. 

6. Facility-Wide Risk Results 

Table 11 of this preamble displays the 

results of the facility-wide risk 

assessment. 


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TABLE 11—PETROLEUM REFINING FACILITY-WIDE RISK ASSESSMENT RESULTS

Number of facilities analyzed .......................................................................................................................................................... 142 

Cancer Risk: 

Estimated maximum facility-wide individual cancer risk (-in-1 million) .................................................................................... 70 

Number of facilities with estimated facility-wide individual cancer risk of 10-in-1 million or more .......................................... 54 

Number of petroleum refining operations contributing 50 percent or more to facility-wide individual cancer risk of 10-in-1 

million or more ...................................................................................................................................................................... 50 

Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more ............................................................. 115 

Number of petroleum refining operations contributing 50 percent or more to facility-wide individual cancer risk of 1-in-1 

million or more ...................................................................................................................................................................... 107 

Chronic Non-cancer Risk: 

Maximum facility-wide chronic non-cancer TOSHI ......................................................................................................................... 4 

Number of facilities with facility-wide maximum non-cancer TOSHI greater than 1 ............................................................... 5 

Number of petroleum refining operations contributing 50 percent or more to facility-wide maximum non-cancer TOSHI of 

1 or more .............................................................................................................................................................................. 0 

The maximum individual cancer 

whole-facility risk from all HAP 

emissions at any petroleum refinery is 

estimated to be 70-in-1 million, based 

on actual emissions. Of the 142 facilities 

included in this analysis, 54 have 

facility-wide maximum individual 

cancer risks of 10-in-1 million or 

greater. At the majority of these facilities 

(50 of 54), the petroleum refinery 

operations account for over 50 percent 

of the risk. 

There are 115 facilities with facilitywide maximum individual cancer risks 

of 1-in-1 million or greater. At the 

majority of these facilities (107 of 115), 

the petroleum refinery operations 

account for over 50 percent of the risk. 

The facility-wide maximum individual 

chronic non-cancer TOSHI is estimated 

to be 4, based on actual emissions. Of 

the 142 refineries included in this 

analysis, five have a TOSHI value 

greater than 1. The highest non-cancer 

TOSHI results from emissions of 

chlorine from cooling towers. In each 

case, the petroleum refinery operations 

account for less than 20 percent of the 

TOSHI values greater than 1. 

Additional detail regarding the 

methodology and the results of the 

facility-wide analyses are included in 

the risk assessment documentation 

(Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector), 

which is available in the docket for this 

rulemaking (Docket ID Number EPA– 

HQ–OAR–2010–0682). 

7. What demographic groups might 

benefit from this regulation? 

To examine the potential for any 

environmental justice issues that might 

be associated with the source categories, 

we performed a demographic analysis of 

the population close to the facilities. In 

this analysis, we evaluated the 

distribution of HAP-related cancer and 

non-cancer risks from petroleum 

refineries across different social, 

demographic, and economic groups 

within the populations living near 

facilities identified as having the highest 

risks. The methodology and the results 

of the demographic analyses are 

included in a technical report, Draft 

Risk and Technology Review—Analysis 

of Socio-Economic Factors for 

Populations Living Near Petroleum 

Refineries, available in the docket for 

this action (Docket ID Number EPA– 

HQ–OAR–2010–0682). 

The results of the demographic 

analysis are summarized in Table 12 of 

this preamble. These results, for various 

demographic groups, are based on the 

estimated risks from actual emissions 

levels for the population living within 

50 km of the facilities. 

TABLE 12—PETROLEUM REFINING DEMOGRAPHIC RISK ANALYSIS RESULTS

Nationwide 

Population with 

cancer risk at or 

above 1-in-1 

million 

Population with 

chronic hazard 

index above 1 

Total Population ......................................................................................................... 312,861,265 5,204,234 0 

Race by Percent 

White .......................................................................................................................... 72 50 0 

All Other Races ......................................................................................................... 28 50 0

Race by Percent 

White .......................................................................................................................... 72 50 0 

African American ....................................................................................................... 13 28 0 

Native American ........................................................................................................ 1 1 0 

Other and Multiracial ................................................................................................. 14 21 0 

Ethnicity by Percent 

Hispanic ..................................................................................................................... 17 29 0 

Non-Hispanic ............................................................................................................. 83 71 0 

Income by Percent 

Below Poverty Level .................................................................................................. 14 21 0 

Above Poverty Level .................................................................................................. 86 79 0 


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39 1-in-10 thousand is equivalent to 100-in-1 

million. The EPA currently describes cancer risks 

as ‘n-in-1 million’. 

TABLE 12—PETROLEUM REFINING DEMOGRAPHIC RISK ANALYSIS RESULTS—Continued 

Nationwide 

Population with 

cancer risk at or 

above 1-in-1 

million 

Population with 

chronic hazard 

index above 1 

Education by Percent 

Over 25 and without High School Diploma ............................................................... 15 23 0 

Over 25 and with a High School Diploma ................................................................. 85 77 0 

The results of the demographic 

analysis indicate that emissions from 

petroleum refineries expose 

approximately 5,000,000 people to a 

cancer risk at or above 1-in-1 million. 

Implementation of the provisions 

included in this proposal is expected to 

reduce the number of people estimated 

to have a cancer risk greater than 1-in1 million due to HAP emissions from 

these sources from 5,000,000 people to 

about 4,000,000. Our analysis of the 

demographics of the population within 

50 km of the facilities indicates 

potential disparities in certain 

demographic groups, including the 

African American, Other and 

Multiracial, Hispanic, Below the 

Poverty Level, and Over 25 without a 

High School Diploma. The population 

living within 50 km of the 142 

petroleum refineries has a higher 

percentage of minority, lower income 

and lower education persons when 

compared to the nationwide percentages 

of those groups. For example, 50 percent 

are in one or more minority 

demographic group, compared to 28 

percent nationwide. As noted above, 

approximately 5,000,000 people 

currently living within 50 km of a 

petroleum refinery have a cancer risk 

greater than 1-in-1 million. We would 

expect that half of those people are in 

one or more minority demographic 

groups. 

Because minority groups make up a 

large portion of the population living 

near refineries, as compared with their 

representation nationwide, those groups 

would similarly see a greater benefit 

from the implementation of the controls 

proposed in this rule, if finalized. For 

example, we estimate that after 

implementation of the controls 

proposed in this action (i.e., postcontrols), about 1,000,000 fewer people 

will be exposed to cancer risks greater 

than 1-in-1 million (i.e., 4,000,000 

people). Further, we estimate that 

approximately 500,000 people no longer 

exposed to a cancer risk greater than 1- 

in-1 million would be in a minority 

demographic group. The post-control 

risk estimates are discussed further in 

section III.A.5 of this preamble. 

Although the EPA’s proposed 

fenceline monitoring requirement is 

intended to ensure that owners and 

operators monitor, manage and, if 

necessary, reduce fugitive emissions of 

HAP, we also expect the collected 

fenceline data to help the EPA 

understand and identify emissions of 

benzene and other fugitive emissions 

that are impacting communities in close 

proximity to the facility. While 

currently-available emissions and 

monitoring data do not indicate that 

risks to nearby populations are 

unacceptable (see section IV.D.1 of this 

preamble), we recognize that the 

collection of additional data through 

routine fenceline monitoring can 

provide important information to 

communities concerned with potential 

risks associated with emissions from 

fugitive sources. We note that the data 

we are proposing to collect on a 

semiannual basis may include 

exceedances of the fenceline action 

level that a facility could have 

addressed or could still be actively 

addressing at the time of the report. As 

noted in section IV.B.1.h of this 

preamble, directly monitoring fugitive 

emissions from each potential emissions 

source at the facility is impractical. 

Fenceline monitoring offers a costeffective alternative for monitoring 

fugitive emissions from the entire 

facility. The EPA’s proposal to require 

the electronic reporting of fenceline 

monitoring data on a semiannual basis 

will ensure that communities have 

access to data on benzene levels near 

the facility, which is directly relevant to 

the potential health risks posed by the 

facility. The proposed requirements for 

fenceline monitoring and corrective 

action when fugitive emissions from a 

facility exceed the specified corrective 

action level will serve as an important 

backstop to protect the health of the 

populations surrounding the facility, 

including minority and low-income 

populations. 

D. What are our proposed decisions 

regarding risk acceptability, ample 

margin of safety and adverse 

environmental effects? 

1. Risk Acceptability 

As noted in section II.A.1 of this 

preamble, the EPA sets standards under 

CAA section 112(f)(2) using ‘‘a two-step 

standard-setting approach, with an 

analytical first step to determine an 

‘acceptable risk’ that considers all 

health information, including risk 

estimation uncertainty, and includes a 

presumptive limit on maximum 

individual lifetime risk (MIR) of 

approximately 1 in 10 thousand.[39] ’’ 

(54 FR 38045, September 14, 1989). 

In this proposal, we estimate risks 

based on actual emissions from 

petroleum refineries. We also estimate 

risks from allowable emissions; as 

discussed earlier, we consider our 

analysis of risk from allowable 

emissions to be conservative and as 

such to represent an upper bound 

estimate on risk from emissions allowed 

under the current MACT standards for 

the source categories. 

a. Estimated Risks From Actual 

Emissions 

The baseline inhalation cancer risk to 

the individual most exposed to 

emissions from sources regulated by 

Refinery MACT 1 and 2 is 60-in-1 

million based on actual emissions. The 

estimated incidence of cancer due to 

inhalation exposures is 0.3 excess 

cancer cases per year, or 1 case every 3.3 

years. Approximately 5,000,000 people 

face an increased cancer risk greater 

than 1-in-1 million due to inhalation 

exposure to actual HAP emissions from 

these source categories, and 

approximately 100,000 people face an 

increased risk greater than 10-in-1 

million and up to 60-in-1 million. The 

agency estimates that the maximum 

chronic non-cancer TOSHI from 

inhalation exposure is 0.9 due to actual 

emissions of HCN from FCCU. 


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The screening assessment of worstcase acute inhalation impacts from 

actual emissions indicates the potential 

for five pollutants—nickel, arsenic, 

acrolein, benzene and acetaldehyde—to 

exceed an HQ value of 1, with an 

estimated worst-case maximum HQ of 5 

for nickel based on the REL values. One 

hundred thirty-six of the 142 petroleum 

refineries had an estimated worst-case 

HQ less than or equal to 1 for all HAP. 

One facility had an estimated worst-case 

maximum HQ of 5 and the remaining 

five refineries with an HQ above 1 had 

an estimated worst-case HQ less than or 

equal to 3. Considering the conservative, 

health-protective nature of the approach 

that is used to develop these acute 

estimates, it is highly unlikely that an 

individual would have an acute 

exposure above the REL. Specifically, 

the analysis is based on the assumption 

that worst-case emissions and 

meteorology would coincide with a 

person being at this exact location for a 

period of time long enough to have an 

exposure level above the conservative 

REL value. 

The Tier II multipathway screening 

analysis of actual emissions indicated 

the potential for PAH emissions that are 

about 30 times the screening level for 

cancer, dioxin and furans emissions that 

are about 40 times the cancer screening 

level and cadmium emissions that are 

about 2 times the screening level for 

non-cancer health effects. No facility’s 

emissions were above the screening 

level for mercury. As we note above, the 

Tier II multipathway screen is 

conservative in that it incorporates 

many health-protective assumptions. 

For example, we choose inputs from the 

upper end of the range of possible 

values for the influential parameters 

used in the Tier II screen and we 

assume that the exposed individual 

exhibits ingestion behavior that would 

lead to a high total exposure. A Tier II 

exceedance cannot be equated with a 

risk value or a HQ or HI. Rather, it 

represents a high-end estimate of what 

the risk or hazard may be. For example, 

an exceedance of 2 for a non-carcinogen 

can be interpreted to mean that we have 

high confidence that the HI would be 

lower than 2. Similarly, an exceedance 

of 30 for a carcinogen means that we 

have high confidence that the risk is 

lower than 30-in-1-million. Our 

confidence comes from the 

conservative, or health-protective, 

assumptions that are used in the Tier II 

screen. 

The refined analysis that we 

conducted for a specific facility showed 

that the Tier II screen for each pollutant 

over-predicted the potential risk when 

compared to the refined analysis results. 

That refined multipathway assessment 

showed that the Tier II screen resulted 

in estimated risks that are higher than 

the risks estimated by the refined 

analysis by 14 times for PAH, 3 times 

for dioxins and furans, and 3 times for 

cadmium. The refined assessment 

results indicate that the multipathway 

risks are considerably lower than the 

estimated inhalation risks, and our 

refined multipathway analysis indicates 

that multipathway risks are low enough 

that, while they are considered in our 

proposed decisions, they do not weigh 

heavily into those decisions because 

risks for the source category are driven 

by inhalation. 

b. Estimated Risks From Allowable 

Emissions 

We estimate that the baseline 

inhalation cancer risk to the individual 

most exposed to emissions from sources 

regulated by Refinery MACT 1 and 2 is 

as high as 100-in-1 million based on 

allowable emissions. The EPA estimates 

that the incidence of cancer due to 

inhalation exposures could be as high as 

0.6 excess cancer cases per year, or 1 

case approximately every 1.5 years. 

About 7,000,000 people face an 

increased cancer risk greater than 1-in1 million due to inhalation exposure to 

allowable HAP emissions from these 

source categories, and greater than 

90,000 people face an increased risk 

greater than 10-in-1 million, and as high 

as 100-in-1 million. Further, we 

estimate that the maximum chronic 

non-cancer TOSHI from inhalation 

exposure values at all refineries is less 

than 1 based on allowable emissions. 

The baseline risks summarized above 

do not account for additional risk 

reductions that we anticipate due to the 

MACT standards or the technology 

review requirements we are proposing 

in this action. 

c. Acceptability Determination 

In determining whether risk is 

acceptable, the EPA considered all 

available health information and risk 

estimation uncertainty as described 

above. As noted above, the agency 

estimated risk from actual and allowable 

emissions. While there are uncertainties 

associated with both the actual and 

allowable emissions, we consider the 

allowable emissions to be an upper 

bound, based on the conservative 

methods we used to calculate allowable 

emissions. 

The results indicate that both the 

actual and allowable inhalation cancer 

risks to the individual most exposed are 

no greater than approximately 100–in-1 

million, which is the presumptive limit 

of acceptability. The MIR based on 

actual emissions is 60-in-1 million, 

approximately 60 percent of the 

presumptive limit. Based on the results 

of the refined site-specific multipathway 

analysis summarized above and 

described in section IV.C.3 of this 

preamble, we also conclude that the 

ingestion cancer risk to the individual 

most exposed is significantly less than 

100-in-1 million. In addition, the 

maximum chronic non-cancer TOSHI 

due to inhalation exposures is less than 

1, and our refined multipathway 

analysis indicates that non-cancer 

ingestion risks are estimated to be less 

than non-cancer risk from inhalation. 

Finally, the evaluation of acute noncancer risks was very conservative, and 

showed acute risks below a level of 

concern. 

In determining risk acceptability, we 

also evaluated population impacts 

because of the large number of people 

living near facilities in the source 

category. The analysis indicates that 

there are approximately 5 million 

people exposed to actual emissions 

resulting in a cancer risk greater than 1- 

in-1 million, and a substantially smaller 

number of people (100,000) are exposed 

to a cancer risk of greater than 10-in-1 

million but less than 100-in-1 million 

(with a maximum risk of 60-in-1 

million). The inhalation cancer 

incidence is approximately one case in 

every 3 years based on actual emissions. 

More detail on this risk analysis is 

presented in section IV.C and 

summarized in Tables 10 and 11 of this 

preamble. The results of the 

demographic analysis for petroleum 

refineries indicate that a greater 

proportion of certain minority groups 

and low-income populations live near 

refineries than the national 

demographic profile. More detail on 

these population impacts is presented in 

section IV.C.7 of this preamble. We did 

not identify any sensitivity to pollutants 

emitted from these source categories 

particular to minority and low income 

populations. Considering the above 

information, we propose that the risks 

remaining after implementation of the 

existing NESHAP for the Refinery 

MACT 1 and 2 source categories is 

acceptable. 

We also note that the estimated 

baseline risks for the refineries source 

categories include risks from emissions 

from DCU, which are a previously 

unregulated emission source. As 

discussed in section IV.A. of this 

preamble, we are proposing new MACT 

standards for these sources that would 

reduce emissions of HAP by 850 tpy. 

We estimate that these new standards 

would not affect the MIR, but would 


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36940 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

40As described in the memorandum entitled 

Refinery Emissions and Risk Estimates for Modeled 

‘‘Allowable’’ Emissions, available in Docket EPA– 

HQ–OAR–2010–0682, the use of model plants and 

post-processing was for the purpose of ensuring that 

our analysis would provide a conservative estimate 

of actual emissions and thus a conservative estimate 

of risk. 

reduce the source category cancer 

incidence by 15 percent. 

We solicit comment on all aspects of 

our proposed acceptability 

determination. We note that while we 

are proposing that the risks estimated 

from actual and allowable emissions are 

acceptable, the risks based on allowable 

emissions are at the presumptive limit 

of acceptable risk. Furthermore, a 

significant number of people live in 

relative proximity to refineries across 

the country, and therefore a large 

population is exposed to risks greater 

than 1-in-1 million. In particular, we 

solicit comment on the methodology 

used to estimate allowable emissions. 

As noted above, we consider the 

allowable emissions to be an upper 

bound estimate based on the 

conservative methods used to calculate 

such emissions. We recognize, however, 

that some of the health information 

concerning allowable emissions 

arguably borders on the edge of 

acceptability. Specifically, the analysis 

of allowable emissions resulted in a MIR 

of 100-in-1 million, which is the 

presumptive limit of acceptability, a 

large number of people (7,000,000) 

estimated to be exposed at a cancer risk 

above 1-in-1 million, and an estimated 

high cancer incidence (one case 

approximately every 1.5 years). 

Although we believe that our allowable 

emissions represent an upper end 

estimate, we nonetheless solicit 

comment on whether the health 

information currently before the Agency 

should be deemed unacceptable. We 

also solicit comment on whether our 

allowable emissions analysis reflects a 

reasonable estimate of emissions 

allowed under the current MACT 

standards. Lastly, we solicit comment 

on the acceptability of risk considering 

individuals’ potential cumulative 

inhalation and ingestion pathway 

exposure. Please provide comments and 

data supporting your position. Such 

information will aid the Agency to make 

an informed decision on risk 

acceptability as it moves forward with 

this rulemaking. 

2. Ample Margin of Safety 

We next considered whether the 

existing MACT standards provide an 

ample margin of safety to protect public 

health. In addition to considering all of 

the health risks and other health 

information considered in the risk 

acceptability determination, in the 

ample margin of safety analysis we 

evaluated the cost and feasibility of 

available control technologies and other 

measures that could be applied in these 

source categories to further reduce the 

risks due to emissions of HAP. For 

purposes of the ample margin of safety 

analysis, we evaluated the changes in 

risk that would occur through adoption 

of a specific technology by looking at 

the changes to the risk due to actual 

emissions. Due to the nature of the 

allowable risk analysis, which is based 

on model plants and post processing to 

combine risk results,40 we did not 

evaluate the risk reductions resulting 

from reducing allowable emissions at 

individual emission sources. Such an 

approach would require an 

unnecessarily complex analysis that 

would not provide any more useful 

information than the analysis we 

undertook using actual emissions. We 

note that while we did not conduct a 

specific analysis for allowable 

emissions, it is reasonable to expect 

reductions in risk similar to those for 

actual emissions. 

As noted in our discussion of the 

technology review in section IV.B of this 

preamble, we identified a number of 

developments in practices, processes or 

control technologies for reducing HAP 

emissions from petroleum refinery 

processes. As part of the risk review, we 

evaluated these developments to 

determine if any of them could reduce 

risks and whether it is necessary to 

require any of these developments to 

provide an ample margin of safety to 

protect public health. 

We evaluated the health information 

and control options for all of the 

emission sources located at refineries, 

including: Storage vessels, equipment 

leaks, gasoline loading racks, marine 

vessel loading operations, cooling 

towers/heat exchange systems, 

wastewater collection and treatment, 

FCCU, flares, miscellaneous process 

vents, CRU and SRU. For each of these 

sources, we considered chronic cancer 

and non-cancer risk metrics as well as 

acute risk. Regarding our ample margin 

of safety analyses for chronic noncancer risk for the various emission 

sources, we note that the baseline 

TOSHIs are less than 1 for the entire 

source category and considerably less 

than 1 for all of the emission sources 

except for the FCCU (which had an 

TOSHI of 0.9). Therefore, we did not 

quantitatively evaluate reductions in the 

chronic non-cancer TOSHI for sources 

other than FCCU in the ample margin of 

safety analysis. Regarding our ample 

margin of safety analyses for acute risk 

for all of the various emission sources, 

we note that our analyses did not 

identify acute risks at a level of concern 

and, therefore, we did not quantitatively 

evaluate reductions in the acute HQ 

values for each individual emission 

source in the ample margin of safety 

analysis. Accordingly, the following 

paragraphs focus on cancer risk in the 

determination of whether the standards 

provide an ample margin of safety to 

protect public health. 

For storage vessels, as discussed in 

section IV.B of this preamble, we 

identified and evaluated three control 

options. Under the technology review, 

we determined that two of the options, 

which we call options 1 and 2, are cost 

effective. We are proposing option 2, 

which includes all of the requirements 

of option 1, as part of the technology 

review. The option 2 controls that we 

are proposing under the technology 

review would result in approximately 

910 tpy reduction in HAP (a 40-percent 

reduction from this emission source). As 

described in section IV.B of this 

preamble, not only are these controls 

cost effective, but we estimate a net cost 

savings because the emission reductions 

translate into reduced product loss. 

These controls would reduce the cancer 

risk to the individual most exposed 

from 60-in-1 million to 50-in-1 million 

based on actual emissions at the facility 

where storage tank emissions were 

driving the risk. However, the MIR 

remains unchanged for the refinery 

source categories, at 60-in 1-million, 

because the facility with the next 

highest cancer risk is 60-in-1 million 

and this risk is driven by another 

emission source. The option 2 controls 

also would reduce cancer incidence by 

approximately 2 percent. Finally, we 

estimate that the option 2 controls 

reduce the number of people with a 

cancer risk greater than 10-in-1 million 

storage tanks from 3,000 to 60 and 

reduce the number of people with a 

cancer risk greater than 1-in-1 million 

from storage tanks from 140,000 to 

72,000. Since these controls reduce 

cancer incidence, and reduce the 

number of people exposed to cancer 

risks greater than 1-in-10 million and 1- 

in-1 million from storage tank 

emissions, and are cost effective, we 

propose that these controls are 

necessary to provide an ample margin of 

safety to protect public health. We also 

evaluated one additional control option 

for storage vessels, option 3, which 

incorporated both options 1 and 2 along 

with additional monitoring 

requirements. We estimate incremental 

HAP emission reductions (beyond those 

provided by option 2) of 90 tpy. The 


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incremental cost effectiveness for option 

3 exceeds $60,000 per ton, which we do 

not consider cost effective. In addition, 

the option 3 controls do not result in 

quantifiable reductions in the cancer 

risk to the individual most exposed or 

the cancer incidence beyond the 

reductions estimated for the option 2 

controls. For these reasons, we propose 

that it is not necessary to require the 

option 3 controls in order to provide an 

ample margin of safety to protect public 

health. 

For equipment leaks, we identified 

and evaluated three control options 

discussed previously in the technology 

review section of this preamble (section 

IV.B). These options are: 

• Option 1—monitoring and repair at 

lower leak definitions; 

• Option 2—applying monitoring and 

repair requirements to connectors; and 

• Option 3—optical gas imaging and 

repair. 

We estimate that these three 

independent control options reduce 

industry-wide emissions of organic HAP 

by 24 tpy, 86 tpy, and 24 tpy, 

respectively. We estimate that none of 

the control options would reduce the 

risk to the individual most exposed. We 

also estimate that the cancer incidence 

would not change perceptively if these 

controls were required. Finally, we 

estimate that the control options do not 

reduce the number of people with a 

cancer risk greater than 10-in-1 million 

or the number of people with a cancer 

risk greater than 1-in-1 million. As 

discussed above, the available control 

options for equipment leaks do not 

provide quantifiable risk reductions 

and, therefore, we propose that these 

controls are not necessary to provide an 

ample margin of safety. 

For gasoline loading racks, we 

identified and evaluated one control 

option discussed previously in the 

technology review section of this 

preamble (section IV.B). As discussed 

earlier, this option is a new 

development that results in emissions 

that are higher than the current level 

required under Refinery MACT 1. Since 

we estimate that no emission reductions 

would result from this new technology 

and thus no reduction in risk, we 

propose that this control option is not 

necessary to provide an ample margin of 

safety. 

For marine vessel loading operations, 

we identified and evaluated two control 

options discussed previously in the 

technology review section of this 

preamble (section IV.B). The first option 

would be to require submerged fill for 

small and offshore marine vessel 

loading operations. Based on actual 

emissions, we project no HAP emission 

reductions for this option, as all marine 

vessels that are used to transport bulk 

refinery liquids are expected to already 

have the required submerged fill pipes. 

Accordingly, we do not project any 

changes in risk. While we are proposing 

this option under the technology 

review, because the option is not 

projected to reduce emissions or risk, 

we propose that a submerged loading 

requirement is not necessary to provide 

an ample margin of safety. We also 

identified and evaluated the use of addon controls for gasoline loading at small 

marine vessel loading operations. In the 

technology review, we rejected this 

control option because the cost 

effectiveness exceeded $70,000 ton of 

HAP reduced. We estimate that this 

option would not result in quantifiable 

changes to any of the risk metrics. 

Because add-on controls would not 

result in quantifiable risk reductions 

and we do not consider the controls to 

be cost effective, we are proposing that 

add-on controls for gasoline loading at 

small marine vessel loading operations 

are not necessary to provide an ample 

margin of safety. 

For cooling towers and heat 

exchangers, we did not identify as part 

of our technology review any 

developments in processes, practices or 

controls beyond those that we 

considered in our beyond-the-floor 

analysis at the time we set the MACT 

standards. We note that we issued 

MACT standards for heat exchange 

systems in a final rule on October 28, 

2009 (74 FR 55686), but existing sources 

were not required to comply until 

October 29, 2012. As a result, the 

reductions were not reflected in the 

inventories submitted in response to the 

ICR for refineries and therefore were not 

included in our risk analysis based on 

actual emissions. We estimate that these 

MACT standards will result in an 

industry-wide reduction of over 600 

tons HAP per year (or 85 percent). The 

projected contribution to risk associated 

with cooling tower emissions after 

implementation of these MACT 

standards for heat exchange systems is 

approximately 1 percent. Because we 

did not identify any control options 

beyond those required by the current 

standards for cooling towers and heat 

exchange systems, we are proposing that 

additional controls for these systems are 

not necessary to provide an ample 

margin of safety. 

For wastewater collection and 

treatment systems, we identified and 

evaluated three options for reducing 

emissions. We estimate implementing 

these independent control options 

would result in emission reductions of 

158 tpy (4 percent), 549 tpy (15 

percent), and 929 tpy (25 percent), 

respectively. None of the control 

options would reduce the cancer risk to 

the individual most exposed from 60-in1 million. Option 1 would reduce the 

cancer incidence by less than 1 percent, 

and we expect any reduction in cancer 

incidence that would result from 

options 2 or 3 to be small because this 

source accounts for about 10 percent of 

the cancer incidence from refineries as 

a whole and the most stringent control 

option would reduce emissions from 

these source by only 25 percent. Finally, 

we estimate that control option 1 would 

not reduce the number of people with 

a cancer risk greater than 10-in-1 

million or the number of people with a 

cancer risk greater than 1-in-1 million. 

We expect any changes to the number 

of people with a cancer risk greater than 

1-in-1 million from implementation of 

options 2 or 3 to be small for the same 

reasons mentioned above for cancer 

incidence. We estimate the cost 

effectiveness of these options to be 

$26,600 per ton, $52,100 per ton, and 

$54,500 per ton of organic HAP 

reduced, and we do not consider any of 

these options to be cost effective. 

Because of the very small reductions in 

risk and the lack of cost-effective control 

options, we propose that these controls 

are not necessary to provide an ample 

margin of safety. 

For FCCU, we did not identify any 

developments in processes, practices or 

control technologies for organic HAP. 

For inorganic HAP from FCCU, in the 

technology review, we identified and 

evaluated one control option for an HCN 

emissions limit and one control option 

for a PM emissions limit. The PM limit 

was adopted for new sources in Refinery 

NSPS Ja as part of our review of 

Refinery NSPS J. We considered the 

costs and emission reductions 

associated with requiring existing 

sources to meet the new source level for 

PM under Refinery NSPS Ja (i.e., 0.5 g 

PM/kg of coke burn-off rather than 

1.0 g PM/kg). As indicated in our 

promulgation of Refinery NSPS Ja, the 

cost effectiveness of lowering the PM 

limit for existing sources to the level we 

are requiring for new sources was 

projected to be $21,000 per ton of PM 

reduced (see 73 FR 35845, June 24, 

2008). Based on the typical metal HAP 

concentration in PM from FCCU, the 

cost effectiveness of this option for HAP 

metals is approximately $1 million per 

ton of HAP reduced. We estimate that 

this control option would not reduce the 

cancer risk to the individual most 

exposed, would not change the cancer 

incidence, and would not change the 

number of people with estimated cancer 


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risk greater than 1-in-1 million or 10-in1 million. For the HCN emissions limit, 

we evaluated the costs of controlling 

HCN using combustion controls in 

combination with SCR. The cost 

effectiveness of this option was 

approximately $9,000 per ton of HCN. 

This control option would reduce the 

non-cancer HI from 0.9 to 0.8 and would 

not change any of the cancer risk 

metrics. Based on the cost effectiveness 

of these options and the limited 

reduction in cancer and non-cancer risk 

(the non-cancer risk is below a level of 

concern based on the existing 

standards), we propose that additional 

controls for FCCU are not necessary to 

provide an ample margin of safety. 

Flares are used as APCD to control 

emissions from several emission sources 

covered by Refinery MACT 1 and 2. In 

this proposed rule, under CAA sections 

112(d)(2) and (3), we are proposing 

operating and monitoring requirements 

to ensure flares achieve the 98-percent 

HAP destruction efficiency identified as 

the MACT Floor in the initial MACT 

rulemaking in 1995. Flares are critical 

safety devices that effectively reduce 

emissions during startup, shutdown, 

and process upsets or malfunctions. In 

most cases, flares are the only means by 

which emissions from pressure relief 

devices can be controlled. Thus, we find 

that properly-functioning flares act to 

reduce HAP emissions, and thereby risk, 

from petroleum refinery operations. The 

changes to the flare requirements that 

we are proposing under CAA sections 

112(d)(2) and (3) will result in sources 

meeting the level required by the 

original standards, and we did not 

identify any control options that would 

further reduce the HAP emissions from 

flares. Therefore, we are proposing that 

additional controls for flares are not 

necessary to provide an ample margin of 

safety. 

For the remaining emission sources 

within the Refinery MACT 1 and 

Refinery MACT 2 source categories, 

including miscellaneous process vents, 

CRU, and SRU, we did not identify any 

developments in processes practices 

and control technologies. Therefore, we 

are proposing that additional controls 

for these three Refinery MACT 1 and 2 

emission sources are not necessary to 

provide an ample margin of safety. 

In summary, we propose that the 

original Refinery MACT 1 and 2 MACT 

standards, along with the proposed 

requirements for storage vessels 

described above, provide an ample 

margin of safety to protect public health. 

We are specifically requesting comment 

on whether there are additional control 

measures for emission sources subject to 

Refinery MACT 1 and Refinery MACT 2 

that are necessary to provide an ample 

margin of safety to protect public health. 

In particular, we are requesting that 

states identify any controls they have 

already required for these facilities, 

controls they are currently considering, 

or other controls of which they may be 

aware. 

While not part of our decisions 

regarding residual risk, we note that 

DCU are an important emission source 

with respect to risk from refineries. As 

described in section IV.A of this 

preamble, we are proposing new MACT 

standards under CAA sections 112(d)(2) 

and (3) for DCU. For informational 

purposes, we also looked at the risk 

reductions that would result from 

implementation of those standards. We 

estimate no reduction in the cancer risk 

to the individual most exposed and a 

decrease in cancer incidence of 0.05 

cases per year, or approximately 15 

percent. While our decisions on risk 

acceptability and ample margin of safety 

are supported even in the absence of 

these reductions, if we finalize the 

proposed requirements for DCU, they 

would further strengthen our 

conclusions that the standards provide 

an ample margin of safety to protect 

public health. 

3. Adverse Environmental Effects 

We conducted an environmental risk 

screening assessment for the petroleum 

refineries source category for lead, 

mercury, cadmium, PAH, dioxins and 

furans, HF, and HCl. For mercury, 

cadmium, PAH, and dioxins and furans, 

none of the individual modeled 

concentrations for any facility in the 

source category exceeded any of the Tier 

II ecological benchmarks (either the 

LOAEL or NOAEL). For lead, we did not 

estimate any exceedances of the 

secondary lead NAAQS. For HF and 

HCl, the average modeled concentration 

around each facility (i.e., the average 

concentration of all off-site data points 

in the modeling domain) did not exceed 

any ecological benchmark. Based on 

these results, EPA proposes that it is not 

necessary to set a more stringent 

standard to prevent, taking into 

consideration costs, energy, safety, and 

other relevant factors, an adverse 

environmental effect. 

E. What other actions are we proposing? 

We are proposing the following 

changes to Refinery MACT 1 and 2 as 

described below: (1) Revising the SSM 

provisions in order to ensure that the 

subparts are consistent with the court 

decision in Sierra Club v. EPA, 551 F. 

3d 1019 (D.C. Cir. 2008), which vacated 

two provisions that exempted sources 

from the requirement to comply with 

otherwise applicable section 112(d) 

emission standards during periods of 

SSM; (2) proposing to clarify 

requirements related to open-ended 

valves or lines; (3) adding electronic 

reporting requirements in Refinery 

MACT 1 and 2; and (4) updating the 

General Provisions cross-reference 

tables. 

1. SSM 

In its 2008 decision in Sierra Club v. 

EPA, 551 F.3d 1019 (D.C. Cir. 2008), the 

United States Court of Appeals for the 

District of Columbia Circuit vacated 

portions of two provisions in the EPA’s 

CAA section 112 regulations governing 

the emissions of HAP during periods of 

SSM. Specifically, the Court vacated the 

SSM exemption contained in 40 CFR 

63.6(f)(1) and 40 CFR 63.6(h)(1), holding 

that under section 302(k) of the CAA, 

emissions standards or limitations must 

be continuous in nature and that the 

SSM exemption violates the CAA’s 

requirement that some section 112 

standards apply continuously. 

We are proposing the elimination of 

the SSM exemption in 40 CFR part 63, 

subparts CC and UUU. Consistent with 

Sierra Club v. EPA, we are proposing 

standards in these rules that apply at all 

times. We are also proposing several 

revisions to Table 6 of subpart CC of 40 

CFR part 63 and to Table 44 to subpart 

UUU of 40 CFR part 63 (the General 

Provisions Applicability tables for each 

subpart) as explained in more detail 

below. For example, we are proposing to 

eliminate the incorporation of the 

General Provisions’ requirement that the 

source develop an SSM plan. We also 

are proposing to eliminate and revise 

certain recordkeeping and reporting 

requirements related to the SSM 

exemption as further described below. 

The EPA has attempted to ensure that 

the provisions we are proposing to 

eliminate are inappropriate, 

unnecessary, or redundant in the 

absence of the SSM exemption. We are 

specifically seeking comment on 

whether we have successfully done so. 

In proposing the standards in this 

rule, the EPA has taken into account 

startup and shutdown periods and, for 

the reasons explained below, we are 

proposing alternate standards for those 

periods for a few select emission 

sources. We expect facilities can meet 

nearly all of the emission standards in 

Refinery MACT 1 and 2 during startup 

and shutdown, including the 

amendments we are proposing in this 

action. For most of the emission 

sources, APCD are operating prior to 

process startup and continue to operate 

through process shutdown. 


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For Refinery MACT 1 and 2, we 

identified three emission sources for 

which specific startup and shutdown 

provisions may be needed. First, as 

noted above, most APCD used to control 

metal HAP emissions from FCCU under 

Refinery MACT 2 (e.g., wet scrubber, 

fabric filter, cyclone) would be 

operating before emissions are routed to 

them and would be operating during 

startup and shutdown events in a 

manner consistent with normal 

operating periods, such that the 

monitoring parameter operating limits 

set during the performance test are 

maintained and met. However, we 

recognize that there are safety concerns 

associated with operating an ESP during 

startup of the FCCU, as described in the 

following paragraphs. Therefore, we are 

proposing specific PM standards for 

startup of FCCU controlled with an ESP 

under Refinery MACT 2. 

During startup of the FCCU, ‘‘torch 

oil’’ (heavy oil typically used as feed to 

the unit via the riser) is injected directly 

into the regenerator and burned to raise 

the temperature of the regenerator and 

catalyst to levels needed for normal 

operation. Given the poor mixing of fuel 

and air in the regenerator during this 

initial startup, it is difficult to maintain 

optimal combustion characteristics, and 

high CO concentrations are common. 

Elevated CO levels pose an explosion 

threat due to the high electric current 

and potential for sparks within the ESP. 

Consequently, it is common practice to 

bypass the ESP during startup of the 

FCCU. Once torch oil is shut off and the 

regenerator is fueled by catalyst coke 

burn-off, the CO levels in the FCCU 

regenerator off-gas will stabilize and the 

gas can be sent to the ESP safely. 

When the ESP is offline, the operating 

limits for the ESP are meaningless. 

During much of the startup process, 

either catalyst is not circulating between 

the FCCU regenerator and reactor or the 

catalyst circulation rate is much lower 

than during normal operations. While 

the catalyst is not circulating or is 

circulating at reduced rates, the PM and 

metal HAP emissions are expected to be 

much lower than during normal 

operations. Therefore, the cyclone 

separators that are internal to the FCCU 

regenerator should provide reasonable 

PM control during this initial startup. 

To ensure the internal cyclones are 

operating efficiently, we are proposing 

that FCCU using an ESP as the APCD 

meet a 30-percent opacity limit (on a 6- 

minute rolling average basis) during the 

period that torch oil is used during 

FCCU startup. This opacity limit was 

selected because it has been used 

historically to assess compliance with 

the PM emission limit for FCCU in 

Refinery NSPS J and because the 

emission limit can be assessed using 

manual opacity readings, eliminating 

the need to install a COMS. We note 

that Refinery NSPS J includes the 

exception for one 6-minute average of 

up to 60-percent opacity in a 1-hour 

period primarily to accommodate soot 

blowing events. As no soot blowing 

should be performed prior to the ESP 

coming on-line, we are not including 

this exception to the proposed 30- 

percent opacity limit during startup for 

FCCU that are controlled by an ESP. 

Second, for emissions of organic HAP 

from FCCU under Refinery MACT 2, we 

also expect that APCD would be 

operating before emissions are routed to 

them, and would be operating during 

startup and shutdown events in a 

manner consistent with normal 

operating periods, such that the 

monitoring parameter operating limits 

set during the performance test are 

maintained and met. However, many 

FCCU operate in ‘‘complete 

combustion’’ mode without a postcombustion device. In other words, for 

FCCU without a post-combustion 

device, organic HAP are controlled by 

the FCCU itself, so there is no separate 

APCD that could be operating during 

startup and demonstrating continuous 

compliance with the monitoring 

parameter operating limits. Therefore, 

we are proposing specific CO standards 

for startup of FCCU without a postcombustion device under Refinery 

MACT 2. 

As mentioned previously, ‘‘torch oil’’ 

is injected directly into the regenerator 

and burned during FCCU startup to 

raise the temperature of the regenerator 

and catalyst to levels needed for normal 

operation. During this period, CO 

concentrations often will exceed the 500 

ppm emissions limit due to the poor 

mixing of fuel and air in the regenerator. 

The emissions limit is based on CO 

emissions, as a surrogate for organic 

HAP emissions, and the emission limit 

is evaluated using a 1-hour averaging 

period. This 1-hour averaging period 

does not provide adequate time for 

short-term excursions that occur during 

startup to be offset by lower emissions 

during normal operational periods. 

Based on available data during normal 

operations, ensuring adequate 

combustion (indicated by CO 

concentration levels below 500 ppmv) 

minimizes organic HAP emissions. Low 

levels of CO in the exhaust gas are 

consistently achieved during normal 

operations when oxygen concentrations 

in the exhaust gas exceed 1-percent by 

volume (dry basis). Thus, maintaining 

an adequate level of excess oxygen for 

the combustion of fuel in the FCCU is 

expected to minimize organic HAP 

emissions. Emissions of CO during 

startup result from a series of reactions 

with the fuel source and are dependent 

on mixing, local oxygen concentrations, 

and temperature. While the refinery 

owner or operator has direct control 

over air blast rates, CO emissions may 

not always directly correlate with the air 

blast rate. Exhaust oxygen 

concentrations are expected to be more 

directly linked with air blast rates and 

are, therefore, more directly under 

control of the refinery owner or 

operator. We are proposing an excess 

oxygen concentration of 1 volume 

percent (dry basis) based on a 1-hour 

average during startup. We consider the 

1-hour averaging period for the oxygen 

concentration in the exhaust gas from 

the FCCU to be appropriate during 

periods of FCCU startup because air 

blast rates can be directly controlled to 

ensure adequate oxygen supply on a 

short-term basis. 

Third, we note that the SRU is unique 

in that it essentially is the APCD for the 

fuel gas system at the facility. The SRU 

would be operating if the refinery is 

operating, including during startup and 

shutdown events. There are typically 

multiple SRU trains at a facility. 

Different trains can be taken off-line as 

sour gas production decreases to 

maintain optimal operating 

characteristics of the operating SRU 

during startup or shutdown of a set of 

process units. Thus, the sulfur recovery 

plant is expected to run continuously 

and would only shut down its operation 

during a complete turnaround or 

shutdown of the facility. For these 

limited situations, the 12-hour averaging 

time provided for the SRU emissions 

limitation under Refinery MACT 2 may 

not be adequate time in which to shut 

down the unit without exceeding the 

emissions limitation. Therefore, we are 

proposing specific standards for SRU 

during periods of shutdown. 

We note also that, for SRU subject to 

Refinery NSPS J or electing to comply 

with Refinery NSPS J as provided in 

Refinery MACT 2, the emissions limit is 

in terms of SO2 concentration for SRU 

with oxidative control systems or 

reductive control systems followed by 

an incinerator. While the SO2

concentration limit provides a 

reasonable proxy of the reduced sulfur 

HAP emissions during normal 

operations, it does not necessarily 

provide a good indication of reduced 

sulfur HAP emissions during periods of 

shutdown. During periods of shutdown, 

the sulfur remaining in the unit is 

purged and combusted generally in a 

thermal oxidizer or a flare. Although the 

sulfur loading to the thermal oxidizer 


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during shutdown may be higher than 

during normal operations (thereby 

causing an increase in the SO2

concentration and exceedance of the 

SO2 emissions limitation), appropriate 

operation of the thermal oxidizer will 

adequately control emissions of reduced 

sulfur HAP. Thus, during periods of 

shutdown, the 300 ppmv reduced sulfur 

compound emission limit alternative 

(provided for SRU not subject to 

Refinery NSPS J) is a better indicator of 

reduced sulfur HAP emissions. In 

Refinery MACT 2, SRU that elect to 

comply with the 300 ppmv reduced 

sulfur compound emission limit (i.e., 

those not subject to Refinery NSPS J or 

electing to comply with Refinery NSPS 

J) and that use a thermal incinerator for 

sulfur HAP control are required to 

maintain a minimum temperature and 

excess oxygen level (as determined 

through a source test of the unit) to 

demonstrate compliance with the 

reduced sulfur compound emission 

limitation. 

In Refinery MACT 2, SRU subject to 

Refinery NSPS J (or that elect to comply 

with Refinery NSPS J) that use an 

incinerator to control sulfur HAP 

emissions are required to install an SO2

CEMS to demonstrate compliance with 

the SO2 emission limitation. For these 

units, it is impractical to require 

installation of a reduced sulfur 

compound monitor or to require a 

source test to establish operating 

parameters during shutdown of the SRU 

because of the few hours per year that 

the entire series of SRU trains are 

shutdown. Although the autoignition 

temperature of COS is unknown, based 

on the autoignition temperature of CS2

(between 200 and 250 °F) and the 

typical operating characteristics of 

thermal oxidizers used to control 

emissions from SRU, we are proposing 

that, for periods of SRU shutdown, 

diverting the purge gases to a flare 

meeting the design and operating 

requirements in 40 CFR 63.670 (or, for 

a limited transitional time period, 40 

CFR 63.11) or to a thermal oxidizer 

operated at a minimum temperature of 

1200 °F and a minimum outlet oxygen 

concentration of 2 volume percent (dry 

basis). We believe that this provides 

adequate assurance of compliance with 

the 300 ppmv reduced sulfur compound 

emission limitation for SRU because 

incineration at these temperatures was 

determined to be the MACT floor in 

cases where no tail gas treatment units 

were used (i.e., units not subject to 

Refinery NSPS J). 

For all other emission sources, we 

believe that the requirements that apply 

during normal operations should apply 

during startup and shutdown. For 

Refinery MACT 1, these emission 

sources include process vents, transfer 

operations, storage tanks, equipment 

leaks, heat exchange systems, and 

wastewater. Emission reductions for 

process vents and transfer operations, 

such as gasoline loading racks and 

marine tank vessel loading, are typically 

achieved by routing vapors to thermal 

oxidizers, carbon adsorbers, absorbers 

and flares. It is common practice to start 

an APCD prior to startup of the 

emissions source it is controlling, so the 

APCD would be operating before 

emissions are routed to it. We expect 

APCD would be operating during 

startup and shutdown events in a 

manner consistent with normal 

operating periods, and that these APCD 

will be operated to maintain and meet 

the monitoring parameter operating 

limits set during the performance test. 

We do not expect startup and shutdown 

events to affect emissions from 

equipment leaks, heat exchange 

systems, wastewater, or storage tanks. 

Leak detection programs associated with 

equipment leaks and heat exchange 

systems are in place to detect leaks, and, 

therefore, it is inconsequential whether 

the process is operating under normal 

operating conditions or is in startup or 

shutdown. Wastewater emissions are 

also not expected to be significantly 

affected by startup or shutdown events 

because the control systems used can 

operate while the wastewater treatment 

system is in startup or shutdown. 

Working and breathing losses from 

storage tanks are the same regardless of 

whether the process is operating under 

normal operating conditions or if it is in 

a startup or shutdown event. Degassing 

of a storage tank is common for 

shutdown of a process; the residual 

emissions in a storage tank are vented 

as part of the cleaning of the storage 

tank. We evaluated degassing controls 

as a control alternative for storage 

vessels and do not consider these 

controls to be cost effective (see 

memorandum Survey of Control 

Technology for Storage Vessels and 

Analysis of Impacts for Storage Vessel 

Control Options, Docket Item Number 

EPA–HQ–OAR–2010–0871–0027). 

Based on this review, we are not 

proposing specific standards for storage 

vessels during startup or shutdown. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a sudden, infrequent, and not 

reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner (see 40 CFR 63.2). The EPA has 

determined that CAA section 112 does 

not require that emissions that occur 

during periods of malfunction be 

factored into development of section 

112 standards. Under section 112, 

emissions standards for new sources 

must be no less stringent than the level 

‘‘achieved’’ by the best-controlled 

similar source and for existing sources 

generally must be no less stringent than 

the average emission limitation 

‘‘achieved’’ by the best-performing 12 

percent of sources in the category. There 

is nothing in section 112 that directs the 

EPA to consider malfunctions in 

determining the level ‘‘achieved’’ by the 

best-performing sources when setting 

emission standards. As the D.C. Circuit 

has recognized, the phrase ‘‘average 

emissions limitation achieved by the 

best performing 12 percent of’’ sources 

‘‘says nothing about how the 

performance of the best units is to be 

calculated.’’ Nat’l Ass’n of Clean Water 

Agencies v. EPA, 734 F.3d 1115, 1141 

(D.C. Cir. 2013). While the EPA 

accounts for variability in setting 

emissions standards, nothing in section 

112 requires the EPA to consider 

malfunctions as part of that analysis. A 

malfunction should not be treated in the 

same manner as the type of variation in 

performance that occurs during routine 

operations of a source. A malfunction is 

a failure of the source to perform in a 

‘‘normal or usual manner’’ and no 

statutory language compels EPA to 

consider such events in setting 

standards based on ‘‘best performers.’’ 

Further, accounting for malfunctions 

in setting emissions standards would be 

difficult, if not impossible, given the 

myriad different types of malfunctions 

that can occur across all sources in the 

category, and given the difficulties 

associated with predicting or accounting 

for the frequency, degree, and duration 

of various malfunctions that might 

occur. As such, the performance of units 

that are malfunctioning is not 

‘‘reasonably’’ foreseeable. See, e.g., 

Sierra Club v. EPA, 167 F. 3d 658, 662 

(D.C. Cir. 1999) (the EPA typically has 

wide latitude in determining the extent 

of data-gathering necessary to solve a 

problem. We generally defer to an 

agency’s decision to proceed on the 

basis of imperfect scientific information, 

rather than to ‘‘invest the resources to 

conduct the perfect study.’’). See also, 

Weyerhaeuser v. Costle, 590 F.2d 1011, 

1058 (D.C. Cir. 1978) (‘‘In the nature of 

things, no general limit, individual 

permit, or even any upset provision can 

anticipate all upset situations. After a 

certain point, the transgression of 

regulatory limits caused by 


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41The court’s reasoning in NRDC focuses on civil 

judicial actions. The Court noted that ‘‘EPA’s ability 

to determine whether penalties should be assessed 

for Clean Air Act violations extends only to 

administrative penalties, not to civil penalties 

imposed by a court.’’ Id. 

‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase enforcement discretion, not for 

specification in advance by 

regulation.’’). In addition, emissions 

during a malfunction event can be 

significantly higher than emissions at 

any other time of source operation, and 

thus, accounting for malfunctions in 

setting standards could lead to 

standards that are significantly less 

stringent than levels that are achieved 

by a well-performing nonmalfunctioning source. It is reasonable 

to interpret section 112 to avoid such a 

result. The EPA’s approach to 

malfunctions is consistent with CAA 

section 112 and is a reasonable 

interpretation of the statute. 

In the event that a source fails to 

comply with the applicable CAA section 

112(d) standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the goodfaith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 112(d) 

standard was, in fact, sudden, 

infrequent, not reasonably preventable 

and was not instead caused in part by 

poor maintenance or careless operation, 

as described in the definition of 

malfunction (see 40 CFR 63.2). Further, 

to the extent the EPA files an 

enforcement action against a source for 

violation of an emission standard, the 

source can raise any and all defenses in 

that enforcement action and the federal 

district court will determine what, if 

any, relief is appropriate. The same is 

true for citizen enforcement actions. 

Similarly, the presiding officer in an 

administrative proceeding can consider 

any defense raised and determine 

whether administrative penalties are 

appropriate. 

In several prior rules, the EPA had 

included an affirmative defense to civil 

penalties for violations caused by 

malfunctions in an effort to create a 

system that incorporates some 

flexibility, recognizing that there is a 

tension, inherent in many types of air 

regulation, to ensure adequate 

compliance while simultaneously 

recognizing that despite the most 

diligent of efforts, emission standards 

may be violated under circumstances 

entirely beyond the control of the 

source. Although the EPA recognized 

that its case-by-case enforcement 

discretion provides sufficient flexibility 

in these circumstances, it included the 

affirmative defense to provide a more 

formalized approach and more 

regulatory clarity. See Weyerhaeuser Co. 

v. Costle, 590 F.2d 1011, 1057–58 (D.C. 

Cir. 1978) (holding that an informal 

case-by-case enforcement discretion 

approach is adequate); but see Marathon 

Oil Co. v. EPA, 564 F.2d 1253, 1272–73 

(9th Cir. 1977) (requiring a more 

formalized approach to consideration of 

‘‘upsets beyond the control of the permit 

holder.’’). Under the EPA’s regulatory 

affirmative defense provisions, if a 

source could demonstrate in a judicial 

or administrative proceeding that it had 

met the requirements of the affirmative 

defense in the regulation, civil penalties 

would not be assessed. Recently, the 

United States Court of Appeals for the 

District of Columbia Circuit vacated 

such an affirmative defense in one of the 

EPA’s section 112(d) regulations. NRDC 

v. EPA, No. 10–1371 (D.C. Cir. April 18, 

2014) 2014 U.S. App. LEXIS 7281 

(vacating affirmative defense provisions 

in section 112(d) rule establishing 

emission standards for Portland cement 

kilns). The court found that the EPA 

lacked authority to establish an 

affirmative defense for private civil suits 

and held that under the CAA, the 

authority to determine civil penalty 

amounts lies exclusively with the 

courts, not the EPA. Specifically, the 

Court found: ‘‘As the language of the 

statute makes clear, the courts 

determine, on a case-by-case basis, 

whether civil penalties are 

‘appropriate.’ ’’ See NRDC, 2014 U.S. 

App. LEXIS 7281 at *21 (‘‘[U]nder this 

statute, deciding whether penalties are 

‘appropriate’ in a given private civil suit 

is a job for the courts, not EPA.’’).41 In 

light of NRDC, the EPA is not including 

a regulatory affirmative defense 

provision in this rulemaking. As 

explained above, if a source is unable to 

comply with emissions standards as a 

result of a malfunction, the EPA may 

use its case-by-case enforcement 

discretion to provide flexibility, as 

appropriate. Further, as the D.C. Circuit 

recognized, in an EPA or citizen 

enforcement action, the court has the 

discretion to consider any defense 

raised and determine whether penalties 

are appropriate. Cf. NRDC, 2014 U.S. 

App. LEXIS 7281 at *24. (arguments 

that violation were caused by 

unavoidable technology failure can be 

made to the courts in future civil cases 

when the issue arises). The same logic 

applies to EPA administrative 

enforcement actions. 

a. General Duty 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.6(e)(1)(i) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entry for § 63.6(e)(1)(i) by 

changing the ‘‘Yes’’ in the third column 

to a ‘‘No.’’ We are making this change 

because section 63.6(e)(1)(i) describes 

the general duty to minimize emissions 

and the current characterizes what the 

general duty entails during periods of 

SSM and that language is no longer 

necessary or appropriate in light of the 

elimination of the SSM exemption. We 

are proposing instead to add general 

duty regulatory text at 40 CFR 63.642(n) 

and 40 CFR 63.1570(c) that reflects the 

general duty to minimize emissions 

while eliminating the reference to 

periods covered by an SSM exemption. 

With the elimination of the SSM 

exemption, there is no need to 

differentiate between normal operations, 

startup and shutdown, and malfunction 

events in describing the general duty. 

Therefore the language the EPA is 

proposing does not include that 

language from 40 CFR 63.6(e)(1). 

We are also proposing to revise the 40 

CFR part 63, subpart CC General 

Provisions table (Table 6) entry for 

63.6(e)(1)(ii) by changing the ‘‘Yes’’ in 

the second column to a ‘‘No.’’ Similarly, 

we are also proposing to revise the 40 

CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for 

§ 63.6(e)(1)(ii) by changing the ‘‘Yes’’ in 

the third column to a ‘‘No.’’ Section 

63.6(e)(1)(ii) imposes requirements that 

are not necessary with the elimination 

of the SSM exemption or are redundant 

of the general duty requirement being 

added at 40 CFR 63.642(n) and 40 CFR 

63.1570(c). 

b. SSM Plan 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entries for 63.6(e)(3)(i) 

and 63.6(e)(3)(iii)–63.6(e)(3)(ix) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entries for § 63.6(e)(3)(i)–(iii), 

§ 63.6(e)(3)(iv), § 63.6(e)(3)(v)–(viii), 

§ 63.6(e)(3)(ix) to be entries for 

63.6(e)(3)(i) and 63.6(e)(3)(iii)– 

63.6(e)(3)(ix) with ‘‘No’’ in the third 

column and § 63.6(e)(3)(ii) with ‘‘Not 


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Applicable’’ in the third column (that 

section is reserved). Generally, these 

paragraphs require development of an 

SSM plan and specify SSM 

recordkeeping and reporting 

requirements related to the SSM plan. 

As noted, the EPA is proposing to 

remove the SSM exemptions. Therefore, 

affected units will be subject to an 

emission standard during such events. 

The applicability of a standard during 

such events will ensure that sources 

have ample incentive to plan for and 

achieve compliance and thus the SSM 

plan requirements are no longer 

necessary. 

c. Compliance With Standards 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.6(f)(1) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entry for § 63.6(f)(1) by 

changing the ‘‘Yes’’ in the third column 

to a ‘‘No.’’ The current language of 40 

CFR 63.6(f)(1) exempts sources from 

non-opacity standards during periods of 

SSM. As discussed above, the court in 

Sierra Club vacated the exemptions 

contained in this provision and held 

that the CAA requires that some section 

112 standard apply continuously. 

Consistent with Sierra Club, the EPA is 

proposing to revise standards in this 

rule to apply at all times. 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.6(h)(1) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entry for § 63.6(h)(1) by 

changing the ‘‘Yes’’ in the third column 

to a ‘‘No.’’ The current language of 40 

CFR 63.6(h)(1) exempts sources from 

opacity standards during periods of 

SSM. As discussed above, the court in 

Sierra Club vacated the exemptions 

contained in this provision and held 

that the CAA requires that some section 

112 standard apply continuously. 

Consistent with Sierra Club, the EPA is 

proposing to revise standards in this 

rule to apply at all times. 

d. Performance Testing 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.7(e)(1) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entry for § 63.7(e)(1) by 

changing the ‘‘Yes’’ in the third column 

to a ‘‘No.’’ Section 63.7(e)(1) describes 

performance testing requirements. The 

EPA is instead proposing to add 

performance testing requirements at 40 

CFR 63.642(d)(3) and 40 CFR 

63.1571(b)(1). The performance testing 

requirements we are proposing differ 

from the General Provisions 

performance testing provisions in 

several respects. The regulatory text 

does not include the language in 40 CFR 

63.7(e)(1) that restated the SSM 

exemption. The regulatory text also does 

not preclude startup and shutdown 

periods from being considered 

‘‘representative’’ for purposes of 

performance testing, however, the 

testing. However, the specific testing 

provisions proposed at 40 CFR 

63.642(d)(3) and 40 CFR 63.1571(b)(1) 

do not allow performance testing during 

startup or shutdown. As in 40 CFR 

63.7(e)(1), performance tests conducted 

under this subpart may not be 

conducted during malfunctions because 

conditions during malfunctions are 

often not representative of normal 

operating conditions. The EPA is 

proposing to add language that requires 

the owner or operator to record the 

process information that is necessary to 

document operating conditions during 

the test and include in such record an 

explanation to support that such 

conditions represent normal operation. 

Section 63.7(e) requires that the owner 

or operator make available to the 

Administrator such records ‘‘as may be 

necessary to determine the condition of 

the performance test’’ available to the 

Administrator upon request, but does 

not specifically require the information 

to be recorded. The regulatory text EPA 

is proposing to add to Refinery MACT 

1 and 2 builds on that requirement and 

makes explicit the requirement to record 

the information. 

e. Monitoring 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entries for 63.8(c)(1)(i) 

and 63.8(c)(1)(iii) by changing the ‘‘Yes’’ 

in the second column to a ‘‘No.’’ 

Similarly, we are proposing to revise the 

40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for 

§ 63.8(c)(1)(i) and § 63.8(c)(1)(iii) by 

changing the ‘‘Yes’’ in the third column 

to a ‘‘No.’’ The cross-references to the 

general duty and SSM plan 

requirements in those subparagraphs are 

not necessary in light of other 

requirements of 40 CFR 63.8 that require 

good air pollution control practices (40 

CFR 63.8(c)(1)) and that set out the 

requirements of a quality control 

program for monitoring equipment (40 

CFR 63.8(d)). 

We are proposing to revise the 40 CFR 

part 63, subpart UUU General 

Provisions table (Table 44) entry for 

§ 63.8(d) to include separate entries for 

specific paragraphs of 40 CFR 63.8(d), 

including an entry for § 63.10(d)(3) with 

‘‘No’’ in the third column. The final 

sentence in 40 CFR 63.8(d)(3) refers to 

the General Provisions’ SSM plan 

requirement which is no longer 

applicable. The EPA is proposing to add 

to the rule at 40 CFR 63.1576(b)(3) text 

that is identical to 40 CFR 63.8(d)(3) 

except that the final sentence is 

replaced with the following sentence: 

‘‘The program of corrective action 

should be included in the plan required 

under § 63.8(d)(2).’’ 

f. Recordkeeping 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.10(b)(2)(i) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Section 63.10(b)(2)(i) 

describes the recordkeeping 

requirements during startup and 

shutdown. These recording provisions 

are no longer necessary because the EPA 

is proposing that recordkeeping and 

reporting applicable to normal 

operations will apply to startup and 

shutdown. In the absence of special 

provisions applicable to startup and 

shutdown, such as a startup and 

shutdown plan, there is no reason to 

retain additional recordkeeping for 

startup and shutdown periods. 

We are proposing to revise the 40 CFR 

part 63, subpart UUU General 

Provisions table (Table 44) entry for 

§ 63.10(b) to include separate entries for 

specific paragraphs of 40 CFR 63.10(b), 

including an entry for § 63.10(b)(2)(i) 

with ‘‘No’’ in the third column. Section 

63.10(b)(2)(i) describes the 

recordkeeping requirements during 

startup and shutdown. We are instead 

proposing to add recordkeeping 

requirements to 40 CFR 63.1576(a)(2). 

When a source is subject to a different 

standard during startup and shutdown, 

it will be important to know when such 

startup and shutdown periods begin and 

end in order to determine compliance 

with the appropriate standard. Thus, the 

EPA is proposing to add language to 40 

CFR 63.1576(a)(2) requiring that sources 

subject to an emission standard during 

startup or shutdown that differs from 

the emission standard that applies at all 

other times must record the date, time, 

and duration of such periods. 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.10(b)(2)(ii) 

by changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 


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subpart UUU General Provisions table 

(Table 44) entry for § 63.10(b) to include 

separate entries for specific paragraphs 

of 40 CFR 63.10(b), including an entry 

for § 63.10(b)(2)(ii) with ‘‘No’’ in the 

third column. Section 63.10(b)(2)(ii) 

describes the recordkeeping 

requirements during a malfunction. The 

EPA is proposing to add such 

requirements to 40 CFR 63.655(i)(11) 

and 40 CFR 63.1576(a)(2). The 

regulatory text we are proposing to add 

differs from the General Provisions 

language that was cross-referenced, 

which provides the creation and 

retention of a record of the occurrence 

and duration of each malfunction of 

process, air pollution control, and 

monitoring equipment. The proposed 

text would apply to any failure to meet 

an applicable standard and would 

require the source to record the date, 

time, and duration of the failure. The 

EPA is also proposing to add to 40 CFR 

63.655(i)(11) and 40 CFR 63.1576(a)(2) a 

requirement that sources keep records 

that include a list of the affected source 

or equipment and actions taken to 

minimize emissions, an estimate of the 

quantity of each regulated pollutant 

emitted over the standard for which the 

source failed to meet a standard, and a 

description of the method used to 

estimate the emissions. Examples of 

such methods would include productloss calculations, mass balance 

calculations, measurements when 

available, or engineering judgment 

based on known process parameters. 

The EPA is proposing to require that 

sources keep records of this information 

to ensure that there is adequate 

information to allow the EPA to 

determine the severity of any failure to 

meet a standard, and to provide data 

that may document how the source met 

the general duty to minimize emissions 

when the source has failed to meet an 

applicable standard. 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.10(b)(2)(iv) 

by changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entry for § 63.10(b) to include 

separate entries for specific paragraphs 

of 40 CFR 63.10(b), including an entry 

for § 63.10(b)(2)(iv)–(v) with ‘‘No’’ in the 

third column. When applicable, 40 CFR 

63.10(b)(2)(iv) requires sources to record 

actions taken during SSM events when 

actions were inconsistent with their 

SSM plan. The requirement is no longer 

appropriate because SSM plans will no 

longer be required. The requirement 

previously applicable under 40 CFR 

63.10(b)(2)(iv)(B) to record actions to 

minimize emissions and record 

corrective actions is now applicable by 

reference to 40 CFR 63.655(i)(11)(iii) 

and 40 CFR 63.1576(a)(2)(iii). 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entry for 63.10(b)(2)(v) by 

changing the ‘‘Yes’’ in the second 

column to a ‘‘No.’’ Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entry for § 63.10(b) to include 

separate entries for specific paragraphs 

of 40 CFR 63.10(b), including an entry 

for § 63.10(b)(2)(iv)–(v) with ‘‘No’’ in the 

third column. When applicable, 40 CFR 

63.10(b)(2)(v) requires sources to record 

actions taken during SSM events to 

show that actions taken were consistent 

with their SSM plan. The requirement is 

no longer appropriate because SSM 

plans would no longer be required. 

We are proposing to revise the 40 CFR 

part 63, subpart UUU General 

Provisions table (Table 44) entry for 

§ 63.10(c)(9)–(15) to include separate 

entries for specific paragraphs of 40 CFR 

63.10(c), including an entry for 

§ 63.10(c)(15) with ‘‘No’’ in the third 

column. The EPA is proposing that 40 

CFR 63.10(c)(15) no longer apply. When 

applicable, the provision allows an 

owner or operator to use the affected 

source’s SSM plan or records kept to 

satisfy the recordkeeping requirements 

of the SSM plan, specified in 40 CFR 

63.6(e), to also satisfy the requirements 

of 40 CFR 63.10(c)(10) through (12). The 

EPA is proposing to eliminate this 

requirement because SSM plans would 

no longer be required, and therefore 40 

CFR 63.10(c)(15) no longer serves any 

useful purpose for affected units. 

g. Reporting 

We are proposing to revise the 40 CFR 

part 63, subpart CC General Provisions 

table (Table 6) entries for 63.10(d)(5)(i) 

and 63.10(d)(5)(ii) by combining them 

into one entry for 63.10(d)(5) with a 

‘‘No’’ in the second column. Similarly, 

we are proposing to revise the 40 CFR 

part 63, subpart UUU General 

Provisions table (Table 44) entries for 

63.10(d)(5)(i) and 63.10(d)(5)(ii) by 

combining them into one entry for 

63.10(d)(5) with a ‘‘No’’ in the third 

column. Section 63.10(d)(5) describes 

the reporting requirements for startups, 

shutdowns, and malfunctions. To 

replace the General Provisions reporting 

requirement, the EPA is proposing to 

add reporting requirements to 40 CFR 

63.655(g)(12), 40 CFR 63.1575(c)(4), 40 

CFR 63.1575(d), and 40 CFR 63.1575(e). 

The General Provisions requirement that 

was cross-referenced requires periodic 

SSM reports as a stand-alone report. In 

its place, we are proposing language that 

requires sources that fail to meet an 

applicable standard at any time to report 

the information concerning such events 

in the periodic report already required 

under each of these rules. We are 

proposing that the report must contain 

the number, date, time, duration, and 

the cause of such events (including 

unknown cause, if applicable), a list of 

the affected source or equipment, an 

estimate of the quantity of each 

regulated pollutant emitted over any 

emission limit, and a description of the 

method used to estimate the emissions. 

Examples of methods that can be used 

to estimate emissions would include 

product-loss calculations, mass balance 

calculations, measurements when 

available, or engineering judgment 

based on known process parameters. 

The EPA is proposing this requirement 

to ensure that there is adequate 

information to determine compliance, to 

allow the EPA to determine the severity 

of the failure to meet an applicable 

standard, and to provide data that may 

document how the source met the 

general duty to minimize emissions 

during a failure to meet an applicable 

standard. 

We will no longer require owners or 

operators to determine whether actions 

taken to correct a malfunction are 

consistent with an SSM plan, because 

SSM plans would no longer be required. 

The proposed rule eliminates the crossreference to 40 CFR 63.10(d)(5)(i) that 

contains the description of the 

previously required SSM report format 

and submittal schedule from this 

section. These specifications are no 

longer necessary because the events will 

be reported in otherwise required 

reports with similar format and 

submittal requirements. 

As noted above, we are proposing to 

revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) 

entries for 63.10(d)(5)(i) and 

63.10(d)(5)(ii) by combining them into 

one entry for 63.10(d)(5) with a ‘‘No’’ in 

the second column. Similarly, we are 

proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table 

(Table 44) entries for 63.10(d)(5)(i) and 

63.10(d)(5)(ii) by combining them into 

one entry for 63.10(d)(5) with a ‘‘No’’ in 

the third column. Section 63.10(d)(5)(ii) 

describes an immediate report for 

startups, shutdown, and malfunctions 

when a source fails to meet an 

applicable standard but does not follow 

the SSM plan. We are proposing to no 

longer require owners and operators to 

report when actions taken during a 

startup, shutdown, or malfunction were 

not consistent with an SSM plan, 


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because such plans would no longer be 

required. 

2. Electronic Reporting 

In this proposal, the EPA is describing 

a process to increase the ease and 

efficiency of performance test data 

submittal while improving data 

accessibility. Specifically, the EPA is 

proposing that owners and operators of 

petroleum refineries submit electronic 

copies of required performance test and 

performance evaluation reports by 

direct computer-to-computer electronic 

transfer using EPA-provided software. 

The direct computer-to-computer 

electronic transfer is accomplished 

through the EPA’s Central Data 

Exchange (CDX) using the Compliance 

and Emissions Data Reporting Interface 

(CEDRI). The CDX is EPA’s portal for 

submittal of electronic data. The EPAprovided software is called the 

Electronic Reporting Tool (ERT) which 

is used to generate electronic reports of 

performance tests and evaluations. The 

ERT generates an electronic report 

package which will be submitted using 

the CEDRI. The submitted report 

package will be stored in the CDX 

archive (the official copy of record) and 

the EPA’s public database called 

WebFIRE. All stakeholders will have 

access to all reports and data in 

WebFIRE and accessing these reports 

and data will be very straightforward 

and easy (see the WebFIRE Report 

Search and Retrieval link at http://

cfpub.epa.gov/webfire/

index.cfm?action=fire.search

ERTSubmission). A description and 

instructions for use of the ERT can be 

found at http://www.epa.gov/ttn/chief/

ert/index.html and CEDRI can be 

accessed through the CDX Web site 

(www.epa.gov/cdx). A description of the 

WebFIRE database is available at: http:// 

cfpub.epa.gov/oarweb/index.cfm?

action=fire.main. 

The proposal to submit performance 

test data electronically to the EPA 

applies only to those performance tests 

(and/or performance evaluations) 

conducted using test methods that are 

supported by the ERT. The ERT 

supports most of the commonly used 

EPA reference methods. A listing of the 

pollutants and test methods supported 

by the ERT is available at: http://

www.epa.gov/ttn/chief/ert/index.html. 

We believe that industry would 

benefit from this proposed approach to 

electronic data submittal. Specifically, 

by using this approach, industry will 

save time in the performance test 

submittal process. Additionally, the 

standardized format that the ERT uses 

allows sources to create a more 

complete test report resulting in less 

time spent on data backfilling if a source 

failed to include all data elements 

required to be submitted. Also through 

this proposal industry may only need to 

submit a report once to meet the 

requirements of the applicable subpart 

because stakeholders can readily access 

these reports from the WebFIRE 

database. This also benefits industry by 

cutting back on recordkeeping costs as 

the performance test reports that are 

submitted to the EPA using CEDRI are 

no longer required to be retained in hard 

copy, thereby reducing staff time 

needed to coordinate these records. 

Since the EPA will already have 

performance test data in hand, another 

benefit to industry is that fewer or less 

substantial data collection requests in 

conjunction with prospective required 

residual risk assessments or technology 

reviews will be needed. This would 

result in a decrease in staff time needed 

to respond to data collection requests. 

State, local and tribal air pollution 

control agencies (S/L/Ts) may also 

benefit from having electronic versions 

of the reports they are now receiving. 

For example, S/L/Ts may be able to 

conduct a more streamlined and 

accurate review of electronic data 

submitted to them. For example, the 

ERT would allow for an electronic 

review process, rather than a manual 

data assessment, therefore, making 

review and evaluation of the source 

provided data and calculations easier 

and more efficient. In addition, the 

public stands to benefit from electronic 

reporting of emissions data because the 

electronic data will be easier for the 

public to access. How the air emissions 

data are collected, accessed and 

reviewed will be more transparent for 

all stakeholders. 

One major advantage of the proposed 

submittal of performance test data 

through the ERT is a standardized 

method to compile and store much of 

the documentation required to be 

reported by this rule. The ERT clearly 

states what testing information would 

be required by the test method and has 

the ability to house additional data 

elements that might be required by a 

delegated authority. 

In addition the EPA must have 

performance test data to conduct 

effective reviews of CAA sections 111 

and 112 standards, as well as for many 

other purposes including compliance 

determinations, emission factor 

development and annual emission rate 

determinations. In conducting these 

required reviews, the EPA has found it 

ineffective and time consuming, not 

only for us, but also for regulatory 

agencies and source owners and 

operators, to locate, collect and submit 

performance test data. In recent years, 

stack testing firms have typically 

collected performance test data in 

electronic format, making it possible to 

move to an electronic data submittal 

system that would increase the ease and 

efficiency of data submittal and improve 

data accessibility. 

A common complaint heard from 

industry and regulators is that emission 

factors are outdated or not 

representative of a particular source 

category. With timely receipt and 

incorporation of data from most 

performance tests, the EPA would be 

able to ensure that emission factors, 

when updated, represent the most 

current range of operational practices. 

Finally, another benefit of the proposed 

data submittal to WebFIRE 

electronically is that these data would 

greatly improve the overall quality of 

existing and new emissions factors by 

supplementing the pool of emissions 

test data for establishing emissions 

factors. 

In summary, in addition to supporting 

regulation development, control strategy 

development and other air pollution 

control activities, having an electronic 

database populated with performance 

test data would save industry, state, 

local and tribal agencies and the EPA 

significant time, money and effort while 

also improving the quality of emission 

inventories and air quality regulations. 

In addition, we are proposing that the 

fenceline data at each monitor location 

(as proposed above) would be reported 

electronically on a semiannual basis. All 

data reported electronically would be 

submitted to CDX through CEDRI and 

made available to the public. 

3. Technical Amendments to Refinery 

MACT 1 and 2 

a. Open-Ended Valves and Lines 

Refinery MACT 1 requires an owner 

or operator to control emissions from 

equipment leaks according to the 

requirements of either 40 CFR part 60, 

subpart VV or 40 CFR part 63, subpart 

H. For open-ended valves and lines, 

both subparts require that the open end 

be equipped with a cap, blind flange, 

plug or second valve that ‘‘shall seal the 

open end at all times.’’ However, neither 

subpart defines ‘‘seal’’ or explains in 

practical and enforceable terms what 

constitutes a sealed open-ended valve or 

line. This has led to uncertainty on the 

part of the owner or operator as to 

whether compliance is being achieved. 

Inspections under the EPA’s Air Toxics 

LDAR initiative have provided evidence 

that while certain open-ended lines may 

be equipped with a cap, blind flange, 

plug or second valve, they are not 


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operating in a ‘‘sealed’’ manner as the 

EPA interprets that term. 

In response to this uncertainty, we are 

proposing to amend 40 CFR 63.648 to 

clarify what is meant by ‘‘seal.’’ This 

proposed amendment clarifies that, for 

the purpose of complying with the 

requirements of 40 CFR 63.648, openended valves and lines are ‘‘sealed’’ by 

the cap, blind flange, plug, or second 

valve when there are no detectable 

emissions from the open-ended valve or 

line at or above an instrument reading 

of 500 ppm. We solicit comment on this 

approach to reducing the compliance 

uncertainty associated with open-ended 

valves and lines and our proposed 

amendment. 

b. General Provisions Cross-Referencing 

We have reviewed the application of 

40 CFR part 63, subpart A (General 

Provisions) to Refinery MACT 2. The 

applicable requirements of 40 CFR part 

63, subpart A are contained in Table 44 

of 40 CFR part 63, subpart UUU. As a 

result of our review, we are proposing 

several amendments to Table 44 of 40 

CFR part 63, subpart UUU (in addition 

to those discussed in section IV.E.1 of 

this preamble that address SSM) to 

bring the table up-to-date with 

requirements of the General Provisions 

that have been amended since this table 

was created, to correct cross-references, 

and to incorporate additional sections of 

the General Provisions that are 

necessary to implement other subparts 

that are cross-referenced by this rule. 

Although we reviewed the application 

of the General Provisions to Refinery 

MACT 1 and amended Table 6 of 40 

CFR part 63, subpart CC in 2009, we are 

proposing a few additional technical 

corrections to this table (in addition to 

those discussed in section IV.E.1 of this 

preamble that address SSM). We are not 

discussing the details of these proposed 

technical corrections in this preamble 

but the rationale for each change to 

Table 6 of 40 CFR part 63, subpart CC 

and Table 44 of 40 CFR part 63, subpart 

UUU (including the proposed 

amendments to address SSM discussed 

above), is included in Docket ID 

Number EPA–HQ–OAR–2010–0682. 

4. Amendments to Refinery NSPS J and 

Ja 

As discussed in section II.B.2 of this 

preamble, we are addressing a number 

of technical corrections and 

clarifications for Refinery NSPS J and Ja 

to address some of the issues raised in 

the petition for reconsideration and to 

improve consistency and clarity of the 

rule requirements. These issues are 

addressed in detail in API’s amended 

petition, dated August 21, 2008 (see 

Docket Item Number EPA–HQ–OAR– 

2007–0011–0246) and the meeting 

minutes for a September 11, 2008 

meeting between EPA and API (see 

Docket Item Number EPA–HQ–OAR– 

2007–0011–0266). 

a. The Depressurization Work Practice 

Standard for Delayed Coking Units 

HOVENSA and the Industry 

Petitioners raised several issues with the 

analysis conducted to support the DCU 

work practice standard in Refinery 

NSPS Ja. With the promulgation and 

implementation of the standards we are 

proposing for the DCU under Refinery 

MACT 1, the DCU work practice 

standards in Refinery NSPS Ja are not 

expected to result in any further 

decreases in emissions from the DCU. 

Any DCU that becomes subject to 

Refinery NSPS Ja would already be in 

compliance with Refinery MACT 1, 

which is a more stringent standard than 

the DCU work practice standards in 

Refinery NSPS Ja. As such, we are 

contemplating various ideas for 

harmonizing the requirements for the 

DCU in these two regulations. One 

option is to amend Refinery NSPS Ja to 

incorporate the same requirements 

being proposed for Refinery MACT 1 

(the DCU work practice standard in 

Refinery NSPS Ja is less stringent than 

the proposed requirements for Refinery 

MACT 1). Another option we are 

contemplating is deleting the DCU work 

practice standard within Refinery NSPS 

Ja once the DCU standards in Refinery 

MACT 1 are promulgated and fully 

implemented. We believe deletion of 

this work practice standard is consistent 

with the objectives of Executive Order 

13563, ‘‘Improving Regulation and 

Regulatory Review.’’ We solicit 

comment on these options as well as 

any other comments regarding the 

interaction between the DCU 

requirements in these two rules (i.e., the 

need to keep the DCU work practice 

standard in Refinery NSPS Ja after 

promulgation of these revisions to 

Refinery MACT 1.) 

b. Technical Corrections and 

Clarifications 

In addition to their primary issues, 

the Industry Petitioners enumerated 

several points of clarification and 

recommended amendments to Refinery 

NSPS J and Ja. These issues are 

addressed in detail in API’s amended 

petition for reconsideration, dated 

August 21, 2008 (see Docket Item 

Number EPA–HQ–OAR–2007–0011– 

0246) and the meeting minutes for a 

September 11, 2008 meeting between 

EPA and API (see Docket Item Number 

EPA–HQ–OAR–2007–0011–0266). We 

are including several proposed 

amendments in this rulemaking to 

specifically address these issues. These 

amendments are discussed in the 

remainder of this section. We are 

addressing these issues now while we 

are proposing amendments for Refinery 

MACT 2 in an effort to improve 

consistency and clarity for sources 

regulated under both the NSPS and 

Refinery MACT 2. 

We are proposing a series of 

amendments to the requirements for 

sulfur recovery plants in 40 CFR 

60.102a, to clarify the applicable 

emission limits for different types of 

sulfur recovery plants based on whether 

oxygen enrichment is used. These 

amendments also clarify that emissions 

averaging across a group of emission 

points within a given sulfur recovery 

plant is allowed from each of the 

different types of sulfur recovery plants, 

and that emissions averaging is specific 

to the SO2 or reduced sulfur standards 

(and not to the H2S limit). The 10 ppmv 

H2S limit for reduction control systems 

not followed by incineration must be 

met on a release point-specific basis. 

These amendments are being made to 

clarify the original intent of the Refinery 

NSPS Ja requirements for sulfur 

recovery plants. 

We are proposing a series of 

corresponding amendments in 40 CFR 

60.106a to clarify the monitoring 

requirements, particularly when oxygen 

enrichment or emissions averaging is 

used. The monitoring requirements in 

Refinery NSPS Ja were incomplete for 

these provisions and did not specify all 

of the types of monitoring devices 

needed for implementation. We are also 

proposing in 40 CFR 60.106a to use the 

term ‘‘reduced sulfur compounds’’ 

when referring to the emission limits 

and monitoring devices needed to 

comply with the reduced sulfur 

compound emission limits for sulfur 

recovery plants with reduction control 

systems not followed by incineration. 

The term ‘‘reduced sulfur compounds’’ 

is a defined term in Refinery NSPS Ja, 

and the emissions limit for sulfur 

recovery plants with reduction control 

systems not followed by incineration is 

specific to ‘‘reduced sulfur 

compounds.’’ Therefore, the proposed 

amendments to the monitoring 

provisions provide clarification of the 

requirements by using a consistent, 

defined term. 

We are proposing amendments to 40 

CFR 60.102a(g)(1) to clarify that CO 

boilers, while part of the FCCU affected 

facility, can also be fuel gas combustion 

devices (FGCD). Industry Petitioners 

suggested that the CO boiler should only 

be subject to the FCCU NOX and SO2


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limits and should not be considered a 

FGCD. While Refinery NSPS Ja clearly 

states that the coke burn-off exhaust 

from the FCCU catalyst regenerator is 

not considered to be fuel gas, other fuels 

combusted in the CO boiler must meet 

the H2S concentration requirements for 

fuel gas like any other FGCD. This 

amendment is provided to clarify our 

original intent with respect to fuel gas. 

Industry Petitioners also noted that 

some CO boiler ‘‘furnaces’’ may be used 

as process heaters rather than steamgenerating boilers. While we did not 

originally contemplate that CO furnaces 

would be used as process heaters, 

available data from the detailed ICR 

suggests that there are a few CO 

furnaces used as process heaters. These 

CO furnaces are all forced-draft process 

heaters, and the newly amended NOX

emissions limit in Refinery NSPS Ja for 

forced-draft process heaters is 60 ppmv, 

averaged over a 30-day period. Given 

the longer averaging time of the process 

heater NOX limits, these two emission 

limits (for FCCU NOX and for process 

heater NOX) are reasonably comparable 

and are not expected to result in a 

significant difference in the control 

systems selected for compliance. As 

such, we are not amending or clarifying 

the NOX standards for the FCCU or 

process heaters at this time. We are, 

however, clarifying (through this 

response) that if an emission source 

meets the definition of more than one 

affected facility, that source would need 

to comply with all requirements 

applicable to the emissions source. 

We are proposing to revise the annual 

testing requirement in 40 CFR 

60.104a(b) to clarify our original intent. 

Instead of requiring a PM performance 

test at least once every 12 months, the 

rule would require a PM performance 

test annually and specify that annually 

means once per calendar year, with an 

interval of at least 8 months but no more 

than 16 months between annual tests. 

This provision will ensure that testing is 

conducted at a reasonable interval while 

giving owners and operators flexibility 

in scheduling the testing. We are also 

proposing to amend 40 CFR 60.104a(f) 

to clarify that the provisions of that 

paragraph are specific to owners or 

operators of an FCCU or FCU that use 

a cyclone to comply with the PM per 

coke burn-off emissions limit (rather 

than just the PM limit) in 40 CFR 

60.102a(b)(1), to clarify that facilities 

electing to comply with the 

concentration limit using a PM CEMS 

would not also be required to install a 

COMS. We are also proposing to amend 

40 CFR 60.104a(j) to delete the 

requirements to measure flow for the 

H2S concentration limit for fuel gas, as 

these are not needed in the performance 

evaluation. 

We are proposing amendments to 40 

CFR 60.105a(b)(1)(ii)(A) to require 

corrective action be completed to repair 

faulty (leaking or plugged) air or water 

lines within 12 hours of identification of 

an abnormal pressure reading during the 

daily checks. We are also proposing 

amendments to 40 CFR 60.105a(i) to 

include periods when abnormal 

pressure readings for a jet ejector-type 

wet scrubber (or other type of wet 

scrubber equipped with atomizing spray 

nozzles) are not corrected within 12 

hours of identification, and periods 

when a bag leak detection system alarm 

(for a fabric filter) is not alleviated 

within the time period specified in the 

rule. These proposed amendments are 

necessary so that periods when the 

APCD operation is compromised are 

properly managed and/or reported. 

We are proposing amendments to 40 

CFR 60.105(b)(1)(iv) and 

60.107a(b)(1)(iv) to allow using tubes 

with a maximum span between 10 and 

40 ppmv, inclusive, when 1≤N≤10, 

where N = number of pump strokes 

rather than requiring use of tubes with 

ranges 0–10/0–100 ppm (N = 10/1) 

because different length-of-stain tube 

manufacturers have different span 

ranges, and none of the commerciallyavailable tubes have a specific span of 

0–10/0–100 ppm (N = 10/1). We are also 

proposing to amend 40 CFR 

60.105(b)(3)(iii) and 40 CFR 

60.107a(b)(3)(iii) to specify that the 

temporary daily stain sampling must be 

made using length-of stain tubes with a 

maximum span between 200 and 400 

ppmv, inclusive, when 1≤N≤5, where N 

= number of pump strokes. This 

proposed amendment clarifies this 

monitoring requirement, ensures the 

proper tube range is used, and provides 

some flexibility in span range to 

accommodate different manufacturers of 

the length-of-stain tubes. We also 

propose to delete the last sentence in 40 

CFR 60.105(b)(3)(iii), as there is no longterm H2S concentration limit in Refinery 

NSPS J. 

We are proposing to clarify that flares 

are subject to the performance test 

requirements. We are also proposing to 

clarify those performance test 

requirements in 40 CFR 60.107a(e)(1)(ii) 

and 40 CFR 60.107a(e)(2)(ii) to remove 

the distinction between flares with or 

without routine flow. The term ‘‘routine 

flow’’ is not defined and it is difficult 

to make this distinction in practice. 

F. What compliance dates are we 

proposing? 

Amendments to Refinery MACT 1 and 

2 proposed in this rulemaking for 

adoption under CAA section 112(d)(2) 

and (3) and CAA section 112(d)(6) are 

subject to the compliance deadlines 

outlined in the CAA under section 

112(i). For all of the requirements we 

are proposing under CAA section 

112(d)(2) and (3) or CAA section 

112(d)(6) except for storage vessels, 

which we are also requiring under 112 

(f)(2), we are proposing the following 

compliance dates. As provided in CAA 

section 112(i), new sources would be 

required to comply with these 

requirements by the effective date of the 

final amendments to Refinery MACT 1 

and 2 or startup, whichever is later. 

For existing sources, CAA section 

112(i) provides that the compliance date 

shall be as expeditiously as practicable, 

but no later than 3 years after the 

effective date of the standard. In 

determining what compliance period is 

as expeditious as practicable, we 

consider the amount of time needed to 

plan and construct projects and change 

operating procedures. Under CAA 

section 112(d)(2) and (3), we are 

proposing new operating requirements 

for DCU. In order to comply with these 

new requirements, we project that most 

DCU owners or operators would need to 

install additional controls (e.g., steam 

ejector systems). Similarly, the proposed 

revision in the CRU pressure limit 

exclusions would require operational 

changes and, in some cases, additional 

controls. The addition of new control 

equipment would require engineering 

design, solicitation and review of 

vendor quotes, contracting and 

installation of the equipment, which 

would need to be timed with process 

unit outage and operator training. 

Therefore, we are proposing that it is 

necessary to provide 3 years after the 

effective date of the final rule for these 

sources to comply with the DCU and 

CRU requirements. 

We are proposing new operating and 

monitoring requirements for flares 

under CAA section 112(d)(2) and (3). 

We anticipate that these requirements 

would require the installation of new 

flare monitoring equipment and we 

project most refineries would install 

new control systems to monitor and 

adjust assist gas (air or steam) addition 

rates. Similar to the addition of new 

control equipment, these new 

monitoring requirements for flares 

would require engineering evaluations, 

solicitation and review of vendor 

quotes, contracting and installation of 

the equipment, and operator training. 


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Installation of new monitoring and 

control equipment on flares will require 

the flare to be taken out of service. 

Depending on the configuration of the 

flares and flare header system, taking 

the flare out of service may also require 

a significant portion of the refinery 

operations to be shut down. Therefore, 

we are proposing that it is necessary to 

provide 3 years after the effective date 

of the final rule for owners or operators 

to comply with the new operating and 

monitoring requirements for flares. 

Under CAA section 112(d)(2) and (3), 

we are proposing new vent control 

requirements for bypasses. These 

requirements would typically require 

the addition of piping and potentially 

new control requirements. As these vent 

controls would most likely be routed to 

the flare, we are proposing to provide 3 

years after the effective date of the final 

rule for owners or operators to afford 

coordination of these bypass 

modifications with the installation of 

the new monitoring equipment for the 

flares. 

Under our technology review, we are 

proposing to require fenceline 

monitoring pursuant to CAA section 

112(d)(6). These proposed provisions 

would require refinery owners or 

operators to install a number of 

monitoring stations around the facility 

fenceline. While the diffusive tube 

sampling system is relatively low-tech 

and is easy to install, site-specific 

factors must be considered in the 

placement of the monitoring systems. 

We also assume all refinery owners or 

operators would invest in the analytical 

equipment needed to perform 

automated sample analysis on-site and 

time is needed to select an appropriate 

vendor for this equipment. Furthermore, 

additional monitoring systems may be 

needed to account for near-field 

contributing sources, for which the 

development and approval of a sitespecific monitoring plan. Considering 

all of the requirements needed to 

implement the fenceline monitoring 

system, we are proposing to provide 3 

years from the effective date of the final 

rule for refinery owners or operators to 

install and begin collecting ambient air 

samples around the fenceline of their 

facility following an approved (if 

necessary) site-specific monitoring plan. 

As a result of our technology review 

for equipment leaks, we are proposing 

to allow the use of optical gas imaging 

devices in lieu of using EPA Method 21 

of 40 CFR part 60, Appendix A–7 

without the annual compliance 

demonstration with EPA Method 21 as 

required in the AWP (see 73 FR 73202, 

December 22, 2008), provided that the 

owner and operator follows the 

provisions of Appendix K to 40 CFR 

part 60. Facilities could begin to comply 

with the optical gas imaging alternative 

as soon as Appendix K to 40 CFR part 

60 is promulgated. Alternatively, as is 

currently provided in the AWP, the 

refinery owner or operator can elect to 

use the optical gas imaging monitoring 

option prior to installation and use of 

the fenceline monitoring system, 

provided they conduct an annual 

compliance demonstration using EPA 

Method 21 as required in the AWP. 

Under our technology review for 

marine vessel loading operations, we are 

proposing to add a requirement for 

submerged filling for small and for 

offshore marine vessel loading 

operations. We anticipate that the 

submerged fill pipes are already in place 

on all marine vessels used to transport 

petroleum refinery liquids, so we are 

proposing that existing sources comply 

with this requirement on the effective 

date of the final rule. We request 

comment regarding the need to provide 

additional time to comply with the 

submerged filling requirement; please 

provide in your comment a description 

of the vessels loaded that do not already 

have a submerged fill pipe, how these 

vessels comply with (or are exempt 

from) the Coast Guard requirements at 

46 CFR 153.282, and an estimate of the 

time needed to add the required 

submerged fill pipes to these vessels. 

We are also proposing to require 

FCCU owners and operators currently 

subject to Refinery NSPS J (or electing 

that compliance option in Refinery 

MACT 2) to transition from the Refinery 

NSPS J option to one of the alternatives 

included in the proposed rule. We are 

also proposing altering the averaging 

times for some of the operating limits. 

A PM performance test is needed in 

order to establish these new operating 

limits prior to transitioning to the 

proposed requirements. Additionally, 

we are proposing that a PM performance 

test be conducted for each FCCU once 

every 5 years. We do not project any 

new control or monitoring equipment 

will be needed in order to comply with 

the proposed provisions; however, 

compliance with the proposed 

provisions is dependent on conducting 

a performance test. Establishing an early 

compliance date for the first 

performance test can cause scheduling 

issues as refinery owners or operators 

compete for limited number of testing 

contractors. Considering these 

scheduling issues, we propose to require 

the first performance test for PM and 

compliance with the new operating 

limits be completed no later than 18 

months after the effective date of the 

final rule. 

In this action, we are proposing 

revisions to the SSM provisions of 

Refinery MACT 1 and 2, including 

specific startup or shutdown standards 

for certain emission sources, and we are 

proposing electronic reporting 

requirements in Refinery MACT 1 and 

2. The proposed monitoring 

requirements associated with the new 

startup and shutdown standards are 

expected to be present on the affected 

source, so we do not expect that owners 

or operators will need additional time to 

transition to these requirements. 

Similarly, the electronic reporting 

requirements are not expected to require 

a significant change in operation or 

equipment, so these requirements 

should be able to be implemented more 

quickly than those that require 

installation of new control or 

monitoring equipment. Based on our 

review of these requirements, we 

propose that these requirements become 

effective upon the effective date of the 

final rule. 

Finally, we are proposing additional 

requirements for storage vessels under 

CAA sections 112(d)(6) and (f)(2). The 

compliance deadlines for standards 

developed under CAA section 112(f)(2) 

are delineated in CAA sections 112(f)(3) 

and (4). As provided in CAA section 

112(f)(4), risk standards shall not apply 

to existing sources until 90 days after 

the effective date of the rule, but the 

Administrator may grant a waiver for a 

particular source for a period of up to 

2 years after the effective date. While 

additional controls will be necessary to 

comply with the proposed new control 

and fitting requirements for storage 

vessels, the timing for installation of 

these controls is specified within the 

Generic MACT (40 CFR part 63, subpart 

WW). Therefore, we propose that these 

new requirements for storage vessels 

become effective 90 days following the 

effective date of the final rule. 

V. Summary of Cost, Environmental 

and Economic Impacts 

A. What are the affected sources, the air 

quality impacts and cost impacts? 

The sources affected by significant 

amendments to the petroleum refinery 

standards include storage vessels, 

equipment leaks, fugitive emissions and 

DCU subject to Refinery MACT 1. The 

proposed amendments for other sources 

subject to one or more of the petroleum 

refinery standards are expected to have 

minimal air quality and cost impacts. 

The total capital investment cost of 

the proposed amendments and 

standards is estimated at $239 million, 

$82.8 million from proposed 

amendments and $156 million from 


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42The flare operational and monitoring 

requirements are projected to reduce methane 

emissions by 29,500 tpy while increasing CO2

emissions by 260,000 tpy, resulting in a net GHG 

reduction of 327,000 metric tonnes per year of 

CO2e, assuming a global warming potential of 21 for 

methane. Combined with methane emissions 

reduction of 18,000 tpy from the proposed controls 

on DCU, the overall GHG reductions of the 

proposed amendments is 670,000 metric tonnes per 

year of CO2e assuming a global warming potential 

of 21 for methane. 

standards to ensure compliance. We 

estimate annualized costs to be 

approximately $4.53 million, which 

includes an estimated $14.4 million 

credit for recovery of lost product and 

the annualized cost of capital. We also 

estimate annualized costs of the 

proposed standards to ensure 

compliance to be approximately $37.9 

million. The proposed amendments 

would achieve a nationwide HAP 

emission reduction of 1,760 tpy, with a 

concurrent reduction in VOC emissions 

of 18,800 tpy. Table 13 of this preamble 

summarizes the cost and emission 

reduction impacts of the proposed 

amendments, and Table 14 of this 

preamble summarizes the costs of the 

proposed standards to ensure 

compliance. 

TABLE 13—NATIONWIDE IMPACTS OF PROPOSED AMENDMENTS

Affected source 

Total capital 

investment 

(million $) 

Total annualized 

cost without credit (million $/yr) 

Product recovery credit (million $/yr) Total annualized costs (million $/yr) VOC emission 

reductions (tpy) 

Cost effectiveness 

($/ton VOC) 

HAP emission 

reductions (tpy) 

Cost effectiveness 

($/ton HAP) 

Storage Vessels .......................... 18.5 3 .13 (8.16) (5.03) 14,600 (345) 910 (5,530) 

Delayed Coking Units ................. 52.0 10 .2 (6.20) 3.98 4,250 937 850 4,680 

Fugitive Emissions (Fenceline 

Monitoring) ............................... 12.2 5 .58 ............................ 5.58 ............................ ............................ ............................ ............................

Total ..................................... 82.8 18 .9 (14.4) 4.53 18,800 241 1,760 2,570 

TABLE 14—NATIONWIDE COSTS OF PROPOSED AMENDMENTS TO ENSURE COMPLIANCE

Affected source 

Total capital 

investment 

(million $) 

Total 

annualized cost 

without credit 

(million $/yr) 

Product 

recovery credit 

(million $/yr) 

Total 

annualized 

costs 

(million $/yr) 

Relief Valve Monitoring .............................................................................. 9 .54 1 .36 ........................ 1 .36 

Flare Monitoring ......................................................................................... 147 36 .3 ........................ 36 .3 

FCCU Testing ............................................................................................ — 0 .21 ........................ 0 .21 

Total .................................................................................................... 156 37 .9 — 37 .9 

Note that any corrective actions taken 

in response to the fenceline monitoring 

program are not included in the impacts 

shown in Table 13. Any corrective 

actions associated with fenceline 

monitoring will result in additional 

emission reductions and additional 

costs. 

The impacts shown in Table 14 do not 

consider emission reductions associated 

with relief valve or flare monitoring 

provisions or emission reductions that 

may occur as a result of the additional 

FCCU testing requirements. The 

proposed operational and monitoring 

requirements for flares at refineries have 

the potential to reduce excess emissions 

from flares by approximately 3,800 tpy 

of HAP, 33,000 tpy of VOC, and 327,000 

metric tonnes per year of CO2e. When 

added to the reductions in CO2e 

achieved from proposed controls on 

DCU, these proposed amendments are 

projected to result in reductions of 

670,000 metric tonnes of CO2e due to 

reductions of methane emissions.42

B. What are the economic impacts? 

We performed a national economic 

impact analysis for petroleum product 

producers. All petroleum product 

refiners will incur annual compliance 

costs of much less than 1 percent of 

their sales. For all firms, the minimum 

cost-to-sales ratio is <0.01 percent; the 

maximum cost-to-sales ratio is 0.87 

percent; and the mean cost-to-sales ratio 

is 0.03 percent. Therefore, the overall 

economic impact of this proposed rule 

should be minimal for the refining 

industry and its consumers. 

In addition, the EPA performed a 

screening analysis for impacts on small 

businesses by comparing estimated 

annualized engineering compliance 

costs at the firm-level to firm sales. The 

screening analysis found that the ratio 

of compliance cost to firm revenue falls 

below 1 percent for the 28 small 

companies likely to be affected by the 

proposal. For small firms, the minimum 

cost-to-sales ratio is <0.01 percent; the 

maximum cost-to-sales ratio is 0.62 

percent; and the mean cost-to-sales ratio 

is 0.07 percent. 

More information and details of this 

analysis are provided in the technical 

document Economic Impact Analysis 

for Petroleum Refineries Proposed 

Amendments to the National Emissions 

Standards for Hazardous Air Pollutants, 

which is available in the docket for this 

proposed rule (Docket ID Number EPA– 

HQ–OAR–2010–0682). 

C. What are the benefits? 

The proposed rule is anticipated to 

result in a reduction of 1,760 tons of 

HAP (based on allowable emissions 

under the MACT standards) and 18,800 

tons of VOC emissions per year, not 

including potential emission reductions 

that may occur as a result of the 

proposed provisions for flares or 

fenceline monitoring. These avoided 

emissions will result in improvements 

in air quality and reduced negative 

health effects associated with exposure 

to air pollution of these emissions; 

however, we have not quantified or 

monetized the benefits of reducing these 

emissions for this rulemaking. 

VI. Request for Comments 

We solicit comments on all aspects of 

this proposed action. In addition to 

general comments on this proposed 

action, we are also interested in 

additional data that may improve the 

risk assessments and other analyses. We 

are specifically interested in receiving 

any improvements to the data used in 

the site-specific emissions profiles used 

for risk modeling. Such data should 

include supporting documentation in 

sufficient detail to allow 

characterization of the quality and 

representativeness of the data or 

information. Section VII of this 

preamble provides more information on 

submitting data. 


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VII. Submitting Data Corrections 

The site-specific emissions profiles 

used in the source category risk and 

demographic analyses and instructions 

are available on the RTR Web page at: 

http://www.epa.gov/ttn/atw/rrisk/

rtrpg.html. The data files include 

detailed information for each HAP 

emissions release point for the facilities 

in the source categories. 

If you believe that the data are not 

representative or are inaccurate, please 

identify the data in question, provide 

your reason for concern and provide any 

‘‘improved’’ data that you have, if 

available. When you submit data, we 

request that you provide documentation 

of the basis for the revised values to 

support your suggested changes. To 

submit comments on the data 

downloaded from the RTR page, 

complete the following steps: 

1. Within this downloaded file, enter 

suggested revisions to the data fields 

appropriate for that information. 

2. Fill in the commenter information 

fields for each suggested revision (i.e., 

commenter name, commenter 

organization, commenter email address, 

commenter phone number and revision 

comments). 

3. Gather documentation for any 

suggested emissions revisions (e.g., 

performance test reports, material 

balance calculations). 

4. Send the entire downloaded file 

with suggested revisions in Microsoft®

Access format and all accompanying 

documentation to Docket ID Number 

EPA–HQ–OAR–2010–0682 (through one 

of the methods described in the 

ADDRESSES section of this preamble). 

5. If you are providing comments on 

a single facility or multiple facilities, 

you need only submit one file for all 

facilities. The file should contain all 

suggested changes for all sources at that 

facility. We request that all data revision 

comments be submitted in the form of 

updated Microsoft® Excel files that are 

generated by the Microsoft® Access file. 

These files are provided on the RTR 

Web page at: http://www.epa.gov/ttn/

atw/rrisk/rtrpg.html. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is a 

‘‘significant regulatory action’’ because 

it raises novel legal and policy issues. 

Accordingly, the EPA submitted this 

action to the Office of Management and 

Budget (OMB) for review under 

Executive Orders 12866 and 13563 (76 

FR 3821, January 21, 2011) and any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this action 

(Docket ID Number EPA–HQ–OAR– 

2010–0682). 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule have been 

submitted for approval to OMB under 

the Paperwork Reduction Act, 44 U.S.C. 

3501, et seq. 

Revisions and burden associated with 

amendments to 40 CFR part 63, subparts 

CC and UUU are discussed in the 

following paragraphs. OMB has 

previously approved the information 

collection requirements contained in the 

existing regulations in 40 CFR part 63, 

subparts CC and UUU under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501, et seq., OMB 

control numbers for the EPA’s 

regulations in 40 CFR are listed in 40 

CFR part 9. Burden is defined at 5 CFR 

1320.3(b). 

The ICR document prepared by the 

EPA for the amendments to the 

Petroleum Refinery MACT standards for 

40 CFR part 63, subpart CC has been 

assigned the EPA ICR number 1692.08. 

Burden changes associated with these 

amendments would result from new 

monitoring, recordkeeping and 

reporting requirements. The estimated 

annual increase in recordkeeping and 

reporting burden hours is 53,619 hours; 

the frequency of response is semiannual 

for all reports for all respondents that 

must comply with the rule’s reporting 

requirements; and the estimated average 

number of likely respondents per year is 

95 (this is the average in the second 

year). The cost burden to respondents 

resulting from the collection of 

information includes the total capital 

cost annualized over the equipment’s 

expected useful life (about $17 million, 

which includes monitoring equipment 

for bypass valves, fenceline monitoring, 

relief valves, and flares), a total 

operation and maintenance component 

(about $16 million per year for fenceline 

and flare monitoring), and a labor cost 

component (about $4.5 million per year, 

the cost of the additional 53,619 labor 

hours). An agency may not conduct or 

sponsor (and a person is not required to 

respond to) a collection of information 

unless it displays a currently-valid OMB 

control number. 

The ICR document prepared by the 

EPA for the amendments to the 

Petroleum Refinery MACT standards for 

40 CFR part 63, subpart UUU has been 

assigned the EPA ICR number 1844.07. 

Burden changes associated with these 

amendments would result from new 

testing, recordkeeping and reporting 

requirements being proposed with this 

action. The estimated average burden 

per response is 26 hours; the frequency 

of response is both once and every 5 

years for respondents that have FCCU, 

and the estimated average number of 

likely respondents per year is 67. The 

cost burden to respondents resulting 

from the collection of information 

includes the performance testing costs 

(approximately $356,000 per year over 

the first 3 years for the initial 

performance test and $213,000 per year 

starting in the fourth year), and a labor 

cost component (approximately 

$238,000 per year for 2,860 additional 

labor hours). An agency may not 

conduct or sponsor (and a person is not 

required to respond to) a collection of 

information unless it displays a 

currently-valid OMB control number. 

To comment on the agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public docket for this rule, 

which includes the ICR, under Docket 

ID Number EPA–HQ–OAR–2010–0682. 

Submit any comments related to the ICR 

to the EPA and OMB. See the ADDRESSES

section at the beginning of this preamble 

for where to submit comments to the 

EPA. Send comments to OMB at the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street NW., 

Washington, DC 20503, Attention: Desk 

Office for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

June 30, 2014, a comment to OMB is 

best assured of having its full effect if 

OMB receives it by July 30, 2014. The 

final rule will respond to any OMB or 

public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute, unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities (SISNOSE). 

Small entities include small businesses, 

small organizations and small 

governmental jurisdictions. For 

purposes of assessing the impacts of this 

proposed rule on small entities, a small 

entity is defined as: (1) A small business 

in the petroleum refining industry 


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having 1,500 or fewer employees (Small 

Business Administration (SBA), 2011); 

(2) a small governmental jurisdiction 

that is a government of a city, county, 

town, school district or special district 

with a population of less than 50,000; 

and (3) a small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The small entities subject to the 

requirements of this proposed rule are 

small refiners. We have determined that 

36 companies (59 percent of the 61 

total) employ fewer than 1,500 workers 

and are considered to be small 

businesses. For small businesses, the 

average cost-to-sales ratio is about 0.05 

percent, the median cost-to-sales ratio is 

0.02 percent and the maximum cost-tosales ratio is 0.55 percent. The potential 

costs do not have a more significant 

impact on small refiners and because no 

small firms are expected to have cost-tosales ratios greater than 1 percent, we 

determined that the cost impacts for this 

rulemaking will not have a SISNOSE. 

Although not required by the RFA to 

convene a Small Business Advocacy 

Review (SBAR) Panel; because the EPA 

has determined that this proposal would 

not have a significant economic impact 

on a substantial number of small 

entities, the EPA originally convened a 

panel to obtain advice and 

recommendations from small entity 

representatives potentially subject to 

this rule’s requirements. The panel was 

not formally concluded; however, a 

summary of the outreach conducted and 

the written comments submitted by the 

small entity representatives can be 

found in the docket for this proposed 

rule (Docket ID Number EPA–HQ–OAR– 

2010–0682). 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

This proposed rule does not contain 

a federal mandate under the provisions 

of Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538 that may result in 

expenditures of $100 million or more 

for state, local and tribal governments, 

in the aggregate, or the private sector in 

any one year. As discussed earlier in 

this preamble, these amendments result 

in nationwide costs of $42.4 million per 

year for the private sector. Thus, this 

proposed rule is not subject to the 

requirements of sections 202 or 205 of 

the UMRA. 

This proposed rule is also not subject 

to the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments 

because it contains no requirements that 

apply to such governments and does not 

impose obligations upon them. 

E. Executive Order 13132: Federalism 

This rule does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. None of the 

facilities subject to this action are 

owned or operated by state 

governments, and, because no new 

requirements are being promulgated, 

nothing in this proposal will supersede 

state regulations. Thus, Executive Order 

13132 does not apply to this rule. 

In the spirit of Executive Order 13132, 

and consistent with the EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed rule from state and 

local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It will not have substantial direct 

effects on tribal governments, on the 

relationship between the federal 

government and Indian tribes, or on the 

distribution of power and 

responsibilities between the federal 

government and Indian tribes as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this action. 

Although Executive Order 13175 does 

not apply to this action, the EPA 

consulted with tribal officials in 

developing this action. The EPA sent 

out letters to tribes nationwide to invite 

them to participate in a tribal 

consultation meeting and solicit their 

input on this rulemaking. The EPA 

conducted the tribal consultation 

meeting on December 14, 2011. 

Participants from eight tribes attended 

the meeting, but they were interested 

only in outreach, and none of the tribes 

had delegation for consultation. The 

EPA presented all the information 

prepared for the consultation and 

conducted a question and answer 

session where participants asked 

clarifying questions about the 

information that was presented and 

generally expressed their support of the 

rulemaking requirements. 

The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 (62 FR 19885, April 23, 

1997) because it is not economically 

significant as defined in Executive 

Order 12866, and because the agency 

does not believe the environmental 

health or safety risks addressed by this 

action present a disproportionate risk to 

children. This action’s health and risk 

assessments are contained in sections 

III.A and B and sections IV.C and D of 

this preamble. 

The public is invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

early life exposure to emissions from 

petroleum refineries. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined under 

Executive Order 13211 (66 FR 28355, 

May 22, 2001), because it is not likely 

to have significant adverse effect on the 

supply, distribution or use of energy. 

The overall economic impact of this 

proposed rule should be minimal for the 

refining industry and its consumers. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law No. 

104–113, 12(d) (15 U.S.C. 272 note) 

directs the EPA to use voluntary 

consensus standards (VCS) in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures, and business practices) that 

are developed or adopted by VCS 

bodies. The NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the agency decides 

not to use available and applicable VCS. 

This proposed rulemaking involves 

technical standards. The EPA proposes 

to use ISO 16017–2, ‘‘Air quality 

Sampling and analysis of volatile 

organic compounds in ambient air, 


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indoor air and workplace air by sorbent 

tube/thermal desorption/capillary gas 

chromatography Part 2: Diffusive 

sampling’’ as an acceptable alternative 

to EPA Method 325A. This method is 

available at http://www.iso.org. This 

method was chosen because it meets the 

requirements of EPA Method 301 for 

equivalency, documentation and 

validation data for diffusive tube 

sampling. 

The EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable VCS and 

to explain why such standards should 

be used in this regulation. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations because it maintains or 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 

high and adverse human health or 

environmental effects on any 

population, including any minority, 

low-income or indigenous populations. 

Further, the EPA believes that 

implementation of the provisions of this 

rule will provide an ample margin of 

safety to protect public health of all 

demographic groups. 

To examine the potential for any 

environmental justice issues that might 

be associated with the refinery source 

categories associated with today’s 

proposed rule, we evaluated the 

percentages of various social, 

demographic and economic groups 

within the at-risk populations living 

near the facilities where these source 

categories are located and compared 

them to national averages. Our analysis 

of the demographics of the population 

with estimated risks greater than 1-in-1 

million indicates potential disparities in 

risks between demographic groups, 

including the African American, Other 

and Multiracial, Hispanic, Below the 

Poverty Level, and Over 25 without a 

High School Diploma groups. In 

addition, the population living within 

50 km of the 142 petroleum refineries 

has a higher percentage of minority, 

lower income and lower education 

persons when compared to the 

nationwide percentages of those groups. 

These groups stand to benefit the most 

from the emission reductions achieved 

by this proposed rulemaking, and this 

proposed rulemaking is projected to 

result in 1 million fewer people exposed 

to risks greater than 1-in-1 million. 

The EPA defines ‘‘Environmental 

Justice’’ to include meaningful 

involvement of all people regardless of 

race, color, national origin or income 

with respect to the development, 

implementation and enforcement of 

environmental laws, regulations and 

policies. To promote meaningful 

involvement, the EPA conducted 

numerous outreach activities and 

discussions, including targeted outreach 

(such as conference calls and Webinars) 

to communities and environmental 

justice organizations. In addition, after 

the rule is proposed, the EPA will be 

conducting a webinar to inform the 

public about the proposed rule and to 

outline how to submit written 

comments to the docket. Further 

stakeholder and public input is 

expected through public comment and 

follow-up meetings with interested 

stakeholders. 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 63 

Environmental protection, Air 

pollution control, Hazardous 

substances, Incorporation by reference, 

Reporting and recordkeeping 

requirements, Volatile organic 

compounds. 

Dated: May 15, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart J—[AMENDED] 

■ 2. Section 60.105 is amended by: 

■ a. Revising paragraph (b)(1)(iv) and 

■ b. Revising paragraph (b)(3)(iii) to 

read as follows: 

§ 60.105 Monitoring of emissions and 

operations. 

* * * * * 

(b) * * * 

(1) * * * 

(iv) The supporting test results from 

sampling the requested fuel gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppmv. Sampling 

data must include, at minimum, 2 

weeks of daily monitoring (14 grab 

samples) for frequently operated fuel gas 

streams/systems; for infrequently 

operated fuel gas streams/systems, 

seven grab samples must be collected 

unless other additional information 

would support reduced sampling. The 

owner or operator shall use detector 

tubes (‘‘length-of-stain tube’’ type 

measurement) following the ‘‘Gas 

Processors Association Standard 2377– 

86, Test for Hydrogen Sulfide and 

Carbon Dioxide in Natural Gas Using 

Length of Stain Tubes,’’ 1986 Revision 

(incorporated by reference—see § 60.17), 

using tubes with a maximum span 

between 10 and 40 ppmv inclusive 

when 1≤N≤10, where N = number of 

pump strokes, to test the applicant fuel 

gas stream for H2S; and 

* * * * * 

(3) * * * 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application and the owner or 

operator chooses not to submit new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance using lengthof-stain tubes with a maximum span 

between 200 and 400 ppmv inclusive 

when 1≤N≤5, where N = number of 

pump strokes. The owner or operator 

must begin monitoring according to the 

requirements in paragraphs (a)(1) or 

(a)(2) of this section as soon as 

practicable but in no case later than 180 

days after the operation change. During 

daily stain tube sampling, a daily 

sample exceeding 162 ppmv is an 


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exceedance of the 3-hour H2S 

concentration limit. 

* * * * * 

Subpart Ja—[AMENDED] 

■ 3. Section 60.100a is amended by 

revising the first sentence of paragraph 

(b) to read as follows: 

§ 60.100a Applicability, designation of 

affected facility, and reconstruction. 

* * * * * 

(b) Except for flares, the provisions of 

this subpart apply only to affected 

facilities under paragraph (a) of this 

section which either commence 

construction, modification or 

reconstruction after May 14, 2007, or 

elect to comply with the provisions of 

this subpart in lieu of complying with 

the provisions in subpart J of this 

part. * * * 

■ 4. Section 60.101a is amended by: 

■ a. Revising the definition of 

‘‘Corrective action’’; and 

■ b. Adding, in alphabetical order, a 

definition for ‘‘Sour water’’ to read as 

follows: 

§ 60.101a Definitions. 

* * * * * 

Corrective action means the design, 

operation and maintenance changes that 

one takes consistent with good 

engineering practice to reduce or 

eliminate the likelihood of the 

recurrence of the primary cause and any 

other contributing cause(s) of an event 

identified by a root cause analysis as 

having resulted in a discharge of gases 

from an affected facility in excess of 

specified thresholds. 

* * * * * 

Sour water means water that contains 

sulfur compounds (usually H2S) at 

concentrations of 10 parts per million 

by weight or more. 

* * * * * 

■ 5. Section 60.102a is amended by: 

■ a. Revising paragraphs (b)(1)(i) and 

(iii); 

■ b. Revising paragraph (f); and 

■ c. Revising paragraph (g)(1). 

The revisions read as follows: 

§ 60.102a Emissions limitations. 

* * * * * 

(b) * * * 

(1) * * * 

(i) 1.0 gram per kilogram (g/kg) (1 

pound (lb) per 1,000 lb) coke burn-off 

or, if a PM continuous emission 

monitoring system (CEMS) is used, 

0.040 grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent excess 

air for each modified or reconstructed 

FCCU. 

* * * * * 

(iii) 1.0 g/kg (1 lb/1,000 lb) coke burnoff or, if a PM CEMS is used, 0.040 grain 

per dry standard cubic feet (gr/dscf) 

corrected to 0 percent excess air for each 

affected FCU. 

* * * * * 

(f) Except as provided in paragraph 

(f)(3), each owner or operator of an 

affected sulfur recovery plant shall 

comply with the applicable emission 

limits in paragraphs (f)(1) or (2) of this 

section. 

(1) For a sulfur recovery plant with a 

design production capacity greater than 

20 long tons per day (LTD), the owner 

or operator shall comply with the 

applicable emission limit in paragraphs 

(f)(1)(i) or (f)(1)(ii) of this section. If the 

sulfur recovery plant consists of 

multiple process trains or release points, 

the owner or operator shall comply with 

the applicable emission limit for each 

process train or release point 

individually or comply with the 

applicable emission limit in paragraphs 

(f)(1)(i) or (f)(1)(ii) of this section as a 

flow rate weighted average for a group 

of release points from the sulfur 

recovery plant provided that flow is 

monitored as specified in 

§ 60.106a(a)(7); if flow is not monitored 

as specified in § 60.106a(a)(7), the 

owner or operator shall comply with the 

applicable emission limit in paragraphs 

(f)(1)(i) or (f)(1)(ii) of this section for 

each process train or release point 

individually. For a sulfur recovery plant 

with a design production capacity 

greater than 20 long LTD and a 

reduction control system not followed 

by incineration, the owner or operator 

shall also comply with the H2S emission 

limit in paragraph (f)(1)(iii) of this 

section for each individual release 

point. 

(i) For a sulfur recovery plant with an 

oxidation control system or a reduction 

control system followed by incineration, 

the owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere (SO2) in 

excess of the emission limit calculated 

using Equation 1 of this section. For 

Claus units that use only ambient air in 

the Claus burner or that elect not to 

monitor O2 concentration of the air/

oxygen mixture used in the Claus 

burner or for non-Claus sulfur recovery 

plants, this SO2 emissions limit is 250 

ppmv (dry basis) at zero percent excess 

air. 

Where: 

ELS = Emission limit for large sulfur recovery 

plant, ppmv (as SO2, dry basis at zero 

percent excess air); 

k1 = Constant factor for emission limit 

conversion: k1 = 1 for converting to the 

SO2 limit for a sulfur recovery plant with 

an oxidation control system or a 

reduction control system followed by 

incineration and k1 = 1.2 for converting 

to the reduced sulfur compounds limit 

for a sulfur recovery plant with a 

reduction control system not followed by 

incineration; and 

%O2 = O2 concentration of the air/oxygen 

mixture supplied to the Claus burner, 

percent by volume (dry basis). If only 

ambient air is used for the Claus burner 

or if the owner or operator elects not to 

monitor O2 concentration of the air/

oxygen mixture used in the Claus burner 

or for non-Claus sulfur recovery plants, 

use 20.9% for %O2. 

(ii) For a sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing reduced sulfur 

compounds in excess of the emission 

limit calculated using Equation 1 of this 

section. For Claus units that use only 

ambient air in the Claus burner or for 

non-Claus sulfur recovery plants, this 

reduced sulfur compounds emission 

limit is 300 ppmv calculated as ppmv 

SO2 (dry basis) at 0-percent excess air. 

(iii) For a sulfur recovery plant with 

a reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing hydrogen sulfide 

(H2S) in excess of 10 ppmv calculated 

as ppmv SO2 (dry basis) at zero percent 

excess air. 

(2) For a sulfur recovery plant with a 

design production capacity of 20 LTD or 

less, the owner or operator shall comply 

with the applicable emission limit in 

paragraphs (f)(2)(i) or (f)(2)(ii) of this 

section. If the sulfur recovery plant 

consists of multiple process trains or 

release points, the owner or operator 

may comply with the applicable 

emission limit for each process train or 

release point individually or comply 

with the applicable emission limit in 

paragraphs (f)(2)(i) or (f)(2)(ii) of this 


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section as a flow rate weighted average 

for a group of release points from the 

sulfur recovery plant provided that flow 

is monitored as specified in 

§ 60.106a(a)(7); if flow is not monitored 

as specified in § 60.106a(a)(7), the 

owner or operator shall comply with the 

applicable emission limit in paragraphs 

(f)(2)(i) or (f)(2)(ii) of this section for 

each process train or release point 

individually. For a sulfur recovery plant 

with a design production capacity of 20 

LTD or less and a reduction control 

system not followed by incineration, the 

owner or operator shall also comply 

with the H2S emission limit in 

paragraph (f)(2)(iii) of this section for 

each individual release point. 

(i) For a sulfur recovery plant with an 

oxidation control system or a reduction 

control system followed by incineration, 

the owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere containing 

SO2 in excess of the emission limit 

calculated using Equation 2 of this 

section. For Claus units that use only 

ambient air in the Claus burner or that 

elect not to monitor O2 concentration of 

the air/oxygen mixture used in the 

Claus burner or for non-Claus sulfur 

recovery plants, this SO2 emission limit 

is 2,500 ppmv (dry basis) at zero percent 

excess air. 

Where: 

ESS = Emission limit for small sulfur recovery 

plant, ppmv (as SO2, dry basis at zero 

percent excess air); 

k1 = Constant factor for emission limit 

conversion: k1 = 1 for converting to the 

SO2 limit for a sulfur recovery plant with 

an oxidation control system or a 

reduction control system followed by 

incineration and k1 = 1.2 for converting 

to the reduced sulfur compounds limit 

for a sulfur recovery plant with a 

reduction control system not followed by 

incineration; and 

%O2 = O2 concentration of the air/oxygen 

mixture supplied to the Claus burner, 

percent by volume (dry basis). If only 

ambient air is used in the Claus burner 

or if the owner or operator elects not to 

monitor O2 concentration of the air/

oxygen mixture used in the Claus burner 

or for non-Claus sulfur recovery plants, 

use 20.9% for %O2. 

(ii) For a sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing reduced sulfur 

compounds in excess of the emission 

limit calculated using Equation 2 of this 

section. For Claus units that use only 

ambient air in the Claus burner or for 

non-Claus sulfur recovery plants, this 

reduced sulfur compounds emission 

limit is 3,000 ppmv calculated as ppmv 

SO2 (dry basis) at zero percent excess 

air. 

(iii) For a sulfur recovery plant with 

a reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing H2S in excess of 

100 ppmv calculated as ppmv SO2 (dry 

basis) at zero percent excess air. 

(3) The emission limits in paragraphs 

(f)(1) and (2) shall not apply during 

periods of maintenance of the sulfur pit, 

which shall not exceed 240 hours per 

year. The owner or operator must 

document the time periods during 

which the sulfur pit vents were not 

controlled and measures taken to 

minimize emissions during these 

periods. Examples of these measures 

include not adding fresh sulfur or 

shutting off vent fans. 

(g) * * * 

(1) Except as provided in (g)(1)(iii) of 

this section, for each fuel gas 

combustion device, the owner or 

operator shall comply with either the 

emission limit in paragraph (g)(1)(i) of 

this section or the fuel gas concentration 

limit in paragraph (g)(1)(ii) of this 

section. For CO boilers or furnaces that 

are part of a fluid catalytic cracking unit 

or fluid coking unit affected facility, the 

owner or operator shall comply with the 

fuel gas concentration limit in 

paragraph (g)(1)(ii) of this section for all 

fuel gas streams combusted in these 

units. 

* * * * * 

■ 6. Section 60.104a is amended by: 

■ a. Revising the first sentence of 

paragraph (a); 

■ b. Revising paragraph (b); 

■ c. Revising paragraph (f) introductory 

text; 

■ d. Revising paragraph (h) introductory 

text; 

■ e. Adding paragraph (h)(6); and 

■ f. Removing and reserving paragraphs 

(j)(1) through (3). 

The revisions and additions read as 

follows: 

§ 60.104a Performance tests. 

* * * * * 

(a) The owner or operator shall 

conduct a performance test for each 

FCCU, FCU, sulfur recovery plant and 

fuel gas combustion device to 

demonstrate initial compliance with 

each applicable emissions limit in 

§ 60.102a and conduct a performance 

test for each flare to demonstrate initial 

compliance with the H2S concentration 

requirement in § 60.103a(h) according to 

the requirements of § 60.8. * * * 

(b) The owner or operator of a FCCU 

or FCU that elects to monitor control 

device operating parameters according 

to the requirements in § 60.105a(b), to 

use bag leak detectors according to the 

requirements in § 60.105a(c), or to use 

COMS according to the requirements in 

§ 60.105a(e) shall conduct a PM 

performance test at least annually (i.e., 

once per calendar year, with an interval 

of at least 8 months but no more than 

16 months between annual tests) and 

furnish the Administrator a written 

report of the results of each test. 

* * * * * 

(f) The owner or operator of an FCCU 

or FCU that uses cyclones to comply 

with the PM per coke burn-off emissions 

limit in § 60.102a(b)(1) shall establish a 

site-specific opacity operating limit 

according to the procedures in 

paragraphs (f)(1) through (3) of this 

section. 

* * * * * 

(h) The owner or operator shall 

determine compliance with the SO2

emissions limits for sulfur recovery 

plants in §§ 60.102a(f)(1)(i) and 

60.102a(f)(2)(i) and the reduced sulfur 

compounds and H2S emissions limits 

for sulfur recovery plants in 

§§ 60.102a(f)(1)(ii), 60.102a(f)(1)(iii), 

60.102a(f)(2)(ii) and 60.102a(f)(2)(iii) 

using the following methods and 

procedures: 

* * * * * 

(6) If oxygen or oxygen-enriched air is 

used in the Claus burner and either 

Equation 1 or 2 of this subpart is used 

to determine the applicable emissions 

limit, determine the average O2

concentration of the air/oxygen mixture 

supplied to the Claus burner, in percent 

by volume (dry basis), for the 

performance test using all hourly 

average O2 concentrations determined 

during the test runs using the 

procedures in § 60.106a(a)(5) or (6). 

* * * * * 

■ 7. Section 60.105a is amended by: 

■ a. Revising paragraph (b)(1)(i); 

■ b. Revising paragraph (b)(1)(ii)(A); 


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■ c. Revising paragraph (b)(2); 

■ d. Revising paragraph (h)(1); 

■ e. Revising paragraph (h)(3)(i); 

■ f. Revising paragraph (i)(1); 

■ g. Redesignating paragraphs (i)(2) 

through (6) as (i)(3) through (7); 

■ h. Adding paragraph (i)(2); and 

■ i. Revising newly redesignated 

paragraph (i)(7). 

The revisions and additions read as 

follows: 

§ 60.105a Monitoring of emissions and 

operations for fluid catalytic cracking units 

(FCCU) and fluid coking units (FCU). 

* * * * * 

(b) * * * 

(1) * * * 

(i) For units controlled using an 

electrostatic precipitator, the owner or 

operator shall use CPMS to measure and 

record the hourly average total power 

input and secondary current to the 

entire system. 

(ii) * * * 

(A) As an alternative to pressure drop, 

the owner or operator of a jet ejector 

type wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles must conduct a daily check of 

the air or water pressure to the spray 

nozzles and record the results of each 

check. Faulty (e.g., leaking or plugged) 

air or water lines must be repaired 

within 12 hours of identification of an 

abnormal pressure reading. 

* * * * * 

(2) For use in determining the coke 

burn-off rate for an FCCU or FCU, the 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring the 

concentrations of CO2, O2 (dry basis), 

and if needed, CO in the exhaust gases 

prior to any control or energy recovery 

system that burns auxiliary fuels. A CO 

monitor is not required for determining 

coke burn-off rate when no auxiliary 

fuel is burned and a continuous CO 

monitor is not required in accordance 

with § 60.105a(h)(3). 

(i) The owner or operator shall install, 

operate, and maintain each CO2 and O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each CO2 and O2 monitor according to 

the requirements in § 60.13(c) and 

Performance Specification 3 of 

Appendix B to part 60. The owner or 

operator shall use Method 3 of 

Appendix A–3 to part 60 for conducting 

the relative accuracy evaluations. 

(iii) If a CO monitor is required, the 

owner or operator shall install, operate, 

and maintain each CO monitor 

according to Performance Specification 

4 or 4A of Appendix B to part 60. If this 

CO monitor also serves to demonstrate 

compliance with the CO emissions limit 

in § 60.102a(b)(4), the span value for 

this instrument is 1,000 ppm; otherwise, 

the span value for this instrument 

should be set at approximately 2 times 

the typical CO concentration expected 

in the FCCU of FCU flue gas prior to any 

emission control or energy recovery 

system that burns auxiliary fuels. 

(iv) If a CO monitor is required, the 

owner or operator shall conduct 

performance evaluations of each CO 

monitor according to the requirements 

in § 60.13(c) and Performance 

Specification 4 of Appendix B to part 

60. The owner or operator shall use 

Method 10, 10A, or 10B of Appendix A– 

3 to part 60 for conducting the relative 

accuracy evaluations. 

(v) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 of 

Appendix F to part 60, including 

quarterly accuracy determinations for 

CO2 and CO monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

* * * * * 

(h) * * * 

(1) The owner or operator shall 

install, operate, and maintain each CO 

monitor according to Performance 

Specification 4 or 4A of appendix B to 

part 60. The span value for this 

instrument is 1,000 ppmv CO. 

* * * * * 

(3) * * * 

(i) The demonstration shall consist of 

continuously monitoring CO emissions 

for 30 days using an instrument that 

meets the requirements of Performance 

Specification 4 or 4A of appendix B to 

part 60. The span value shall be 100 

ppmv CO instead of 1,000 ppmv, and 

the relative accuracy limit shall be 10 

percent of the average CO emissions or 

5 ppmv CO, whichever is greater. For 

instruments that are identical to Method 

10 of appendix A–4 to part 60 and 

employ the sample conditioning system 

of Method 10A of appendix A–4 to part 

60, the alternative relative accuracy test 

procedure in section 10.1 of 

Performance Specification 2 of 

appendix B to part 60 may be used in 

place of the relative accuracy test. 

* * * * * 

(i) * * * 

(1) If a CPMS is used according to 

§ 60.105a(b)(1), all 3-hour periods 

during which the average PM control 

device operating characteristics, as 

measured by the continuous monitoring 

systems under § 60.105a(b)(1), fall 

below the levels established during the 

performance test. If the alternative to 

pressure drop CPMS is used for the 

owner or operator of a jet ejector type 

wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles, each day in which abnormal 

pressure readings are not corrected 

within 12 hours of identification. 

(2) If a bag leak detection system is 

used according to § 60.105a(c), each day 

in which the cause of an alarm is not 

alleviated within the time period 

specified in § 60.105a(c)(3). 

* * * * * 

(7) All 1-hour periods during which 

the average CO concentration as 

measured by the CO continuous 

monitoring system under § 60.105a(h) 

exceeds 500 ppmv or, if applicable, all 

1-hour periods during which the 

average temperature and O2

concentration as measured by the 

continuous monitoring systems under 

§ 60.105a(h)(4) fall below the operating 

limits established during the 

performance test. 

* * * * * 

■ 8. Section 60.106a is amended by: 

■ a. Revising paragraph (a)(1)(i); 

■ b. Adding paragraphs (a)(1)(iv) 

through (vii); 

■ c. Revising paragraph (a)(2) 

introductory text; 

■ d. Revising paragraphs (a)(2)(i) and 

(ii); 

■ e. Revising the first sentence of 

paragraph (a)(2)(iii); 

■ f. Removing paragraphs (a)(2)(iv) and 

(v); 

■ g. Redesignating (a)(2)(vi) through (ix) 

as (a)(2)(iv) through (vii); 

■ h. Revising the first sentence of 

paragraph (a)(3) introductory text; 

■ i. Revising paragraph (a)(3)(i); 

■ j. Adding paragraphs (a)(4) through 

(7); and 

■ k. Revising paragraphs (b)(2) and (3). 

The revisions and additions read as 

follows: 

§ 60.106a Monitoring of emissions and 

operations for sulfur recovery plants. 

(a) * * * 

(1) * * * 

(i) The span value for the SO2 monitor 

is two times the applicable SO2

emission limit at the highest O2

concentration in the air/oxygen stream 

used in the Claus burner, if applicable. 

* * * * * 

(iv) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60. 

(v) The span value for the O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(vi) The owner or operator shall 

conduct performance evaluations for the 


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O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

Appendix B to part 60. The owner or 

operator shall use Methods 3, 3A, or 3B 

of Appendix A–2 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference— 

see § 60.17) is an acceptable alternative 

to EPA Method 3B of Appendix A–2 to 

part 60. 

(vii) The owner or operator shall 

comply with the applicable quality 

assurance procedures of Appendix F to 

part 60 for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(2) For sulfur recovery plants that are 

subject to the reduced sulfur 

compounds emission limit in 

§ 60.102a(f)(1)(ii) or § 60.102a(f)(2)(ii), 

the owner or operator shall install, 

operate, calibrate, and maintain an 

instrument for continuously monitoring 

and recording the concentration of 

reduced sulfur compounds and O2

emissions into the atmosphere. The 

reduced sulfur compounds emissions 

shall be calculated as SO2 (dry basis, 

zero percent excess air). 

(i) The span value for the reduced 

sulfur compounds monitor is two times 

the applicable reduced sulfur 

compounds emission limit as SO2 at the 

highest O2 concentration in the air/

oxygen stream used in the Claus burner, 

if applicable. 

(ii) The owner or operator shall 

install, operate, and maintain each 

reduced sulfur compounds CEMS 

according to Performance Specification 

5 of Appendix B to part 60. 

(iii) The owner or operator shall 

conduct performance evaluations of 

each reduced sulfur compounds 

monitor according to the requirements 

in § 60.13(c) and Performance 

Specification 5 of Appendix B to part 

60. * * * 

* * * * * 

(3) In place of the reduced sulfur 

compounds monitor required in 

paragraph (a)(2) of this section, the 

owner or operator may install, calibrate, 

operate, and maintain an instrument 

using an air or O2 dilution and 

oxidation system to convert any reduced 

sulfur to SO2 for continuously 

monitoring and recording the 

concentration (dry basis, 0 percent 

excess air) of the total resultant SO2. 

* * * 

(i) The span value for this monitor is 

two times the applicable reduced sulfur 

compounds emission limit as SO2 at the 

highest O2 concentration in the air/

oxygen stream used in the Claus burner, 

if applicable. 

* * * * * 

(4) For sulfur recovery plants that are 

subject to the H2S emission limit in 

§ 60.102a(f)(1)(iii) or § 60.102a(f)(2)(iii), 

the owner or operator shall install, 

operate, calibrate, and maintain an 

instrument for continuously monitoring 

and recording the concentration of H2S, 

and O2 emissions into the atmosphere. 

The H2S emissions shall be calculated 

as SO2 (dry basis, zero percent excess 

air). 

(i) The span value for this monitor is 

two times the applicable H2S emission 

limit. 

(ii) The owner or operator shall 

install, operate, and maintain each H2S 

CEMS according to Performance 

Specification 7 of appendix B to part 60. 

(iii) The owner or operator shall 

conduct performance evaluations for 

each H2S monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 7 of 

appendix B to part 60. The owner or 

operator shall use Methods 11 or 15 of 

appendix A–5 to part 60 or Method 16 

of appendix A–6 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference— 

see § 60.17) is an acceptable alternative 

to EPA Method 15A of appendix A–5 to 

part 60. 

(iv) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of appendix B to part 60. 

(v) The span value for the O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(vi) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

appendix B to part 60. The owner or 

operator shall use Methods 3, 3A, or 3B 

of appendix A–2 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference— 

see § 60.17) is an acceptable alternative 

to EPA Method 3B of appendix A–2 to 

part 60. 

(vii) The owner or operator shall 

comply with the applicable quality 

assurance procedures of appendix F to 

part 60 for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(5) For sulfur recovery plants that use 

oxygen or oxygen enriched air in the 

Claus burner and that elects to monitor 

O2 concentration of the air/oxygen 

mixture supplied to the Claus burner, 

the owner or operator shall install, 

operate, calibrate, and maintain an 

instrument for continuously monitoring 

and recording the O2 concentration of 

the air/oxygen mixture supplied to the 

Claus burner in order to determine the 

allowable emissions limit. 

(i) The owner or operator shall install, 

operate, and maintain each O2 monitor 

according to Performance Specification 

3 of appendix B to part 60. 

(ii) The span value for the O2 monitor 

shall be 100 percent. 

(iii) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

appendix B to part 60. The owner or 

operator shall use Methods 3, 3A, or 3B 

of appendix A–2 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference— 

see § 60.17) is an acceptable alternative 

to EPA Method 3B of appendix A–2 to 

part 60. 

(iv) The owner or operator shall 

comply with the applicable quality 

assurance procedures of appendix F to 

part 60 for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(v) The owner or operator shall use 

the hourly average O2 concentration 

from this monitor for use in Equation 1 

or 2 of § 60.102a(f), as applicable, for 

each hour and determine the allowable 

emission limit as the arithmetic average 

of 12 contiguous 1-hour averages (i.e., 

the rolling 12-hour average). 

(6) As an alternative to the O2 monitor 

required in paragraph (a)(5) of this 

section, the owner or operator may 

install, calibrate, operate, and maintain 

a CPMS to measure and record the 

volumetric gas flow rate of ambient air 

and oxygen-enriched gas supplied to the 

Claus burner and calculate the hourly 

average O2 concentration of the air/

oxygen mixture used in the Claus 

burner as specified in paragraphs 

(a)(6)(i) through (iv) of this section in 

order to determine the allowable 

emissions limit as specified in 

paragraphs (a)(6)(v) of this section. 

(i) The owner or operator shall install, 

calibrate, operate and maintain each 

flow monitor according to the 

manufacturer’s procedures and 

specifications and the following 

requirements. 

(A) The owner or operator shall install 

locate the monitor in a position that 


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36960 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

provides a representative measurement 

of the total gas flow rate. 

(B) Use a flow sensor with a 

measurement sensitivity of no more 

than 5 percent of the flow rate or 10 

cubic feet per minute, whichever is 

greater. 

(C) Use a flow monitor that is 

maintainable online, is able to 

continuously correct for temperature, 

pressure and, for ambient air flow 

monitor, moisture content, and is able to 

record dry flow in standard conditions 

(as defined in § 60.2) over one-minute 

averages. 

(D) At least quarterly, perform a visual 

inspection of all components of the 

monitor for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

the flow monitor is not equipped with 

a redundant flow sensor. 

(E) Recalibrate the flow monitor in 

accordance with the manufacturer’s 

procedures and specifications biennially 

(every two years) or at the frequency 

specified by the manufacturer. 

(ii) The owner or operator shall use 

20.9 percent as the oxygen content of 

the ambient air. 

(iii) The owner or operator shall use 

product specifications (e.g., as reported 

in material safety data sheets) for 

percent oxygen for purchased oxygen. 

For oxygen produced onsite, the percent 

oxygen shall be determined by periodic 

measurements or process knowledge. 

(iv) The owner or operator shall 

calculate the hourly average O2

concentration of the air/oxygen mixture 

used in the Claus burner using Equation 

10 of this section: 

Where: 

%O2 = O2 concentration of the air/oxygen 

mixture used in the Claus burner, 

percent by volume (dry basis); 

20.9 = O2 concentration in air, percent dry 

basis; 

Qair = Volumetric flow rate of ambient air 

used in the Claus burner, dscfm; 

%O2,oxy = O2 concentration in the enriched 

oxygen stream, percent dry basis; and 

Qoxy = Volumetric flow rate of enriched 

oxygen stream used in the Claus burner, 

dscfm. 

(v) The owner or operator shall use 

the hourly average O2 concentration 

determined using Equation 8 of this 

section for use in Equation 1 or 2 of 

§ 60.102a(f), as applicable, for each hour 

and determine the allowable emission 

limit as the arithmetic average of 12 

contiguous 1-hour averages (i.e., the 

rolling 12-hour average). 

(7) Owners or operators of a sulfur 

recovery plant that elects to comply 

with the SO2 emission limit in 

§ 60.102a(f)(1)(i) or § 60.102a(f)(2)(i) or 

the reduced sulfur compounds emission 

limit in § 60.102a(f)(1)(ii) or 

§ 60.102a(f)(2)(ii) as a flow rate weighted 

average for a group of release points 

from the sulfur recovery plant rather 

than for each process train or release 

point individually shall install, 

calibrate, operate, and maintain a CPMS 

to measure and record the volumetric 

gas flow rate of each release point 

within the group of release points from 

the sulfur recovery plant as specified in 

paragraphs (a)(7)(i) through (iv) of this 

section. 

(i) The owner or operator shall install, 

calibrate, operate and maintain each 

flow monitor according to the 

manufacturer’s procedures and 

specifications and the following 

requirements. 

(A) The owner or operator shall install 

locate the monitor in a position that 

provides a representative measurement 

of the total gas flow rate. 

(B) Use a flow sensor with a 

measurement sensitivity of no more 

than 5 percent of the flow rate or 10 

cubic feet per minute, whichever is 

greater. 

(C) Use a flow monitor that is 

maintainable online, is able to 

continuously correct for temperature, 

pressure, and moisture content, and is 

able to record dry flow in standard 

conditions (as defined in § 60.2) over 

one-minute averages. 

(D) At least quarterly, perform a visual 

inspection of all components of the 

monitor for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

the flow monitor is not equipped with 

a redundant flow sensor. 

(E) Recalibrate the flow monitor in 

accordance with the manufacturer’s 

procedures and specifications biennially 

(every two years) or at the frequency 

specified by the manufacturer. 

(ii) The owner or operator shall 

correct the flow to 0 percent excess air 

using Equation 11 of this section: 

Where: 

Qadj = Volumetric flow rate adjusted to 0 

percent excess air, dry standard cubic 

feet per minute (dscfm); 

Cmeas = Volumetric flow rate measured by the 

flow meter corrected to dry standard 

conditions, dscfm; 

20.9c = 20.9 percent O2¥0.0 percent O2

(defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

%O2 = O2 concentration measured on a dry 

basis, percent. 

(iii) The owner or operator shall 

calculate the flow weighted average SO2

or reduced sulfur compounds 

concentration for each hour using 

Equation 12 of this section: 


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Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36961 

Where: 

Cave = Flow weighted average concentration 

of the pollutant, ppmv (dry basis, zero 

percent excess air). The pollutant is 

either SO2 [if complying with the SO2

emission limit in § 60.102a(f)(1)(i) or 

§ 60.102a(f)(2)(i)] or reduced sulfur 

compounds [if complying with the 

reduced sulfur compounds emission 

limit in § 60.102a(f)(1)(ii) or 

§ 60.102a(f)(2)(ii)]; 

N = Number of release points within the 

group of release points from the sulfur 

recovery plant for which emissions 

averaging is elected; 

Cn = Pollutant concentration in the nth 

release point within the group of release 

points from the sulfur recovery plant for 

which emissions averaging is elected, 

ppmv (dry basis, zero percent excess air); 

Qadj,n = Volumetric flow rate of the nth 

release point within the group of release 

points from the sulfur recovery plant for 

which emissions averaging is elected, 

dry standard cubic feet per minute 

(dscfm, adjusted to 0 percent excess air). 

(iv) For sulfur recovery plants that use 

oxygen or oxygen enriched air in the 

Claus burner, the owner or operator 

shall use Equation 10 of this section and 

the hourly emission limits determined 

in paragraphs (a)(5)(v) or (a)(6)(v) of this 

section in-place of the pollutant 

concentration to determine the flow 

weighted average hourly emission limit 

for each hour. The allowable emission 

limit shall be calculated as the 

arithmetic average of 12 contiguous 1- 

hour averages (i.e., the rolling 12-hour 

average). 

(b) * * * 

(2) All 12-hour periods during which 

the average concentration of reduced 

sulfur compounds (as SO2) as measured 

by the reduced sulfur compounds 

continuous monitoring system required 

under paragraph (a)(2) or (3) of this 

section exceeds the applicable emission 

limit; or 

(3) All 12-hour periods during which 

the average concentration of H2S as 

measured by the H2S continuous 

monitoring system required under 

paragraph (a)(4) of this section exceeds 

the applicable emission limit (dry basis, 

0 percent excess air). 

■ 9. Section 60.107a is amended by: 

■ a. Revising paragraphs (a)(1)(i) and 

(ii); 

■ b. Revising paragraph (b)(1)(iv); 

■ c. Revising the first sentence of 

paragraph (b)(3)(iii); 

■ d. Revising paragraph (d)(3); 

■ e. Revising paragraph (e)(1) 

introductory text; 

■ f. Revising paragraph (e)(1)(ii); 

■ g. Revising paragraph (e)(2) 

introductory text; 

■ h. Revising paragraph (e)(2)(ii); 

■ i. Revising paragraph (e)(2)(vi)(C); 

■ j. Revising paragraph (e)(3); and 

■ k. Revising paragraph (h)(5). 

The revisions read as follows: 

§ 60.107a Monitoring of emissions and 

operations for fuel gas combustion devices 

and flares. 

(a) * * * 

(1) * * * 

(i) The owner or operator shall install, 

operate, and maintain each SO2 monitor 

according to Performance Specification 

2 of appendix B to part 60. The span 

value for the SO2 monitor is 50 ppmv 

SO2. 

(ii) The owner or operator shall 

conduct performance evaluations for the 

SO2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 2 of 

appendix B to part 60. The owner or 

operator shall use Methods 6, 6A, or 6C 

of appendix A–4 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981, ‘‘Flue and Exhaust Gas 

Analyses,’’ (incorporated by reference— 

see § 60.17) is an acceptable alternative 

to EPA Method 6 or 6A of appendix A– 

4 to part 60. Samples taken by Method 

6 of appendix A–4 to part 60 shall be 

taken at a flow rate of approximately 2 

liters/min for at least 30 minutes. The 

relative accuracy limit shall be 20 

percent or 4 ppmv, whichever is greater, 

and the calibration drift limit shall be 5 

percent of the established span value. 

* * * * * 

(b) * * * 

(1) * * * 

(iv) The supporting test results from 

sampling the requested fuel gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppmv H2S. 

Sampling data must include, at 

minimum, 2 weeks of daily monitoring 

(14 grab samples) for frequently 

operated fuel gas streams/systems; for 

infrequently operated fuel gas streams/ 

systems, seven grab samples must be 

collected unless other additional 

information would support reduced 

sampling. The owner or operator shall 

use detector tubes (‘‘length-of-stain 

tube’’ type measurement) following the 

‘‘Gas Processors Association Standard 

2377–86, Test for Hydrogen Sulfide and 

Carbon Dioxide in Natural Gas Using 

Length of Stain Tubes,’’ 1986 Revision 

(incorporated by reference—see § 60.17), 

using tubes with a maximum span 

between 10 and 40 ppmv inclusive 

when 1≤N≤10, where N = number of 

pump strokes, to test the applicant fuel 

gas stream for H2S; and 

* * * * * 

(3) * * * 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application and the owner or 

operator chooses not to submit new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance using lengthof-stain tubes with a maximum span 

between 200 and 400 ppmv inclusive 

when 1≤N≤5, where N = number of 

pump strokes. * * * 

* * * * * 

(d) * * * 

(3) As an alternative to the 

requirements in paragraph (d)(2) of this 

section, the owner or operator of a gasfired process heater shall install, operate 

and maintain a gas composition 

analyzer and determine the average F 

factor of the fuel gas using the factors in 

Table 1 of this subpart and Equation 13 

of this section. If a single fuel gas system 

provides fuel gas to several process 

heaters, the F factor may be determined 

at a single location in the fuel gas 

system provided it is representative of 

the fuel gas fed to the affected process 

heater(s). 

Where: 

Fd = F factor on dry basis at 0% excess air, 

dscf/MMBtu. 

Xi = mole or volume fraction of each 

component in the fuel gas. 

MEVi = molar exhaust volume, dry standard 

cubic feet per mole (dscf/mol). 

MHCi = molar heat content, Btu per mole 

(Btu/mol). 

1,000,000 = unit conversion, Btu per MMBtu. 

* * * * * 

(e) * * * 

(1) Total reduced sulfur monitoring 

requirements. The owner or operator 

shall install, operate, calibrate and 

maintain an instrument or instruments 

for continuously monitoring and 


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recording the concentration of total 

reduced sulfur in gas discharged to the 

flare. 

* * * * * 

(ii) The owner or operator shall 

conduct performance evaluations of 

each total reduced sulfur monitor 

according to the requirements in 

§ 60.13(c) and Performance 

Specification 5 of Appendix B to part 

60. The owner or operator of each total 

reduced sulfur monitor shall use EPA 

Method 15A of Appendix A–5 to part 60 

for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

Appendix A–5 to part 60. The 

alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for 

conducting the relative accuracy 

evaluations, except that it is not 

necessary to include as much of the 

sampling probe or sampling line as 

practical. 

* * * * * 

(2) H2S monitoring requirements. The 

owner or operator shall install, operate, 

calibrate, and maintain an instrument or 

instruments for continuously 

monitoring and recording the 

concentration of H2S in gas discharged 

to the flare according to the 

requirements in paragraphs (e)(2)(i) 

through (iii) of this section and shall 

collect and analyze samples of the gas 

and calculate total sulfur concentrations 

as specified in paragraphs (e)(2)(iv) 

through (ix) of this section. 

* * * * * 

(ii) The owner or operator shall 

conduct performance evaluations of 

each H2S monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 7 of 

Appendix B to part 60. The owner or 

operator shall use EPA Method 11, 15 or 

15A of Appendix A–5 to part 60 for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

Appendix A–5 to part 60. The 

alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for 

conducting the relative accuracy 

evaluations, except that it is not 

necessary to include as much of the 

sampling probe or sampling line as 

practical. 

* * * * * 

(vi) * * * 

(C) Determine the acceptable range for 

subsequent weekly samples based on 

the 95-percent confidence interval for 

the distribution of daily ratios based on 

the 10 individual daily ratios using 

Equation 14 of this section. 

Where: 

AR = Acceptable range of subsequent ratio 

determinations, unitless. 

RatioAvg = 10-day average total sulfur-to-H2S 

concentration ratio, unitless. 

2.262 = t-distribution statistic for 95-percent 

2-sided confidence interval for 10 

samples (9 degrees of freedom). 

SDev = Standard deviation of the 10 daily 

average total sulfur-to-H2S concentration 

ratios used to develop the 10-day average 

total sulfur-to-H2S concentration ratio, 

unitless. 

* * * * * 

(3) SO2 monitoring requirements. The 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration of SO2 from 

a process heater or other fuel gas 

combustion device that is combusting 

gas representative of the fuel gas in the 

flare gas line according to the 

requirements in paragraph (a)(1) of this 

section, determine the F factor of the 

fuel gas at least daily according to the 

requirements in paragraphs (d)(2) 

through (4) of this section, determine 

the higher heating value of the fuel gas 

at least daily according to the 

requirements in paragraph (d)(7) of this 

section, and calculate the total sulfur 

content (as SO2) in the fuel gas using 

Equation 15 of this section. 

Where: 

TSFG = Total sulfur concentration, as SO2, in 

the fuel gas, ppmv. 

CSO2 = Concentration of SO2 in the exhaust 

gas, ppmv (dry basis at 0-percent excess 

air). 

Fd = F factor gas on dry basis at 0-percent 

excess air, dscf/MMBtu. 

HHVFG = Higher heating value of the fuel gas, 

MMBtu/scf. 

* * * * * 

(h) * * * 

(5) Daily O2 limits for fuel gas 

combustion devices. Each day during 

which the concentration of O2 as 

measured by the O2 continuous 

monitoring system required under 

paragraph (c)(6) or (d)(8) of this section 

exceeds the O2 operating limit or 

operating curve determined during the 

most recent biennial performance test. 

PART 63—NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 10. The authority citation for part 63 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

■ 11. Section 63.14 is amended by: 

■ a. Revising paragraph (g)(14); 

■ b. Adding paragraphs (g)(95) and (96); 

■ c. Adding paragraph (i)(2); 

■ d. Adding paragraphs (l)(21) through 

(23); and 

■ e. Adding paragraphs (m)(3) and (s). 

The revisions and additions read as 

follows: 

§ 63.14 Incorporation by reference. 

* * * * * 

(g) * * * 

(14) ASTM D1945–03 (Reapproved 

2010), Standard Test Method for 

Analysis of Natural Gas by Gas 

Chromatography, (Approved January 1, 

2010), IBR approved for §§ 63.670(j), 

63.772(h), and 63.1282(g). 

* * * * * 

(95) ASTM D6196–03 (Reapproved 

2009), Standard Practice for Selection of 

Sorbents, Sampling, and Thermal 

Desorption Analysis Procedures for 

Volatile Organic Compounds in Air, IBR 

approved for appendix A to part 63: 

Method 325A, Sections 1.2 and 6.1, and 

Method 325B, Sections 1.3, 7.1.2, 7.1.3, 

and A.1.1. 

(96) ASTM UOP539–12, Refinery Gas 

Analysis by Gas Chromatography, IBR 

approved for § 63.670(j). 

* * * * * 

(i) * * * 

(2) BS EN 14662–4:2005, Ambient Air 

Quality: Standard Method for the 

Measurement of Benzene 

Concentrations—Part 4: Diffusive 

Sampling Followed By Thermal 

Desorption and Gas Chromatography, 

IBR approved for appendix A to part 63: 

Method 325A, Section 1.2, and Method 

325B, Sections 1.3, 7.1.3, and A.1.1. 

* * * * * 

(l) * * * 

(21) EPA–454/R–99–005, Office of Air 

Quality Planning and Standards 

(OAQPS), Meteorological Monitoring 


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Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36963 

Guidance for Regulatory Modeling 

Applications, February 2000, IBR 

approved for appendix A to part 63: 

Method 325A, Section 8.3. 

(22) EPA–454/B–08–002, Office of Air 

Quality Planning and Standards 

(OAQPS), Quality Assurance Handbook 

for Air Pollution Measurement Systems, 

Volume IV: Meteorological 

Measurements, Version 2.0 (Final), 

March 2008, IBR approved for 

§ 63.658(d) and appendix A to part 63: 

Method 325A, Sections 8.1.4 and 10.0. 

(23) EPA–454/B–13–003, Office of Air 

Quality Planning and Standards 

(OAQPS), Quality Assurance Handbook 

for Air Pollution Measurement Systems, 

Volume II: Ambient Air Quality 

Monitoring Program, May 2013, IBR 

approved for § 63.658(c) and appendix 

A to part 63: Method 325A, Section 4.1. 

(m) * * * 

(3) ISO 16017–2:2003, Indoor, 

Ambient and Workplace Air—Sampling 

and Analysis of Volatile Organic 

Compounds by Sorbent Tube/Thermal 

Desorption/Capillary Gas 

Chromatography—Part 2: Diffusive 

Sampling, First edition, June 11, 2003, 

IBR approved for appendix A to part 63: 

Method 325A, Sections 1.2, 6.1, and 6.5, 

and Method 325B, Sections 1.3, 7.1.2, 

7.1.3, and A.1.1. 

* * * * * 

(s) U.S. Department of the Interior, 

1849 C Street NW., Washington, DC 

20240, (202) 208–3100, www.doi.gov. 

(1) Bulletin 627, Bureau of Mines, 

Flammability Characteristics of 

Combustible Gases and Vapors, 1965, 

IBR approved for § 63.670(l). 

(2) [Reserved] 

Subpart Y—[Amended] 

■ 12. Section 63.560 is amended by 

revising paragraph (a)(4) to read as 

follows: 

§ 63.560 Applicability and designation of 

affected source. 

(a) * * * 

(4) Existing sources with emissions 

less than 10 and 25 tons must meet the 

submerged fill standards of 46 CFR 

153.282. 

* * * * * 

Subpart CC—[Amended] 

■ 13. Section 63.640 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraph (c) introductory 

text; 

■ c. Adding paragraph (c)(9); 

■ d. Revising paragraph (d)(5); 

■ e. Revising paragraph (h); 

■ f. Revising paragraph (k)(1); 

■ g. Revising paragraph (l) introductory 

text; 

■ h. Revising paragraph (l)(2) 

introductory text; 

■ i. Revising paragraph (l)(2)(i); 

■ j. Revising paragraph (l)(3) 

introductory text; 

■ k. Revising paragraph (m) 

introductory text; 

■ l. Revising paragraph (n) introductory 

text; 

■ m. Revising paragraphs (n)(1) through 

(5); 

■ n. Revising paragraph (n)(8) 

introductory text; 

■ o. Revising paragraph (n)(8)(ii); 

■ p. Adding paragraphs (n)(8)(vii) and 

(viii); 

■ q. Revising paragraph (n)(9)(i); 

■ r. Adding paragraph (n)(10); 

■ s. Revising paragraph (o)(2)(i) 

introductory text; 

■ t. Adding paragraph (o)(2)(i)(D); 

■ u. Revising paragraph (o)(2)(ii) 

introductory text; 

■ v. Adding paragraph (o)(2)(ii)(C); and 

■ w. Revising paragraph (p)(2). 

The revisions and additions read as 

follows: 

§ 63.640 Applicability and designation of 

affected source. 

(a) This subpart applies to petroleum 

refining process units and to related 

emissions points that are specified in 

paragraphs (c)(1) through (9) of this 

section that are located at a plant site 

and that meet the criteria in paragraphs 

(a)(1) and (2) of this section: 

* * * * * 

(c) For the purposes of this subpart, 

the affected source shall comprise all 

emissions points, in combination, listed 

in paragraphs (c)(1) through (c)(9) of this 

section that are located at a single 

refinery plant site. 

* * * * * 

(9) All releases associated with the 

decoking operations of a delayed coking 

unit, as defined in this subpart. 

* * * * * 

(d) * * * 

(5) Emission points routed to a fuel 

gas system, as defined in § 63.641 of this 

subpart, provided that on and after [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], any flares receiving gas 

from that fuel gas system are in 

compliance with § 63.670. No other 

testing, monitoring, recordkeeping, or 

reporting is required for refinery fuel gas 

systems or emission points routed to 

refinery fuel gas systems. 

* * * * * 

(h) Sources subject to this subpart are 

required to achieve compliance on or 

before the dates specified in table 11 of 

this subpart, except as provided in 

paragraphs (h)(1) through (3) of this 

section. 

(1) Marine tank vessels at existing 

sources shall be in compliance with this 

subpart, except for §§ 63.657 through 

63.661, no later than August 18, 1999, 

unless the vessels are included in an 

emissions average to generate emission 

credits. Marine tank vessels used to 

generate credits in an emissions average 

shall be in compliance with this subpart 

no later than August 18, 1998 unless an 

extension has been granted by the 

Administrator as provided in § 63.6(i). 

(2) Existing Group 1 floating roof 

storage vessels meeting the applicability 

criteria in item 1 of the definition of 

Group 1 storage vessel shall be in 

compliance with § 63.646 at the first 

degassing and cleaning activity after 

August 18, 1998, or August 18, 2005, 

whichever is first. 

(3) An owner or operator may elect to 

comply with the provisions of 

§ 63.648(c) through (i) as an alternative 

to the provisions of § 63.648(a) and (b). 

In such cases, the owner or operator 

shall comply no later than the dates 

specified in paragraphs (h)(3)(i) through 

(h)(3)(iii) of this section. 

(i) Phase I (see table 2 of this subpart), 

beginning on August 18, 1998; 

(ii) Phase II (see table 2 of this 

subpart), beginning no later than August 

18, 1999; and 

(iii) Phase III (see table 2 of this 

subpart), beginning no later than 

February 18, 2001. 

* * * * * 

(k) * * * 

(1) The reconstructed source, 

addition, or change shall be in 

compliance with the new source 

requirements in item (1), (2), or (3) of 

table 11 of this subpart, as applicable, 

upon initial startup of the reconstructed 

source or by August 18, 1995, 

whichever is later; and 

* * * * * 

(l) If an additional petroleum refining 

process unit is added to a plant site or 

if a miscellaneous process vent, storage 

vessel, gasoline loading rack, marine 

tank vessel loading operation, heat 

exchange system, or decoking operation 

that meets the criteria in paragraphs 

(c)(1) through (9) of this section is added 

to an existing petroleum refinery or if 

another deliberate operational process 

change creating an additional Group 1 

emissions point(s) (as defined in 

§ 63.641) is made to an existing 

petroleum refining process unit, and if 

the addition or process change is not 

subject to the new source requirements 

as determined according to paragraphs 

(i) or (j) of this section, the requirements 

in paragraphs (l)(1) through (4) of this 


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section shall apply. Examples of process 

changes include, but are not limited to, 

changes in production capacity, or feed 

or raw material where the change 

requires construction or physical 

alteration of the existing equipment or 

catalyst type, or whenever there is 

replacement, removal, or addition of 

recovery equipment. For purposes of 

this paragraph and paragraph (m) of this 

section, process changes do not include: 

Process upsets, unintentional temporary 

process changes, and changes that are 

within the equipment configuration and 

operating conditions documented in the 

Notification of Compliance Status report 

required by § 63.655(f). 

* * * * * 

(2) The added emission point(s) and 

any emission point(s) within the added 

or changed petroleum refining process 

unit shall be in compliance with the 

applicable requirements in item (4) of 

table 11 of this subpart by the dates 

specified in paragraphs (l)(2)(i) or 

(l)(2)(ii) of this section. 

(i) If a petroleum refining process unit 

is added to a plant site or an emission 

point(s) is added to any existing 

petroleum refining process unit, the 

added emission point(s) shall be in 

compliance upon initial startup of any 

added petroleum refining process unit 

or emission point(s) or by the applicable 

compliance date in item (4) of table 11 

of this subpart, whichever is later. 

* * * * * 

(3) The owner or operator of a 

petroleum refining process unit or of a 

storage vessel, miscellaneous process 

vent, wastewater stream, gasoline 

loading rack, marine tank vessel loading 

operation, heat exchange system, or 

decoking operation meeting the criteria 

in paragraphs (c)(1) through (9) of this 

section that is added to a plant site and 

is subject to the requirements for 

existing sources shall comply with the 

reporting and recordkeeping 

requirements that are applicable to 

existing sources including, but not 

limited to, the reports listed in 

paragraphs (l)(3)(i) through (vii) of this 

section. A process change to an existing 

petroleum refining process unit shall be 

subject to the reporting requirements for 

existing sources including, but not 

limited to, the reports listed in 

paragraphs (l)(3)(i) through (l)(3)(vii) of 

this section. The applicable reports 

include, but are not limited to: 

* * * * * 

(m) If a change that does not meet the 

criteria in paragraph (l) of this section 

is made to a petroleum refining process 

unit subject to this subpart, and the 

change causes a Group 2 emission point 

to become a Group 1 emission point (as 

defined in § 63.641), then the owner or 

operator shall comply with the 

applicable requirements of this subpart 

for existing sources, as specified in item 

(4) of table 11 of this subpart, for the 

Group 1 emission point as expeditiously 

as practicable, but in no event later than 

3 years after the emission point becomes 

Group 1. 

* * * * * 

(n) Overlap of subpart CC with other 

regulations for storage vessels. As 

applicable, paragraphs (n)(1), (n)(3), 

(n)(4), (n)(6), and (n)(7) of this section 

apply for Group 2 storage vessels and 

paragraphs (n)(2) and (n)(5) of this 

section apply for Group 1 storage 

vessels. 

(1) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 2 storage vessel that is 

subject to the provisions of 40 CFR part 

60, subpart Kb is required to comply 

only with the requirements of 40 CFR 

part 60, subpart Kb, except as provided 

in paragraph (n)(8) of this section. After 

the compliance dates specified in 

paragraph (h) of this section, a Group 2 

storage vessel that is subject to the 

provisions of CFR part 61, subpart Y is 

required to comply only with the 

requirements of 40 CFR part 60, subpart 

Y, except as provided in paragraph 

(n)(10) of this section. 

(2) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 1 storage vessel that is 

also subject to 40 CFR part 60, subpart 

Kb is required to comply only with 

either 40 CFR part 60, subpart Kb, 

except as provided in paragraph (n)(8) 

of this section; or this subpart. After the 

compliance dates specified in paragraph 

(h) of this section, a Group 1 storage 

vessel that is also subject to 40 CFR part 

61, subpart Y is required to comply only 

with either 40 CFR part 61, subpart Y, 

except as provided in paragraph (n)(10) 

of this section; or this subpart. 

(3) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 2 storage vessel that is 

part of a new source and is subject to 

40 CFR 60.110b, but is not required to 

apply controls by 40 CFR 60.110b or 

60.112b, is required to comply only 

with this subpart. 

(4) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 2 storage vessel that is 

part of a new source and is subject to 

40 CFR 61.270, but is not required to 

apply controls by 40 CFR 61.271, is 

required to comply only with this 

subpart. 

(5) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 1 storage vessel that is 

also subject to the provisions of 40 CFR 

part 60, subparts K or Ka is required to 

only comply with the provisions of this 

subpart. 

* * * * * 

(8) Storage vessels described by 

paragraph (n)(1) of this section are to 

comply with 40 CFR part 60, subpart Kb 

except as provided in paragraphs 

(n)(8)(i) through (n)(8)(vi) of this 

section. Storage vessels described by 

paragraph (n)(2) electing to comply with 

part 60, subpart Kb of this chapter shall 

comply with subpart Kb except as 

provided in paragraphs (n)(8)(i) through 

(n)(8)(vii) of this section. 

* * * * * 

(ii) If the owner or operator 

determines that it is unsafe to perform 

the seal gap measurements required in 

§ 60.113b(b) of subpart Kb or to inspect 

the vessel to determine compliance with 

§ 60.113b(a) of subpart Kb because the 

roof appears to be structurally unsound 

and poses an imminent danger to 

inspecting personnel, the owner or 

operator shall comply with the 

requirements in either § 63.120(b)(7)(i) 

or § 63.120(b)(7)(ii) of subpart G (only 

up to the compliance date specified in 

paragraph (h) of this section for 

compliance with § 63.660, as applicable) 

or either § 63.1063(c)(2)(iv)(A) or 

§ 63.1063(c)(2)(iv)(B) of subpart WW. 

* * * * * 

(vii) To be in compliance with 

§ 60.112b(a)(2)(ii) of this chapter, 

floating roof storage vessels must be 

equipped with guidepole controls as 

described in Appendix I: Acceptable 

Controls for Slotted Guidepoles Under 

the Storage Tank Emissions Reduction 

Partnership Program (available at 

http://www.epa.gov/ttn/atw/petrefine/

petrefpg.html). 

(viii) If a flare is used as a control 

device for a storage vessel, on and after 

[THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the owner or 

operator must meet the requirements of 

§ 63.670 instead of the requirements 

referenced from part 60, subpart Kb of 

this chapter for that flare. 

(9) * * * 

(i) If the owner or operator determines 

that it is unsafe to perform the seal gap 

measurements required in 

§ 60.113a(a)(1) of subpart Ka because the 

floating roof appears to be structurally 

unsound and poses an imminent danger 

to inspecting personnel, the owner or 

operator shall comply with the 

requirements in either § 63.120(b)(7)(i) 

or § 63.120(b)(7)(ii) of subpart G (only 

up to the compliance date specified in 

paragraph (h) of this section for 


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compliance with § 63.660, as applicable) 

or either § 63.1063(c)(2)(iv)(A) or 

§ 63.1063(c)(2)(iv)(B) of subpart WW. 

* * * * * 

(10) Storage vessels described by 

paragraph (n)(1) of this section are to 

comply with 40 CFR part 61, subpart Y 

except as provided in paragraphs 

(n)(10)(i) through (n)(8)(vi) of this 

section. Storage vessels described by 

paragraph (n)(2) electing to comply with 

40 CFR part 61, subpart Y shall comply 

with subpart Y except as provided for in 

paragraphs (n)(10)(i) through 

(n)(10)(viii) of this section. 

(i) Storage vessels that are to comply 

with § 61.271(b) of this chapter are 

exempt from the secondary seal 

requirements of § 61.271(b)(2)(ii) of this 

chapter during the gap measurements 

for the primary seal required by 

§ 61.272(b) of this chapter. 

(ii) If the owner or operator 

determines that it is unsafe to perform 

the seal gap measurements required in 

§ 61.272(b) of this chapter or to inspect 

the vessel to determine compliance with 

§ 61.272(a) of this chapter because the 

roof appears to be structurally unsound 

and poses an imminent danger to 

inspecting personnel, the owner or 

operator shall comply with the 

requirements in either § 63.120(b)(7)(i) 

or § 63.120(b)(7)(ii) of subpart G (only 

up to the compliance date specified in 

paragraph (h) of this section for 

compliance with § 63.660, as applicable) 

or either § 63.1063(c)(2)(iv)(A) or 

§ 63.1063(c)(2)(iv)(B) of subpart WW. 

(iii) If a failure is detected during the 

inspections required by § 61.272(a)(2) of 

this chapter or during the seal gap 

measurements required by § 61.272(b)(1) 

of this chapter, and the vessel cannot be 

repaired within 45 days and the vessel 

cannot be emptied within 45 days, the 

owner or operator may utilize up to two 

extensions of up to 30 additional 

calendar days each. The owner or 

operator is not required to provide a 

request for the extension to the 

Administrator. 

(iv) If an extension is utilized in 

accordance with paragraph (n)(10)(iii) of 

this section, the owner or operator shall, 

in the next periodic report, identify the 

vessel, provide the information listed in 

§ 61.272(a)(2) or § 61.272(b)(4)(iii) of 

this chapter, and describe the nature 

and date of the repair made or provide 

the date the storage vessel was emptied. 

(v) Owners and operators of storage 

vessels complying with 40 CFR part 61, 

subpart Y may submit the inspection 

reports required by § 61.275(a), (b)(1), 

and (d) of this chapter as part of the 

periodic reports required by this 

subpart, rather than within the 60-day 

period specified in § 61.275(a), (b)(1), 

and (d) of this chapter. 

(vi) The reports of rim seal 

inspections specified in § 61.275(d) of 

this chapter are not required if none of 

the measured gaps or calculated gap 

areas exceed the limitations specified in 

§ 61.272(b)(4) of this chapter. 

Documentation of the inspections shall 

be recorded as specified in § 61.276(a) of 

this chapter. 

(vii) To be in compliance with 

§ 61.271(b)(3) of this chapter, floating 

roof storage vessels must be equipped 

with guidepole controls as described in 

Appendix I: Acceptable Controls for 

Slotted Guidepoles Under the Storage 

Tank Emissions Reduction Partnership 

Program (available at http://

www.epa.gov/ttn/atw/petrefine/

petrefpg.html). 

(viii) If a flare is used as a control 

device for a storage vessel, on and after 

[THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the owner or 

operator must meet the requirements of 

§ 63.670 instead of the requirements 

referenced from part 61, subpart Y of 

this chapter for that flare. 

(o) * * * 

(2) * * * 

(i) Comply with paragraphs 

(o)(2)(i)(A) through (D) of this section. 

* * * * * 

(D) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of 40 CFR part 

61, subpart FF and subpart G of this 

part, or the requirements of § 63.670. 

(ii) Comply with paragraphs 

(o)(2)(ii)(A) through (C) of this section. 

* * * * * 

(C) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of 40 CFR part 

61, subpart FF and subpart G of this 

part, or the requirements of § 63.670. 

(p) * * * 

(2) Equipment leaks that are also 

subject to the provisions of 40 CFR part 

60, subpart GGGa, are required to 

comply only with the provisions 

specified in 40 CFR part 60, subpart 

GGGa. Owners and operators of 

equipment leaks that are subject to the 

provisions of 40 CFR part 60, subpart 

GGGa and subject to this subpart may 

elect to monitor equipment leaks 

following the provisions in § 63.661, 

provided that the equipment is in 

compliance with all other provisions of 

40 CFR part 60, subpart GGGa. 

* * * * * 

■ 14. Section 63.641 is amended by: 

■ a. Adding, in alphabetical order, new 

definitions of ‘‘Assist air,’’ ‘‘Assist 

steam,’’ ‘‘Center steam,’’ ‘‘Closed 

blowdown system,’’ ‘‘Combustion 

zone,’’ ‘‘Combustion zone gas,’’ 

‘‘Decoking operations,’’ ‘‘Delayed coking 

unit,’’ ‘‘Flare,’’ ‘‘Flare purge gas,’’ ‘‘Flare 

supplemental gas,’’ ‘‘Flare sweep gas,’’ 

‘‘Flare vent gas,’’ ‘‘Halogenated vent 

stream or halogenated stream,’’ 

‘‘Halogens and hydrogen halides,’’ 

‘‘Lower steam,’’ ‘‘Net heating value,’’ 

‘‘Perimeter assist air,’’ ‘‘Pilot gas,’’ 

‘‘Premix assist air,’’ ‘‘Total steam,’’ and 

‘‘Upper steam’’; and 

■ b. Revising the definitions of 

‘‘Delayed coker vent,’’ ‘‘Emission 

point,’’ ‘‘Group 1 storage vessel,’’ 

‘‘Miscellaneous process vent,’’ 

‘‘Periodically discharged,’’ and 

‘‘Reference control technology for 

storage vessels’’. 

The revisions and additions read as 

follows: 

§ 63.641 Definitions. 

* * * * * 

Assist air means all air that 

intentionally is introduced prior to or at 

a flare tip through nozzles or other 

hardware conveyance for the purposes 

including, but not limited to, protecting 

the design of the flare tip, promoting 

turbulence for mixing or inducing air 

into the flame. Assist air includes 

premix assist air and perimeter assist 

air. Assist air does not include the 

surrounding ambient air. 

Assist steam means all steam that 

intentionally is introduced prior to or at 

a flare tip through nozzles or other 

hardware conveyance for the purposes 

including, but not limited to, protecting 

the design of the flare tip, promoting 

turbulence for mixing or inducing air 

into the flame. Assist steam includes, 

but is not necessarily limited to, center 

steam, lower steam and upper steam. 

* * * * * 

Center steam means the portion of 

assist steam introduced into the stack of 

a flare to reduce burnback. 


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Closed blowdown system means a 

system used for depressuring process 

vessels that is not open to the 

atmosphere and is configured of piping, 

ductwork, connections, accumulators/

knockout drums, and, if necessary, flow 

inducing devices that transport gas or 

vapor from process vessel to a control 

device or back into the process. 

* * * * * 

Combustion zone means the area of 

the flare flame where the combustion 

zone gas combines for combustion. 

Combustion zone gas means all gases 

and vapors found just after a flare tip. 

This gas includes all flare vent gas, total 

steam, and premix air. 

* * * * * 

Decoking operations means the 

sequence of steps conducted at the end 

of the delayed coking unit’s cooling 

cycle to open the coke drum to the 

atmosphere in order to remove coke 

from the coke drum. Decoking 

operations begin at the end of the 

cooling cycle when steam released from 

the coke drum is no longer discharged 

via the delayed coker vent to the unit’s 

blowdown system but instead is vented 

directly to the atmosphere. Decoking 

operations include atmospheric 

depressuring (venting), deheading, 

draining, and decoking (coke cutting). 

Delayed coker vent means a vent that 

is typically intermittent in nature, and 

usually occurs only during the cooling 

cycle of a delayed coking unit coke 

drum when vapor from the coke drums 

cannot be sent to the fractionator 

column for product recovery, but 

instead is routed to the atmosphere 

through the delayed coking unit’s 

blowdown system. The emissions from 

the decoking operations, which include 

direct atmospheric venting, deheading, 

draining, or decoking (coke cutting), are 

not considered to be delayed coker 

vents. 

Delayed coking unit means a refinery 

process unit in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is produced in a series of closed, batch 

system reactors. A delayed coking unit 

includes, but is not limited to, all of the 

coke drums associated with a single 

fractionator; the fractionator, including 

the bottoms receiver and the overhead 

condenser; the coke drum cutting water 

and quench system, including the jet 

pump and coker quench water tank; and 

the coke drum blowdown recovery 

compressor system. 

* * * * * 

Emission point means an individual 

miscellaneous process vent, storage 

vessel, wastewater stream, equipment 

leak, decoking operation or heat 

exchange system associated with a 

petroleum refining process unit; an 

individual storage vessel or equipment 

leak associated with a bulk gasoline 

terminal or pipeline breakout station 

classified under Standard Industrial 

Classification code 2911; a gasoline 

loading rack classified under Standard 

Industrial Classification code 2911; or a 

marine tank vessel loading operation 

located at a petroleum refinery. 

* * * * * 

Flare means a combustion device 

lacking an enclosed combustion 

chamber that uses an uncontrolled 

volume of ambient air to burn gases. For 

the purposes of this rule, the definition 

of flare includes, but is not necessarily 

limited to, air-assisted flares, steamassisted flares and non-assisted flares. 

Flare purge gas means gas introduced 

between a flare header’s water seal and 

the flare tip to prevent oxygen 

infiltration (backflow) into the flare tip. 

For a flare with no water seal, the 

function of flare purge gas is performed 

by flare sweep gas and, therefore, by 

definition, such a flare has no flare 

purge gas. 

Flare supplemental gas means all gas 

introduced to the flare in order to 

improve the combustible characteristics 

of combustion zone gas. 

Flare sweep gas means, for a flare 

with a flare gas recovery system, the 

minimum amount of gas necessary to 

maintain a constant flow of gas through 

the flare header in order to prevent 

oxygen buildup in the flare header; flare 

sweep gas in these flares is introduced 

prior to and recovered by the flare gas 

recovery system. For a flare without a 

flare gas recovery system, flare sweep 

gas means the minimum amount of gas 

necessary to maintain a constant flow of 

gas through the flare header and out the 

flare tip in order to prevent oxygen 

buildup in the flare header and to 

prevent oxygen infiltration (backflow) 

into the flare tip. 

Flare vent gas means all gas found just 

prior to the flare tip. This gas includes 

all flare waste gas (i.e., gas from facility 

operations that is directed to a flare for 

the purpose of disposing of the gas), 

flare sweep gas, flare purge gas and flare 

supplemental gas, but does not include 

pilot gas, total steam or assist air. 

* * * * * 

Group 1 storage vessel means: 

(1) Prior to [THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER]: 

(i) A storage vessel at an existing 

source that has a design capacity greater 

than or equal to 177 cubic meters and 

stored-liquid maximum true vapor 

pressure greater than or equal to 10.4 

kilopascals and stored-liquid annual 

average true vapor pressure greater than 

or equal to 8.3 kilopascals and annual 

average HAP liquid concentration 

greater than 4 percent by weight total 

organic HAP; 

(ii) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 151 cubic meters and 

stored-liquid maximum true vapor 

pressure greater than or equal to 3.4 

kilopascals and annual average HAP 

liquid concentration greater than 2 

percent by weight total organic HAP; or 

(iii) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 76 cubic meters and 

less than 151 cubic meters and storedliquid maximum true vapor pressure 

greater than or equal to 77 kilopascals 

and annual average HAP liquid 

concentration greater than 2 percent by 

weight total organic HAP. 

(2) On and after [THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER]: 

(i) A storage vessel at an existing 

source that has a design capacity greater 

than or equal to 151 cubic meters 

(40,000 gallons) and stored-liquid 

maximum true vapor pressure greater 

than or equal to 5.2 kilopascals (0.75 

pounds per square inch) and annual 

average HAP liquid concentration 

greater than 4 percent by weight total 

organic HAP; 

(ii) A storage vessel at an existing 

source that has a design storage capacity 

greater than or equal to 76 cubic meters 

(20,000 gallons) and less than 151 cubic 

meters (40,000 gallons) and storedliquid maximum true vapor pressure 

greater than or equal to 13.1 kilopascals 

(1.9 pounds per square inch) and annual 

average HAP liquid concentration 

greater than 4 percent by weight total 

organic HAP; 

(iii) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 151 cubic meters 

(40,000 gallons) and stored-liquid 

maximum true vapor pressure greater 

than or equal to 3.4 kilopascals (0.5 

pounds per square inch) and annual 

average HAP liquid concentration 

greater than 2 percent by weight total 

organic HAP; or 

(iv) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 76 cubic meters (20,000 

gallons) and less than 151 cubic meters 

(40,000 gallons) and stored-liquid 

maximum true vapor pressure greater 

than or equal to 13.1 kilopascals (1.9 

pounds per square inch) and annual 

average HAP liquid concentration 


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greater than 2 percent by weight total 

organic HAP. 

* * * * * 

Halogenated vent stream or 

halogenated stream means a stream 

determined to have a mass rate of 

halogen atoms of 0.45 kilograms per 

hour or greater, determined by the 

procedures presented in 

§ 63.115(d)(2)(v). The following 

procedures may be used as alternatives 

to the procedures in 

§ 63.115(d)(2)(v)(A): 

(1) Process knowledge that halogen or 

hydrogen halides are present in a vent 

stream and that the vent stream is 

halogenated, or 

(2) Concentration of compounds 

containing halogen and hydrogen 

halides measured by Method 26 or 26A 

of part 60, Appendix A–8 of this 

chapter, or 

(3) Concentration of compounds 

containing hydrogen halides measured 

by Method 320 of Appendix A of this 

part. 

Halogens and hydrogen halides means 

hydrogen chloride (HCl), chlorine (Cl2), 

hydrogen bromide (HBr), bromine (Br2), 

and hydrogen fluoride (HF). 

* * * * * 

Lower steam means the portion of 

assist steam piped to an exterior annular 

ring near the lower part of a flare tip, 

which then flows through tubes to the 

flare tip, and ultimately exits the tubes 

at the flare tip. 

* * * * * 

Miscellaneous process vent means a 

gas stream containing greater than 20 

parts per million by volume organic 

HAP that is continuously or periodically 

discharged from a petroleum refining 

process unit meeting the criteria 

specified in § 63.640(a). Miscellaneous 

process vents include gas streams that 

are discharged directly to the 

atmosphere, gas streams that are routed 

to a control device prior to discharge to 

the atmosphere, or gas streams that are 

diverted through a product recovery 

device prior to control or discharge to 

the atmosphere. Miscellaneous process 

vents include vent streams from: caustic 

wash accumulators, distillation tower 

condensers/accumulators, flash/

knockout drums, reactor vessels, 

scrubber overheads, stripper overheads, 

vacuum pumps, steam ejectors, hot 

wells, high point bleeds, wash tower 

overheads, water wash accumulators, 

blowdown condensers/accumulators, 

and delayed coker vents. Miscellaneous 

process vents do not include: 

(1) Gaseous streams routed to a fuel 

gas system, provided that on and after 

[THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], any flares 

receiving gas from the fuel gas system 

are in compliance with § 63.670; 

(2) Relief valve discharges regulated 

under § 63.648; 

(3) Leaks from equipment regulated 

under § 63.648; 

(4) [Reserved]; 

(5) In situ sampling systems (onstream 

analyzers) until [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER]. After 

this date, these sampling systems will 

be included in the definition of 

miscellaneous process vents; 

(6) Catalytic cracking unit catalyst 

regeneration vents; 

(7) Catalytic reformer regeneration 

vents; 

(8) Sulfur plant vents; 

(9) Vents from control devices such as 

scrubbers, boilers, incinerators, and 

electrostatic precipitators applied to 

catalytic cracking unit catalyst 

regeneration vents, catalytic reformer 

regeneration vents, and sulfur plant 

vents; 

(10) Vents from any stripping 

operations applied to comply with the 

wastewater provisions of this subpart, 

subpart G of this part, or 40 CFR part 61, 

subpart FF; 

(11) Emissions associated with 

delayed coking unit decoking 

operations; 

(12) Vents from storage vessels; 

(13) Emissions from wastewater 

collection and conveyance systems 

including, but not limited to, 

wastewater drains, sewer vents, and 

sump drains; and 

(14) 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. 

Net heating value means the energy 

released as heat when a compound 

undergoes complete combustion with 

oxygen to form gaseous carbon dioxide 

and gaseous water (also referred to as 

lower heating value). 

* * * * * 

Perimeter assist air means the portion 

of assist air introduced at the perimeter 

of the flare tip or above the flare tip. 

Perimeter assist air includes air 

intentionally entrained in lower and 

upper steam. Perimeter assist air 

includes all assist air except premix 

assist air. 

Periodically discharged means 

discharges that are intermittent and 

associated with routine operations, 

maintenance activities, startups, 

shutdowns, malfunctions, or process 

upsets. 

* * * * * 

Pilot gas means gas introduced into a 

flare tip that provides a flame to ignite 

the flare vent gas. 

* * * * * 

Premix assist air means the portion of 

assist air that is introduced to the flare 

vent gas prior to the flare tip. Premix 

assist air also includes any air 

intentionally entrained in center steam. 

* * * * * 

Reference control technology for 

storage vessels means either: 

(1) For Group 1 storage vessels 

complying with § 63.660: 

(i) An internal floating roof meeting 

the specifications of §§ 63.1063(a)(1)(i) 

and (b); 

(ii) An external floating roof meeting 

the specifications of § 63.1063(a)(1)(ii), 

(a)(2), and (b); 

(iii) An external floating roof 

converted to an internal floating roof 

meeting the specifications of 

§ 63.1063(a)(1)(i) and (b); or 

(iv) A closed-vent system to a control 

device that reduces organic HAP 

emissions by 95 percent, or to an outlet 

concentration of 20 parts per million by 

volume (ppmv). 

(v) For purposes of emissions 

averaging, these four technologies are 

considered equivalent. 

(2) For all other storage vessels: 

(i) An internal floating roof meeting 

the specifications of § 63.119(b) of 

subpart G except for § 63.119(b)(5) and 

(b)(6); 

(ii) An external floating roof meeting 

the specifications of § 63.119(c) of 

subpart G except for § 63.119(c)(2); 

(iii) An external floating roof 

converted to an internal floating roof 

meeting the specifications of § 63.119(d) 

of subpart G except for § 63.119(d)(2); or 

(iv) A closed-vent system to a control 

device that reduces organic HAP 

emissions by 95 percent, or to an outlet 

concentration of 20 parts per million by 

volume. 

(v) For purposes of emissions 

averaging, these four technologies are 

considered equivalent. 

* * * * * 

Total steam means the total of all 

steam that is supplied to a flare and 

includes, but is not limited to, lower 

steam, center steam and upper steam. 

Upper steam means the portion of 

assist steam introduced via nozzles 

located on the exterior perimeter of the 

upper end of the flare tip. 

* * * * * 

■ 15. Section 63.642 is amended by: 

■ a. Adding paragraph (b); 

■ b. Revising paragraph (d)(3); 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36968 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

■ c. Revising paragraph (e); 

■ d. Revising paragraph (i); 

■ e. Revising paragraph (k) introductory 

text; 

■ f. Revising paragraph (k)(1); 

■ g. Revising paragraph (l) introductory 

text; 

■ h. Revising paragraph (l)(2); and 

■ i. Adding paragraph (n). 

The revisions and additions read as 

follows: 

§ 63.642 General standards. 

* * * * * 

(b) The emission standards set forth in 

this subpart shall apply at all times. 

* * * * * 

(d) * * * 

(3) Performance tests shall be 

conducted at maximum representative 

operating capacity for the process. 

During the performance test, an owner 

or operator shall operate the control 

device at either maximum or minimum 

representative operating conditions for 

monitored control device parameters, 

whichever results in lower emission 

reduction. An owner or operator shall 

not conduct a performance test during 

startup, shutdown, periods when the 

control device is bypassed or periods 

when the process, monitoring 

equipment or control device is not 

operating properly. The owner/operator 

may not conduct performance tests 

during periods of malfunction. The 

owner or operator must record the 

process information that is necessary to 

document operating conditions during 

the test and include in such record an 

explanation to support that the test was 

conducted at maximum representative 

operating capacity. Upon request, the 

owner or operator shall make available 

to the Administrator such records as 

may be necessary to determine the 

conditions of performance tests. 

* * * * * 

(e) All applicable records shall be 

maintained as specified in § 63.655(i). 

* * * * * 

(i) The owner or operator of an 

existing source shall demonstrate 

compliance with the emission standard 

in paragraph (g) of this section by 

following the procedures specified in 

paragraph (k) of this section for all 

emission points, or by following the 

emissions averaging compliance 

approach specified in paragraph (l) of 

this section for specified emission 

points and the procedures specified in 

paragraph (k)(1) of this section. 

* * * * * 

(k) The owner or operator of an 

existing source may comply, and the 

owner or operator of a new source shall 

comply, with the applicable provisions 

in §§ 63.643 through 63.645, 63.646 or 

63.660, 63.647, 63.650, and 63.651, as 

specified in § 63.640(h). 

(1) The owner or operator using this 

compliance approach shall also comply 

with the requirements of §§ 63.648 and/ 

or 63.649 or 63.661, 63.654, 63.655, 

63.657, 63.658, 63.670 and 63.671, as 

applicable. 

* * * * * 

(l) The owner or operator of an 

existing source may elect to control 

some of the emission points within the 

source to different levels than specified 

under §§ 63.643 through 63.645, 63.646 

or 63.660, 63.647, 63.650, and 63.651, as 

applicable according to § 63.640(h), by 

using an emissions averaging 

compliance approach as long as the 

overall emissions for the source do not 

exceed the emission level specified in 

paragraph (g) of this section. The owner 

or operator using emissions averaging 

shall meet the requirements in 

paragraphs (l)(1) and (2) of this section. 

* * * * * 

(2) Comply with the requirements of 

§§ 63.648 and/or 63.649 or 63.661, 

63.654, 63.652, 63.653, 63.655, 63.657, 

63.658, 63.670 and 63.671, as 

applicable. 

* * * * * 

(n) At all times, the owner or operator 

must operate and maintain any affected 

source, including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. The general duty 

to minimize emissions does not require 

the owner operator to make any further 

efforts to reduce emissions if levels 

required by the applicable standard 

have been achieved. Determination of 

whether a source is operating in 

compliance with operation and 

maintenance requirements will be based 

on information available to the 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

■ 16. Section 63.643 is amended by 

revising paragraph (a)(1) to read as 

follows: 

§ 63.643 Miscellaneous process vent 

provisions. 

(a) * * * 

(1) Reduce emissions of organic 

HAP’s using a flare. On and after [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.11(b) of subpart A 

or the requirements of § 63.670. 

* * * * * 

■ 17. Section 63.644 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraph (a)(2); and 

■ c. Revising paragraph (c). 

The revisions read as follows: 

§ 63.644 Monitoring provisions for 

miscellaneous process vents. 

(a) Except as provided in paragraph 

(b) of this section, each owner or 

operator of a Group 1 miscellaneous 

process vent that uses a combustion 

device to comply with the requirements 

in § 63.643(a) shall install the 

monitoring equipment specified in 

paragraph (a)(1), (a)(2), (a)(3), or (a)(4) of 

this section, depending on the type of 

combustion device used. All monitoring 

equipment shall be installed, calibrated, 

maintained, and operated according to 

manufacturer’s specifications or other 

written procedures that provide 

adequate assurance that the equipment 

will monitor accurately and must meet 

the applicable minimum accuracy, 

calibration and quality control 

requirements specified in table 13 of 

this subpart. 

* * * * * 

(2) Where a flare is used prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], a device (including but not 

limited to a thermocouple, an ultraviolet 

beam sensor, or an infrared sensor) 

capable of continuously detecting the 

presence of a pilot flame is required, or 

the requirements of § 63.670 shall be 

met. Where a flare is used on and after 

[THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the 

requirements of § 63.670 shall be met. 

* * * * * 

(c) The owner or operator of a Group 

1 miscellaneous process vent using a 

vent system that contains bypass lines 

that could divert a vent stream away 

from the control device used to comply 

with paragraph (a) of this section shall 

comply with either paragraph (c)(1) or 

(2) of this section. Use of the bypass at 

any time to divert a Group 1 

miscellaneous process vent stream is an 

emissions standards violation. 

Equipment such as low leg drains and 

equipment subject to § 63.648 are not 

subject to this paragraph. 


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(1) Install, operate, calibrate, and 

maintain a continuous parameter 

monitoring system for flow, as specified 

in paragraphs (c)(1)(i) through (iii) of 

this section. 

(i) Install a continuous parameter 

monitoring system for flow at the 

entrance to any bypass line. The 

continuous parameter monitoring 

system must record the volume of the 

gas stream that bypassed the control 

device and must meet the applicable 

minimum accuracy, calibration and 

quality control requirements specified 

in table 13 of this subpart. 

(ii) Equip the continuous parameter 

monitoring system for flow with an 

alarm system that will alert an operator 

immediately and automatically when 

flow is detected in the bypass line. 

Locate the alarm such that an operator 

can easily detect and recognize the alert. 

(iii) Reports and records shall be 

generated as specified in § 63.655(g) and 

(i). 

(2) Secure the bypass line valve in the 

non-diverting position with a car-seal or 

a lock-and-key type configuration. A 

visual inspection of the seal or closure 

mechanism shall be performed at least 

once every month to ensure that the 

valve is maintained in the non-diverting 

position and that the vent stream is not 

diverted through the bypass line. 

* * * * * 

■ 18. Section 63.645 is amended by 

revising paragraphs (e)(1) and (f)(2) to 

read as follows: 

§ 63.645 Test methods and procedures for 

miscellaneous process vents. 

* * * * * 

(e) * * * 

(1) Methods 1 or 1A of 40 CFR part 

60, Appendix A–1, as appropriate, shall 

be used for selection of the sampling 

site. For vents smaller than 0.10 meter 

in diameter, sample at the center of the 

vent. 

* * * * * 

(f) * * * 

(2) The gas volumetric flow rate shall 

be determined using Methods 2, 2A, 2C, 

2D, or 2F of 40 CFR part 60, Appendix 

A–1 or Method 2G of 40 CFR part 60, 

Appendix A–2, as appropriate. 

* * * * * 

■ 19. Section 63.646 is amended by: 

■ a. Adding introductory text to 

§ 63.646; and 

■ b. Revising paragraph (b)(2). 

The revisions and additions read as 

follows: 

§ 63.646 Storage vessel provisions. 

Upon a demonstration of compliance 

with the standards in § 63.660 by the 

compliance dates specified in 

§ 63.640(h), the standards in this section 

shall no longer apply. 

* * * * * 

(b) * * * 

(2) When an owner or operator and 

the Administrator do not agree on 

whether the annual average weight 

percent organic HAP in the stored liquid 

is above or below 4 percent for a storage 

vessel at an existing source or above or 

below 2 percent for a storage vessel at 

a new source, an appropriate method 

(based on the type of liquid stored) as 

published by EPA or a consensus-based 

standards organization shall be used. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street NW., 6th Floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http://

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http://

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.naesb.org). 

* * * * * 

■ 20. Section 63.647 is amended by: 

■ a. Revising paragraph (a); 

■ b. Redesignating paragraph (c) as 

paragraph (d); and 

■ c. Adding paragraph (c). 

The revisions and additions read as 

follows: 

§ 63.647 Wastewater provisions. 

(a) Except as provided in paragraphs 

(b) and (c) of this section, each owner 

or operator of a Group 1 wastewater 

stream shall comply with the 

requirements of §§ 61.340 through 

61.355 of this chapter for each process 

wastewater stream that meets the 

definition in § 63.641. 

* * * * * 

(c) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of part 61, 

subpart FF of this chapter, or the 

requirements of § 63.670. 

* * * * * 

■ 21. Section 63.648 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Adding paragraphs (a)(3) and (4); 

■ c. Revising paragraph (c) introductory 

text; 

■ d. Revising paragraph (c)(2)(ii); 

■ e. Adding paragraphs (c)(11) and (12); 

and 

■ f. Adding paragraph (j). 

The revisions and additions read as 

follows: 

§ 63.648 Equipment leak standards. 

(a) Each owner or operator of an 

existing source subject to the provisions 

of this subpart shall comply with the 

provisions of part 60, subpart VV of this 

chapter and paragraph (b) of this section 

except as provided in paragraphs (a)(1), 

(a)(2), and (c) through (i) of this section. 

Each owner or operator of a new source 

subject to the provisions of this subpart 

shall comply with subpart H of this part 

except as provided in paragraphs (c) 

through (i) of this section. As an 

alternative to the monitoring 

requirements of part 60, subpart VV of 

this chapter or subpart H of this part, as 

applicable, the owner or operator may 

elect to monitor equipment leaks 

following the provisions in § 63.661. 

* * * * * 

(3) On and after [THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], for the purpose of 

complying with the requirements of 

§ 60.482–6(a)(2) of this chapter, the term 

‘‘seal’’ or ‘‘sealed’’ means that 

instrument monitoring of the openended valve or line conducted 

according to the method specified in 

§ 60.485(b) and, as applicable, 

§ 60.485(c) of this chapter indicates no 

readings of 500 parts per million or 

greater. 

(4) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of part 60, 

subpart VV of this chapter, or the 

requirements of § 63.670. 

* * * * * 


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36970 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

(c) In lieu of complying with the 

existing source provisions of paragraph 

(a) in this section, an owner or operator 

may elect to comply with the 

requirements of §§ 63.161 through 

63.169, 63.171, 63.172, 63.175, 63.176, 

63.177, 63.179, and 63.180 of subpart H 

of this part except as provided in 

paragraphs (c)(1) through (c)(12) and (e) 

through (i) of this section. 

* * * * * 

(2) * * * 

(ii) If an owner or operator elects to 

monitor connectors according to the 

provisions of § 63.649, paragraphs (b), 

(c), or (d), then the owner or operator 

shall monitor valves at the frequencies 

specified in table 9 of this subpart. If an 

owner or operator elects to comply with 

§ 63.649, the owner or operator cannot 

also elect to comply with § 63.661. 

* * * * * 

(11) On and after [THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], for the purpose of 

complying with the requirements of 

§ 63.167(a)(2), the term ‘‘seal’’ or 

‘‘sealed’’ means that instrument 

monitoring of the open-ended valve or 

line conducted according to the method 

specified in § 63.180(b) and, as 

applicable, § 63.180(c) of this chapter 

indicates no readings of 500 parts per 

million or greater. 

(12) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of §§ 63.172 

and 63.180, or the requirements of 

§ 63.670. 

* * * * * 

(j) Except as specified in paragraph 

(j)(4) of this section, the owner or 

operator must comply with the 

requirements specified in paragraphs 

(j)(1) and (2) of this section for relief 

valves in organic HAP gas or vapor 

service instead of the pressure relief 

device requirements of § 60.482–4 or 

§ 63.165, as applicable. Except as 

specified in paragraph (j)(4) of this 

section, the owner or operator must also 

comply with the requirements specified 

in paragraph (j)(3) of this section for all 

relief valves in organic HAP service. 

(1) Operating requirements. Except 

during a pressure release, operate each 

relief valve in organic HAP gas or vapor 

service with an instrument reading of 

less than 500 ppm above background as 

detected by Method 21 of 40 CFR part 

60, Appendix A–7. 

(2) Pressure release requirements. For 

relief valves in organic HAP gas or 

vapor service, the owner or operator 

must comply with either paragraph 

(j)(2)(i) or (ii) of this section following 

a pressure release. 

(i) If the relief valve does not consist 

of or include a rupture disk, conduct 

instrument monitoring, as specified in 

§ 60.485(b) or § 63.180(c), as applicable, 

no later than 5 calendar days after the 

relief valve returns to organic HAP gas 

or vapor service following a pressure 

release to verify that the relief valve is 

operating with an instrument reading of 

less than 500 ppm. 

(ii) If the relief valve consists of or 

includes a rupture disk, install a 

replacement disk as soon as practicable 

after a pressure release, but no later than 

5 calendar days after the pressure 

release. The owner or operator must also 

conduct instrument monitoring, as 

specified in § 60.485(b) or § 63.180(c), as 

applicable, no later than 5 calendar days 

after the relief valve returns to organic 

HAP gas or vapor service following a 

pressure release to verify that the relief 

valve is operating with an instrument 

reading of less than 500 ppm. 

(3) Pressure release management. 

Except as specified in paragraph (j)(4) of 

this section, emissions of organic HAP 

may not be discharged to the 

atmosphere from relief valves in organic 

HAP service, and on or before [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the owner or operator shall 

comply with the requirements specified 

in paragraphs (j)(3)(i) and (ii) of this 

section for all relief valves in organic 

HAP service. 

(i) The owner or operator must equip 

each relief valve in organic HAP service 

with a device(s) or use a monitoring 

system that is capable of: (1) Identifying 

the pressure release; (2) recording the 

time and duration of each pressure 

release; and (3) notifying operators 

immediately that a pressure release is 

occurring. The device or monitoring 

system may be either specific to the 

pressure relief device itself or may be 

associated with the process system or 

piping, sufficient to indicate a pressure 

release to the atmosphere. Examples of 

these types of devices and systems 

include, but are not limited to, a rupture 

disk indicator, magnetic sensor, motion 

detector on the pressure relief valve 

stem, flow monitor, or pressure monitor. 

(ii) If any relief valve in organic HAP 

service vents or releases to atmosphere 

as a result of a pressure release event, 

the owner or operator must calculate the 

quantity of organic HAP released during 

each pressure release event and report 

this quantity as required in 

§ 63.655(g)(10)(iii). Calculations may be 

based on data from the relief valve 

monitoring alone or in combination 

with process parameter monitoring data 

and process knowledge. 

(4) Relief valves routed to a control 

device. If all releases and potential leaks 

from a relief valve in organic HAP 

service are routed through a closed vent 

system to a control device, the owner or 

operator is not required to comply with 

paragraphs (j)(1), (2) or (3) (if applicable) 

of this section. Both the closed vent 

system and control device (if applicable) 

must meet the requirements of § 63.644. 

When complying with this paragraph, 

all references to ‘‘Group 1 miscellaneous 

process vent’’ in 63.644 mean ‘‘relief 

valve.’’ 

■ 22. Section 63.650 is amended by 

revising paragraph (a) and adding 

paragraph (d) to read as follows: 

§ 63.650 Gasoline loading rack provisions. 

(a) Except as provided in paragraphs 

(b) through (d) of this section, each 

owner or operator of a Group 1 gasoline 

loading rack classified under Standard 

Industrial Classification code 2911 

located within a contiguous area and 

under common control with a 

petroleum refinery shall comply with 

subpart R, §§ 63.421, 63.422(a) through 

(c) and (e), 63.425(a) through (c) and (i), 

63.425(e) through (h), 63.427(a) and (b), 

and 63.428(b), (c), (g)(1), (h)(1) through 

(3), and (k). 

* * * * * 

(d) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of subpart R of 

this part, or the requirements of 

§ 63.670. 

■ 23. Section 63.651 is amended by 

revising paragraph (a) and adding 

paragraph (e) to read as follows: 

§ 63.651 Marine tank vessel loading 

operation provisions. 

(a) Except as provided in paragraphs 

(b) through (e) of this section, each 

owner or operator of a marine tank 

vessel loading operation located at a 

petroleum refinery shall comply with 


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the requirements of §§ 63.560 through 

63.568. 

* * * * * 

(e) If a flare is used as a control 

device, on and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the 

applicable requirements of subpart Y of 

this part, or the requirements of 

§ 63.670. 

■ 24. Section 63.652 is amended by: 

■ a. Revising paragraph (a); 

■ b. Removing and reserving paragraph 

(f)(2); 

■ c. Revising paragraph (g)(2)(iii)(B)(1); 

■ d. Revising paragraph (h)(3); 

■ e. Revising paragraph (k) introductory 

text; and 

■ f. Revising paragraph (k)(3). 

The revisions and additions read as 

follows: 

§ 63.652 Emissions averaging provisions. 

(a) This section applies to owners or 

operators of existing sources who seek 

to comply with the emission standard in 

§ 63.642(g) by using emissions averaging 

according to § 63.642(l) rather than 

following the provisions of §§ 63.643 

through 63.645, 63.646 or 63.660, 

63.647, 63.650, and 63.651. Existing 

marine tank vessel loading operations 

located at the Valdez Marine Terminal 

source may not comply with the 

standard by using emissions averaging. 

* * * * * 

(g) * * * 

(2) * * * 

(iii) * * * 

(B) * * * 

(1) The percent reduction shall be 

measured according to the procedures 

in § 63.116 of subpart G if a combustion 

control device is used. For a flare 

meeting the criteria in § 63.116(a) of 

subpart G or § 63.670 of this subpart, as 

applicable, or a boiler or process heater 

meeting the criteria in § 63.645(d) of this 

subpart or § 63.116(b) of subpart G, the 

percentage of reduction shall be 98 

percent. If a noncombustion control 

device is used, percentage of reduction 

shall be demonstrated by a performance 

test at the inlet and outlet of the device, 

or, if testing is not feasible, by a control 

design evaluation and documented 

engineering calculations. 

* * * * * 

(h) * * * 

(3) Emissions from storage vessels 

shall be determined as specified in 

§ 63.150(h)(3) of subpart G, except as 

follows: 

(i) For storage vessels complying with 

§ 63.646: 

(A) All references to § 63.119(b) in 

§ 63.150(h)(3) of subpart G shall be 

replaced with: § 63.119(b) or § 63.119(b) 

except for § 63.119(b)(5) and (b)(6). 

(B) All references to § 63.119(c) in 

§ 63.150(h)(3) of subpart G shall be 

replaced with: § 63.119(c) or § 63.119(c) 

except for § 63.119(c)(2). 

(C) All references to § 63.119(d) in 

§ 63.150(h)(3) of subpart G shall be 

replaced with: § 63.119(d) or § 63.119(d) 

except for § 63.119(d)(2). 

(ii) For storage vessels complying 

with § 63.660: 

(A) Sections 63.1063(a)(1)(i), (a)(2), 

and (b) or §§ 63.1063(a)(1)(i) and (b) 

shall apply instead of § 63.119(b) in 

§ 63.150(h)(3) of subpart G. 

(B) Sections 63.1063(a)(1)(ii), (a)(2), 

and (b) shall apply instead of § 63.119(c) 

in § 63.150(h)(3) of subpart G. 

(C) Sections 63.1063(a)(1)(i), (a)(2), 

and (b) or §§ 63.1063(a)(1)(i) and (b) 

shall apply instead of § 63.119(d) in 

§ 63.150(h)(3) of subpart G. 

* * * * * 

(k) The owner or operator shall 

demonstrate that the emissions from the 

emission points proposed to be 

included in the average will not result 

in greater hazard or, at the option of the 

State or local permitting authority, 

greater risk to human health or the 

environment than if the emission points 

were controlled according to the 

provisions in §§ 63.643 through 63.645, 

63.646 or 63.660, 63.647, 63.650, and 

63.651, as applicable. 

* * * * * 

(3) An emissions averaging plan that 

does not demonstrate an equivalent or 

lower hazard or risk to the satisfaction 

of the State or local permitting authority 

shall not be approved. The State or local 

permitting authority may require such 

adjustments to the emissions averaging 

plan as are necessary in order to ensure 

that the average will not result in greater 

hazard or risk to human health or the 

environment than would result if the 

emission points were controlled 

according to §§ 63.643 through 63.645, 

63.646 or 63.660, 63.647, 63.650, and 

63.651, as applicable. 

* * * * * 

■ 25. Section 63.653 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraphs (a)(3)(i) and 

(ii); and 

■ c. Revising paragraph (a)(7). 

The revisions read as follows: 

§ 63.653 Monitoring, recordkeeping, and 

implementation plan for emissions 

averaging. 

(a) For each emission point included 

in an emissions average, the owner or 

operator shall perform testing, 

monitoring, recordkeeping, and 

reporting equivalent to that required for 

Group 1 emission points complying 

with §§ 63.643 through 63.645, 63.646 

or 63.660, 63.647, 63.650, and 63.651, as 

applicable. The specific requirements 

for miscellaneous process vents, storage 

vessels, wastewater, gasoline loading 

racks, and marine tank vessels are 

identified in paragraphs (a)(1) through 

(7) of this section. 

* * * * * 

(3) * * * 

(i) Perform the monitoring or 

inspection procedures in § 63.646 and 

either § 63.120 of subpart G or § 63.1063 

of subpart WW, as applicable; and 

(ii) For closed vent systems with 

control devices, conduct an initial 

design evaluation as specified in 

§ 63.646 and either § 63.120(d) of 

subpart G or § 63.985(b) of subpart SS, 

as applicable. 

* * * * * 

(7) If an emission point in an 

emissions average is controlled using a 

pollution prevention measure or a 

device or technique for which no 

monitoring parameters or inspection 

procedures are specified in §§ 63.643 

through 63.645, 63.646 or 63.660, 

63.647, 63.650, and 63.651, as 

applicable, the owner or operator shall 

establish a site-specific monitoring 

parameter and shall submit the 

information specified in § 63.655(h)(4) 

in the Implementation Plan. 

* * * * * 

■ 26. Section 63.655 is amended by: 

■ a. Revising paragraph (f) introductory 

text; 

■ b. Revising paragraph (f)(1) 

introductory text; 

■ c. Revising paragraph (f)(1)(i)(A) 

introductory text; 

■ d. Revising paragraphs (f)(1)(i)(A)(2) 

and (3); 

■ e. Revising paragraph (f)(1)(i)(B) 

introductory text; 

■ f. Revising paragraph (f)(1)(i)(B)(2); 

■ g. Revising paragraph (f)(1)(i)(D)(2); 

■ h. Revising paragraph (f)(1)(iv) 

introductory text; 

■ i. Revising paragraph (f)(1)(iv)(A); 

■ j. Adding paragraph (f)(1)(vii); 

■ k. Revising paragraph (f)(2) 

introductory text; 

■ l. Revising paragraph (f)(3) 

introductory text; 

■ m. Revising paragraph (f)(6); 

■ n. Revising paragraph (g) introductory 

text; 


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36972 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

■ o. Revising paragraphs (g)(1) through 

(5); 

■ p. Revising paragraph (g)(6)(iii); 

■ q. Revising paragraph (g)(7)(i); 

■ r. Adding paragraphs (g)(10) through 

(13); 

■ s. Removing and reserving paragraph 

(h)(1); 

■ t. Revising paragraph (h)(2) 

introductory text; 

■ u. Revising paragraph (h)(2)(i)(B); 

■ v. Revising paragraph (h)(2)(ii); 

■ w. Adding paragraphs (h)(8) and (9); 

■ x. Adding paragraph (i) introductory 

text; 

■ y. Revising paragraph (i)(1) 

introductory text; 

■ z. Revising paragraph (i)(1)(ii); 

■ aa. Adding paragraphs (i)(1)(v) and 

(vi); 

■ bb. Redesignating paragraph (i)(4) and 

(5) as (i)(5) and (6) respectively; 

■ cc. Adding paragraph (i)(4); 

■ dd. Revising newly redesignated 

paragraph (i)(5) introductory text; and 

■ ee. Adding paragraphs (i)(7) through 

(11). 

The revisions and additions read as 

follows: 

§ 63.655 Reporting and recordkeeping 

requirements. 

* * * * * 

(f) Each owner or operator of a source 

subject to this subpart shall submit a 

Notification of Compliance Status report 

within 150 days after the compliance 

dates specified in § 63.640(h) with the 

exception of Notification of Compliance 

Status reports submitted to comply with 

§ 63.640(l)(3) and for storage vessels 

subject to the compliance schedule 

specified in § 63.640(h)(2). Notification 

of Compliance Status reports required 

by § 63.640(l)(3) and for storage vessels 

subject to the compliance dates 

specified in § 63.640(h)(2) shall be 

submitted according to paragraph (f)(6) 

of this section. This information may be 

submitted in an operating permit 

application, in an amendment to an 

operating permit application, in a 

separate submittal, or in any 

combination of the three. If the required 

information has been submitted before 

the date 150 days after the compliance 

date specified in § 63.640(h), a separate 

Notification of Compliance Status report 

is not required within 150 days after the 

compliance dates specified in 

§ 63.640(h). If an owner or operator 

submits the information specified in 

paragraphs (f)(1) through (f)(5) of this 

section at different times, and/or in 

different submittals, later submittals 

may refer to earlier submittals instead of 

duplicating and resubmitting the 

previously submitted information. Each 

owner or operator of a gasoline loading 

rack classified under Standard 

Industrial Classification Code 2911 

located within a contiguous area and 

under common control with a 

petroleum refinery subject to the 

standards of this subpart shall submit 

the Notification of Compliance Status 

report required by subpart R of this part 

within 150 days after the compliance 

dates specified in § 63.640(h) of this 

subpart. 

(1) The Notification of Compliance 

Status report shall include the 

information specified in paragraphs 

(f)(1)(i) through (f)(1)(vii) of this section. 

(i) * * * 

(A) Identification of each storage 

vessel subject to this subpart, and for 

each Group 1 storage vessel subject to 

this subpart, the information specified 

in paragraphs (f)(1)(i)(A)(1) through 

(f)(1)(i)(A)(3) of this section. This 

information is to be revised each time a 

Notification of Compliance Status report 

is submitted for a storage vessel subject 

to the compliance schedule specified in 

§ 63.640(h)(2) or to comply with 

§ 63.640(l)(3). 

* * * * * 

(2) For storage vessels subject to the 

compliance schedule specified in 

§ 63.640(h)(2) that are not complying 

with § 63.646, the anticipated 

compliance date. 

(3) For storage vessels subject to the 

compliance schedule specified in 

§ 63.640(h)(2) that are complying with 

§ 63.646 and the Group 1 storage vessels 

described in § 63.640(l), the actual 

compliance date. 

(B) If a closed vent system and a 

control device other than a flare is used 

to comply with § 63.646 or § 63.660, the 

owner or operator shall submit: 

* * * * * 

(2) The design evaluation 

documentation specified in 

§ 63.120(d)(1)(i) of subpart G or 

§ 63.985(b)(1)(i) of subpart SS (as 

applicable), if the owner or operator 

elects to prepare a design evaluation; or 

* * * * * 

(D) * * * 

(2) All visible emission readings, heat 

content determinations, flow rate 

measurements, and exit velocity 

determinations made during the 

compliance determination required by 

§ 63.120(e) of subpart G or § 63.987(b) of 

subpart SS or § 63.670(h), as applicable; 

and 

* * * * * 

(iv) For miscellaneous process vents 

controlled by flares, initial compliance 

test results including the information in 

paragraphs (f)(1)(iv)(A) and (B) of this 

section; 

(A) All visible emission readings, heat 

content determinations, flow rate 

measurements, and exit velocity 

determinations made during the 

compliance determination required by 

§ 63.645 of this subpart and § 63.116(a) 

of subpart G of this part or § 63.670(h) 

of this subpart, as applicable, and 

* * * * * 

(vii) For relief valves in organic HAP 

service, a description of the monitoring 

system to be implemented, including 

the relief valves and process parameters 

to be monitored, and a description of 

the alarms or other methods by which 

operators will be notified of a pressure 

release. 

(2) If initial performance tests are 

required by §§ 63.643 through 63.653 of 

this subpart, the Notification of 

Compliance Status report shall include 

one complete test report for each test 

method used for a particular source. On 

and after [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], performance 

tests shall be submitted according to 

paragraph (h)(9) of this section. 

* * * * * 

(3) For each monitored parameter for 

which a range is required to be 

established under § 63.120(d) of subpart 

G or § 63.985(b) of subpart SS for storage 

vessels or § 63.644 for miscellaneous 

process vents, the Notification of 

Compliance Status report shall include 

the information in paragraphs (f)(3)(i) 

through (f)(3)(iii) of this section. 

* * * * * 

(6) Notification of Compliance Status 

reports required by § 63.640(l)(3) and for 

storage vessels subject to the 

compliance dates specified in 

§ 63.640(h)(2) shall be submitted no 

later than 60 days after the end of the 

6-month period during which the 

change or addition was made that 

resulted in the Group 1 emission point 

or the existing Group 1 storage vessel 

was brought into compliance, and may 

be combined with the periodic report. 

Six-month periods shall be the same 6- 

month periods specified in paragraph 

(g) of this section. The Notification of 

Compliance Status report shall include 

the information specified in paragraphs 

(f)(1) through (f)(5) of this section. This 

information may be submitted in an 

operating permit application, in an 

amendment to an operating permit 

application, in a separate submittal, as 

part of the periodic report, or in any 

combination of these four. If the 

required information has been 

submitted before the date 60 days after 

the end of the 6-month period in which 

the addition of the Group 1 emission 


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point took place, a separate Notification 

of Compliance Status report is not 

required within 60 days after the end of 

the 6-month period. If an owner or 

operator submits the information 

specified in paragraphs (f)(1) through 

(f)(5) of this section at different times, 

and/or in different submittals, later 

submittals may refer to earlier 

submittals instead of duplicating and 

resubmitting the previously submitted 

information. 

(g) The owner or operator of a source 

subject to this subpart shall submit 

Periodic Reports no later than 60 days 

after the end of each 6-month period 

when any of the information specified 

in paragraphs (g)(1) through (7) of this 

section or paragraphs (g)(9) through (12) 

of this section is collected. The first 6- 

month period shall begin on the date the 

Notification of Compliance Status report 

is required to be submitted. A Periodic 

Report is not required if none of the 

events identified in paragraph (g)(1) 

through (7) of this section or paragraphs 

(g)(9) through (12) of this section 

occurred during the 6-month period 

unless emissions averaging is utilized. 

Quarterly reports must be submitted for 

emission points included in emission 

averages, as provided in paragraph (g)(8) 

of this section. An owner or operator 

may submit reports required by other 

regulations in place of or as part of the 

Periodic Report required by this 

paragraph if the reports contain the 

information required by paragraphs 

(g)(1) through (12) of this section. 

(1) For storage vessels, Periodic 

Reports shall include the information 

specified for Periodic Reports in 

paragraph (g)(2) through (g)(5) of this 

section. Information related to gaskets, 

slotted membranes, and sleeve seals is 

not required for storage vessels that are 

part of an existing source complying 

with § 63.646. 

(2) Internal floating roofs. (i) An 

owner or operator who elects to comply 

with § 63.646 by using a fixed roof and 

an internal floating roof or by using an 

external floating roof converted to an 

internal floating roof shall submit the 

results of each inspection conducted in 

accordance with § 63.120(a) of subpart G 

in which a failure is detected in the 

control equipment. 

(A) For vessels for which annual 

inspections are required under 

§ 63.120(a)(2)(i) or (a)(3)(ii) of subpart G, 

the specifications and requirements 

listed in paragraphs (g)(2)(i)(A)(1) 

through (3) of this section apply. 

(1) A failure is defined as any time in 

which the internal floating roof is not 

resting on the surface of the liquid 

inside the storage vessel and is not 

resting on the leg supports; or there is 

liquid on the floating roof; or the seal is 

detached from the internal floating roof; 

or there are holes, tears, or other 

openings in the seal or seal fabric; or 

there are visible gaps between the seal 

and the wall of the storage vessel. 

(2) Except as provided in paragraph 

(g)(2)(i)(C) of this section, each Periodic 

Report shall include the date of the 

inspection, identification of each storage 

vessel in which a failure was detected, 

and a description of the failure. The 

Periodic Report shall also describe the 

nature of and date the repair was made 

or the date the storage vessel was 

emptied. 

(3) If an extension is utilized in 

accordance with § 63.120(a)(4) of 

subpart G, the owner or operator shall, 

in the next Periodic Report, identify the 

vessel; include the documentation 

specified in § 63.120(a)(4) of subpart G; 

and describe the date the storage vessel 

was emptied and the nature of and date 

the repair was made. 

(B) For vessels for which inspections 

are required under § 63.120(a)(2)(ii), 

(a)(3)(i), or (a)(3)(iii) of subpart G (i.e., 

internal inspections), the specifications 

and requirements listed in paragraphs 

(g)(2)(i)(B)(1) and (2) of this section 

apply. 

(1) A failure is defined as any time in 

which the internal floating roof has 

defects; or the primary seal has holes, 

tears, or other openings in the seal or 

the seal fabric; or the secondary seal (if 

one has been installed) has holes, tears, 

or other openings in the seal or the seal 

fabric; or, for a storage vessel that is part 

of a new source, the gaskets no longer 

close off the liquid surface from the 

atmosphere; or, for a storage vessel that 

is part of a new source, the slotted 

membrane has more than a 10 percent 

open area. 

(2) Each Periodic Report shall include 

the date of the inspection, identification 

of each storage vessel in which a failure 

was detected, and a description of the 

failure. The Periodic Report shall also 

describe the nature of and date the 

repair was made. 

(ii) An owner or operator who elects 

to comply with § 63.660 by using a fixed 

roof and an internal floating roof shall 

submit the results of each inspection 

conducted in accordance with 

§ 63.1063(c)(1), (d)(1), and (d)(2) of 

subpart WW in which a failure is 

detected in the control equipment. For 

vessels for which inspections are 

required under § 63.1063(c) and (d), the 

specifications and requirements listed 

in paragraphs (g)(2)(ii)(A) through 

(g)(2)(ii)(C) of this section apply. 

(A) A failure is defined in 

§ 63.1063(d)(1) of subpart WW. 

(B) Each Periodic Report shall include 

a copy of the inspection record required 

by § 63.1065(b) of subpart WW when a 

failure occurs. 

(C) An owner or operator who elects 

to use an extension in accordance with 

§ 63.1063(e)(2) of subpart WW shall, in 

the next Periodic Report, submit the 

documentation required by 

§ 63.1063(e)(2). 

(3) External floating roofs. (i) An 

owner or operator who elects to comply 

with § 63.646 by using an external 

floating roof shall meet the periodic 

reporting requirements specified in 

paragraphs (g)(3)(i)(A) and (B) of this 

section. 

(A) The owner or operator shall 

submit, as part of the Periodic Report, 

documentation of the results of each 

seal gap measurement made in 

accordance with § 63.120(b) of subpart 

G in which the seal and seal gap 

requirements of § 63.120(b)(3), (b)(4), 

(b)(5), or (b)(6) of subpart G are not met. 

This documentation shall include the 

information specified in paragraphs 

(g)(3)(i)(A)(1) through (4) of this section. 

(1) The date of the seal gap 

measurement. 

(2) The raw data obtained in the seal 

gap measurement and the calculations 

described in § 63.120(b)(3) and (b)(4) of 

subpart G. 

(3) A description of any seal condition 

specified in § 63.120(b)(5) or (b)(6) of 

subpart G that is not met. 

(4) A description of the nature of and 

date the repair was made, or the date the 

storage vessel was emptied. 

(B) If an extension is utilized in 

accordance with § 63.120(b)(7)(ii) or 

(b)(8) of subpart G, the owner or 

operator shall, in the next Periodic 

Report, identify the vessel; include the 

documentation specified in 

§ 63.120(b)(7)(ii) or (b)(8) of subpart G, 

as applicable; and describe the date the 

vessel was emptied and the nature of 

and date the repair was made. 

(C) The owner or operator shall 

submit, as part of the Periodic Report, 

documentation of any failures that are 

identified during visual inspections 

required by § 63.120(b)(10) of subpart G. 

This documentation shall meet the 

specifications and requirements in 

paragraphs (g)(3)(i)(C)(1) and (2) of this 

section. 

(1) A failure is defined as any time in 

which the external floating roof has 

defects; or the primary seal has holes or 

other openings in the seal or the seal 

fabric; or the secondary seal has holes, 

tears, or other openings in the seal or 

the seal fabric; or, for a storage vessel 

that is part of a new source, the gaskets 

no longer close off the liquid surface 

from the atmosphere; or, for a storage 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36974 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

vessel that is part of a new source, the 

slotted membrane has more than 10 

percent open area. 

(2) Each Periodic Report shall include 

the date of the inspection, identification 

of each storage vessel in which a failure 

was detected, and a description of the 

failure. The Periodic Report shall also 

describe the nature of and date the 

repair was made. 

(ii) An owner or operator who elects 

to comply with § 63.660 by using an 

external floating roof shall meet the 

periodic reporting requirements 

specified in paragraphs (g)(3)(ii)(A) and 

(B) of this section. 

(A) For vessels for which inspections 

are required under § 63.1063(c)(2), 

(d)(1), and (d)(3) of subpart WW, the 

owner or operator shall submit, as part 

of the Periodic Report, a copy of the 

inspection record required by 

§ 63.1065(b) of subpart WW when a 

failure occurs. A failure is defined in 

§ 63.1063(d)(1). 

(B) An owner or operator who elects 

to use an extension in accordance with 

§ 63.1063(e)(2) or § 63.1063(c)(2)(iv)(B) 

of subpart WW shall, in the next 

Periodic Report, submit the 

documentation required by those 

paragraphs. 

(4) An owner or operator who elects 

to comply with § 63.646 or § 63.660 by 

using an external floating roof converted 

to an internal floating roof shall comply 

with the periodic reporting 

requirements of paragraph (g)(2)(i) of 

this section. 

(5) An owner or operator who elects 

to comply with § 63.646 or § 63.660 by 

installing a closed vent system and 

control device shall submit, as part of 

the next Periodic Report, the 

information specified in paragraphs 

(g)(5)(i) through (g)(5)(iii) of this section, 

as applicable. 

(i) The Periodic Report shall include 

the information specified in paragraphs 

(g)(5)(i)(A) and (B) of this section for 

those planned routine maintenance 

operations that would require the 

control device not to meet the 

requirements of either § 63.119(e)(1) or 

(e)(2) of subpart G, § 63.985(a) and (b) of 

subpart SS, or § 63.670, as applicable. 

(A) A description of the planned 

routine maintenance that is anticipated 

to be performed for the control device 

during the next 6 months. This 

description shall include the type of 

maintenance necessary, planned 

frequency of maintenance, and lengths 

of maintenance periods. 

(B) A description of the planned 

routine maintenance that was performed 

for the control device during the 

previous 6 months. This description 

shall include the type of maintenance 

performed and the total number of 

hours during those 6 months that the 

control device did not meet the 

requirements of either § 63.119(e)(1) or 

(2) of subpart G, § 63.985(a) and (b) of 

subpart SS, or § 63.670, as applicable, 

due to planned routine maintenance. 

(ii) If a control device other than a 

flare is used, the Periodic Report shall 

describe each occurrence when the 

monitored parameters were outside of 

the parameter ranges documented in the 

Notification of Compliance Status 

report. The description shall include: 

Identification of the control device for 

which the measured parameters were 

outside of the established ranges, and 

causes for the measured parameters to 

be outside of the established ranges. 

(iii) If a flare is used prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER] and prior to electing to 

comply with the requirements in 

§ 63.670, the Periodic Report shall 

describe each occurrence when the flare 

does not meet the general control device 

requirements specified in § 63.11(b) of 

subpart A of this part and shall include: 

Identification of the flare that does not 

meet the general requirements specified 

in § 63.11(b) of subpart A of this part, 

and reasons the flare did not meet the 

general requirements specified in 

§ 63.11(b) of subpart A of this part. 

(iv) If a flare is used on and after 

compliance with the requirements in 

§ 63.670 is elected, which can be no 

later than [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the Periodic 

Report shall include the items specified 

in paragraph (g)(11) of this section. 

(v) An owner or operator who elects 

to comply with § 63.660 by installing an 

alternate control device as described in 

§ 63.1064 of subpart WW shall submit, 

as part of the next Periodic Report, a 

written application as described in 

§ 63.1066(b)(3) of subpart WW. 

(6) * * * 

(iii) For closed vent systems, include 

the records of periods when vent stream 

flow was detected in the bypass line or 

diverted from the control device, a flow 

indicator was not operating or a bypass 

of the system was indicated, as specified 

in paragraph (i)(4) of this section. 

(7) * * * 

(i) Results of the performance test 

shall include the identification of the 

source tested, the date of the test, the 

percentage of emissions reduction or 

outlet pollutant concentration reduction 

(whichever is needed to determine 

compliance) for each run and for the 

average of all runs, and the values of the 

monitored operating parameters. 

* * * * * 

(10) For relief valves, Periodic Reports 

must include the information specified 

in paragraphs (g)(10)(i) through (iii) of 

this section. 

(i) For relief valves in organic HAP 

gas or vapor service, pursuant to 

§ 63.648(j), report any instrument 

reading of 500 ppm or greater, more 

than 5 days after the relief valve returns 

to service after a pressure release. 

(ii) For relief valves in organic HAP 

gas or vapor service subject to 

§ 63.648(j)(2), report confirmation that 

all monitoring to show compliance was 

conducted within the reporting period. 

(iii) For relief valves in organic HAP 

service, report each pressure release to 

the atmosphere, including duration of 

the pressure release and estimate of 

quantity of substances released. 

(11) For flares subject to § 63.670, 

Periodic Reports must include the 

information specified in paragraphs 

(g)(11)(i) through (iii) of this section. 

(i) Records as specified in paragraph 

(i)(9)(i) of this section for each period 

when regulated material is routed to a 

flare and a pilot flame is not present. 

(ii) Visible emission records as 

specified in paragraph (i)(9)(ii) of this 

section for each period of 2 consecutive 

hours during which visible emissions 

exceeded a total of 5 minutes. 

(iii) The 15-minute block periods for 

which the applicable operating limits 

specified in § 63.670(d) through (f) are 

not met. Indicate the date and time for 

the period, the 15-minute block average 

operating parameters determined 

following the methods in § 63.670(k) 

through (o) as applicable, and an 

indication of whether the three criteria 

in § 63.670(e)(vi) were all met for that 

15-minute block period. 

(iv) Records as specified in paragraph 

(i)(9)(x) of this section for each period 

when a halogenated vent stream as 

defined in § 63.641 is discharged to the 

flare. 

(12) If a source fails to meet an 

applicable standard, report such events 

in the Periodic Report. Report the 

number of failures to meet an applicable 

standard. For each instance, report the 

date, time and duration of each failure. 

For each failure the report must include 

a list of the affected sources or 

equipment, an estimate of the quantity 

of each regulated pollutant emitted over 

any emission limit, and a description of 

the method used to estimate the 

emissions. 

(13) Any changes in the information 

provided in a previous Notification of 

Compliance Status report. 


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(h) * * * 

(2) For storage vessels, notifications of 

inspections as specified in paragraphs 

(h)(2)(i) and (h)(2)(ii) of this section. 

(i) * * * 

(B) Except as provided in paragraph 

(h)(2)(i)(C) of this section, if the internal 

inspection required by § 63.120(a)(2), 

§ 63.120(a)(3), or § 63.120(b)(10) of 

subpart G or § 63.1063(d)(1) of subpart 

WW is not planned and the owner or 

operator could not have known about 

the inspection 30 calendar days in 

advance of refilling the vessel with 

organic HAP, the owner or operator 

shall notify the Administrator at least 7 

calendar days prior to refilling of the 

storage vessel. Notification may be made 

by telephone and immediately followed 

by written documentation 

demonstrating why the inspection was 

unplanned. This notification, including 

the written documentation, may also be 

made in writing and sent so that it is 

received by the Administrator at least 7 

calendar days prior to the refilling. 

* * * * * 

(ii) In order to afford the 

Administrator the opportunity to have 

an observer present, the owner or 

operator of a storage vessel equipped 

with an external floating roof shall 

notify the Administrator of any seal gap 

measurements. The notification shall be 

made in writing at least 30 calendar 

days in advance of any gap 

measurements required by § 63.120(b)(1) 

or (b)(2) of subpart G or § 63.1062(d)(3) 

of subpart WW. The State or local 

permitting authority can waive this 

notification requirement for all or some 

storage vessels subject to the rule or can 

allow less than 30 calendar days’ notice. 

* * * * * 

(8) For fenceline monitoring systems 

subject to § 63.658, within 45 calendar 

days after the end of each semiannual 

reporting period, each owner or operator 

shall submit the following information 

to the EPA’s Compliance and Emissions 

Data Reporting Interface (CEDRI) that is 

accessed through the EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

The owner or operator need not transmit 

this data prior to obtaining 12 months 

of data. 

(i) Individual sample results for each 

monitor for each sampling episode 

during the semiannual reporting period. 

For the first reporting period and for any 

period in which a passive monitor is 

added or moved, the owner or operator 

shall report the coordinates of all of the 

passive monitor locations. The owner or 

operator shall determine the coordinates 

using an instrument with an accuracy of 

at least 3 meters. Coordinates shall be in 

decimal degrees with at least five 

decimal places. 

(ii) The biweekly 12-month rolling 

average concentration difference (Dc) 

values for benzene for the semiannual 

reporting period. 

(iii) Notation for each biweekly value 

that indicates whether background 

correction was used, all measurements 

in the sampling period were below 

detection, or whether an outlier was 

removed from the sampling period data 

set. 

(9) On and after [THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], if required to submit the 

results of a performance test or CEMS 

performance evaluation, the owner or 

operator shall submit the results using 

EPA’s Electronic Reporting Tool (ERT) 

according to the procedures in 

paragraphs (h)(9)(i) and (ii) of this 

section. 

(i) Within 60 days after the date of 

completing each performance test as 

required by this subpart, the owner or 

operator shall submit the results of the 

performance tests according to the 

method specified by either paragraph 

(h)(9)(i)(A) or (h)(9)(i)(B) of this section. 

(A) For data collected using test 

methods supported by the EPA’s ERT as 

listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/

index.html), the owner or operator must 

submit the results of the performance 

test to the CEDRI accessed through the 

EPA’s CDX (http://cdx.epa.gov/epa_

home.asp), unless the Administrator 

approves another approach. 

Performance test data must be submitted 

in a file format generated through the 

use of the EPA’s ERT. If an owner or 

operator claims that some of the 

performance test information being 

submitted is confidential business 

information (CBI), the owner or operator 

must submit a complete file generated 

through the use of the EPA’s ERT, 

including information claimed to be 

CBI, on a compact disc or other 

commonly used electronic storage 

media (including, but not limited to, 

flash drives) by registered letter to the 

EPA. The electronic media must be 

clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, 

Attention: WebFIRE Administrator, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same ERT file with the 

CBI omitted must be submitted to the 

EPA via CDX as described earlier in this 

paragraph. 

(B) For data collected using test 

methods that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT 

Web site, the owner or operator must 

submit the results of the performance 

test to the Administrator at the 

appropriate address listed in § 63.13. 

(ii) Within 60 days after the date of 

completing each CEMS performance 

evaluation as required by this subpart, 

the owner or operator must submit the 

results of the performance evaluation 

according to the method specified by 

either paragraph (h)(9)(ii)(A) or 

(h)(9)(ii)(B) of this section. 

(A) For data collection of relative 

accuracy test audit (RATA) pollutants 

that are supported by the EPA’s ERT as 

listed on the ERT Web site, the owner 

or operator must submit the results of 

the performance evaluation to the 

CEDRI that is accessed through the 

EPA’s CDX, unless the Administrator 

approves another approach. 

Performance evaluation data must be 

submitted in a file format generated 

through the use of the EPA’s ERT. If an 

owner or operator claims that some of 

the performance evaluation information 

being submitted is CBI, the owner or 

operator must submit a complete file 

generated through the use of the EPA’s 

ERT, including information claimed to 

be CBI, on a compact disc or other 

commonly used electronic storage 

media (including, but not limited to, 

flash drives) by registered letter to the 

EPA. The electronic media must be 

clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, 

Attention: WebFIRE Administrator, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same ERT file with the 

CBI omitted must be submitted to the 

EPA via CDX as described earlier in this 

paragraph. 

(B) For any performance evaluation 

data with RATA pollutants that are not 

supported by the EPA’s ERT as listed on 

the EPA’s ERT Web site, the owner or 

operator must submit the results of the 

performance evaluation to the 

Administrator at the appropriate 

address listed in § 63.13. 

(i) Recordkeeping. Each owner or 

operator of a source subject to this 

subpart shall keep copies of all 

applicable reports and records required 

by this subpart for at least 5 years except 

as otherwise specified in paragraphs 

(i)(1) through (11) of this section. All 

applicable records shall be maintained 

in such a manner that they can be 

readily accessed within 24 hours. 

Records may be maintained in hard 

copy or computer-readable form 

including, but not limited to, on paper, 

microfilm, computer, flash drive, floppy 

disk, magnetic tape, or microfiche. 

(1) Each owner or operator subject to 

the storage vessel provisions in § 63.646 

shall keep the records specified in 

§ 63.123 of subpart G of this part except 

as specified in paragraphs (i)(1)(i) 


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through (iv) of this section. Each owner 

or operator subject to the storage vessel 

provisions in § 63.660 shall keep 

records as specified in paragraphs 

(i)(1)(v) and (vi) of this section. 

* * * * * 

(ii) All references to § 63.122 in 

§ 63.123 of subpart G of this part shall 

be replaced with § 63.655(e). 

* * * * * 

(v) Each owner or operator of a Group 

1 storage vessel subject to the provisions 

in § 63.660 shall keep records as 

specified in § 63.1065. 

(vi) Each owner or operator of a Group 

2 storage vessel shall keep the records 

specified in § 63.1065(a) of subpart WW. 

If a storage vessel is determined to be 

Group 2 because the weight percent 

total organic HAP of the stored liquid is 

less than or equal to 4 percent for 

existing sources or 2 percent for new 

sources, a record of any data, 

assumptions, and procedures used to 

make this determination shall be 

retained. 

* * * * * 

(4) For each closed vent system that 

contains bypass lines that could divert 

a vent stream away from the control 

device and to the atmosphere, or cause 

air intrusion into the control device, the 

owner or operator shall keep a record of 

the information specified in either 

paragraph (i)(4)(i) or (ii) of this section, 

as applicable. 

(i) The owner or operator shall 

maintain records of any alarms triggered 

because flow was detected in the bypass 

line, including the date and time the 

alarm was triggered and the duration of 

the flow in the bypass line. The owner 

or operator shall also maintain records 

of all periods when the vent stream is 

diverted from the control device or air 

intrudes into the control device. The 

owner or operator shall include an 

estimate of the volume of gas, the 

concentration of organic HAP in the gas 

and the resulting emissions of organic 

HAP that bypassed the control device. 

(ii) Where a seal mechanism is used 

to comply with § 63.644(c)(2), hourly 

records of flow are not required. In such 

cases, the owner or operator shall record 

the date that the monthly visual 

inspection of the seals or closure 

mechanisms is completed. The owner or 

operator shall also record the 

occurrence of all periods when the seal 

or closure mechanism is broken, the 

bypass line valve position has changed 

or the key for a lock-and-key type lock 

has been checked out. The owner or 

operator shall include an estimate of the 

volume of gas, the concentration of 

organic HAP in the gas and the resulting 

emissions of organic HAP that bypassed 

the control device. 

(5) The owner or operator of a heat 

exchange system subject to this subpart 

shall comply with the recordkeeping 

requirements in paragraphs (i)(5)(i) 

through (v) of this section and retain 

these records for 5 years. 

* * * * * 

(7) Each owner or operator subject to 

the delayed coking unit decoking 

operations provisions in § 63.657 must 

maintain records of the average pressure 

for the 5-minute period prior to venting 

to the atmosphere, draining, or 

deheading the coke drum for each 

cooling cycle for each coke drum. 

(8) For fenceline monitoring systems 

subject to § 63.658, each owner or 

operator shall keep the records specified 

in paragraphs (i)(8)(i) through (ix) of this 

section on an ongoing basis. 

(i) Coordinates of all passive 

monitors, including replicate samplers 

and field blanks, and the meteorological 

station. The owner or operator shall 

determine the coordinates using an 

instrument with an accuracy of at least 

3 meters. The coordinates shall be in 

decimal degrees with at least five 

decimal places. 

(ii) The start and stop times and dates 

for each sample, as well as the tube 

identifying information. 

(iii) Daily unit vector wind direction, 

calculated daily sigma theta, daily 

average temperature and daily average 

barometric pressure measurements. 

(iv) For each outlier determined in 

accordance with Section 9.2 of Method 

325A of Appendix A of this part, the 

sampler location of and the 

concentration of the outlier and the 

evidence used to conclude that the 

result is an outlier. 

(v) For samples that will be adjusted 

for a background, the location of and the 

concentration measured simultaneously 

by the background sampler, and the 

perimeter samplers to which it applies. 

(vi) Individual sample results, the 

calculated Dc for benzene for each 

sampling episode and the two samples 

used to determine it, whether 

background correction was used, and 

the 12-month rolling average Dc 

calculated after each sampling episode. 

(vii) Method detection limit for each 

sample, including co-located samples 

and blanks. 

(viii) Documentation of corrective 

action taken each time the action level 

was exceeded. 

(ix) Other records as required by 

Methods 325A and 325B of Appendix A 

of this part. 

(9) For each flare subject to § 63.670, 

each owner or operator shall keep the 

records specified in paragraphs (i)(9)(i) 

through (vii) of this section up-to-date 

and readily accessible, as applicable. 

(i) Retain records of the output of the 

monitoring device used to detect the 

presence of a pilot flame as required in 

§ 63.670(b) for a minimum of 2 years. 

Retain records of periods during which 

the pilot flame is not present when 

regulated material is routed to a flare for 

a minimum of 5 years. 

(ii) Daily visible emissions 

observations, as required in § 63.670(c), 

as well as any observations required in 

§ 63.670(h). The record must identify 

whether the visible emissions 

observation was performed, the results 

of each observation, total duration of 

observed visible emissions, and whether 

it was a 5-minute or 2-hour observation. 

If the owner or operator performs visible 

emissions observations more than one 

time during a day, the record must also 

identify the date and time of day each 

visible emissions observation was 

performed. 

(iii) The 15-minute block average 

cumulative flows for flare vent gas and, 

if applicable, total steam, perimeter 

assist air, and premix assist air specified 

to be monitored under § 63.670(i), along 

with the date and time interval for the 

15-minute block. If multiple monitoring 

locations are used to determine 

cumulative vent gas flow, total steam, 

perimeter assist air, and premix assist 

air, retain records of the 15-minute 

block average flows for each monitoring 

location for a minimum of 2 years, and 

retain the 15-minute block average 

cumulative flows that are used in 

subsequent calculations for a minimum 

of 5 years. If pressure and temperature 

monitoring is used, retain records of the 

15-minute block average temperature, 

pressure and molecular weight of the 

flare vent gas or assist gas stream for 

each measurement location used to 

determine the 15-minute block average 

cumulative flows for a minimum of 2 

years, and retain the 15-minute block 

average cumulative flows that are used 

in subsequent calculations for a 

minimum of 5 years. 

(iv) The flare vent gas compositions 

specified to be monitored under 

§ 63.670(j). Retain records of individual 

component concentrations from each 

compositional analyses for a minimum 

of 2 years. If NHVvg or total hydrocarbon 

analyzer is used, retain records of the 

15-minute block average values for a 

minimum of 5 years. 

(v) Each 15-minute block average 

operating parameter calculated 

following the methods specified in 

§ 63.670(k) through (m), as applicable. 

(vi) The 15-minute block average 

olefins, hydrogen, and olefins plus 


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hydrogen concentration in the 

combustion zone used to determine if 

the criteria in § 63.670(e)(4) are met. If 

process knowledge and engineering 

calculations are used, retain records of 

the information used in the assessment 

and records of all compositional 

analyses required in § 63.670(o)(ii). 

Identify all 15-minute block averages for 

which all three criteria in § 63.670(e)(4) 

are met or are assumed to be met. 

(vii) All periods during which 

operating values are outside of the 

applicable operating limits specified in 

§ 63.670(d) through (f) when regulated 

material is being routed to the flare. 

(viii) All periods during which the 

owner or operator does not perform flare 

monitoring according to the procedures 

in § 63.670(g) through (j). 

(ix) Records of periods when there is 

flow of vent gas to the flare, but when 

there is no flow of regulated material to 

the flare, including the start and stop 

time and dates of periods of no 

regulated material flow. 

(x) All periods during which a 

halogenated vent stream, as defined in 

§ 63.641, is discharged to the flare. 

Records shall include the start time and 

date of the event, the end time and date 

of the event, and an estimate of the 

cumulative flow of the halogenated vent 

stream over the duration of the event. 

(10) If the owner or operator elects to 

comply with § 63.661, the owner or 

operator shall keep the records 

described in paragraphs (i)(10)(i) 

through (v) of this section. 

(i) The equipment and process units 

for which the owner or operator chooses 

to use the optical gas imaging 

instrument. 

(ii) All records required by part 60, 

Appendix K of this chapter, as 

applicable. 

(iii) A video record to document the 

leak survey results. The video record 

must include a time and date stamp for 

each monitoring event. 

(iv) Identification of the equipment 

screened and the time and date of the 

screening. 

(v) Documentation of repairs 

attempted and repairs delayed. If repair 

of a leak is confirmed using the optical 

gas imaging instrument, then instead of 

the maximum instrument reading 

measured by Method 21 of part 60, 

Appendix A–7 of this chapter, the 

owner or operator shall keep a video 

record following repair to confirm the 

equipment is repaired. 

(11) Other records must be kept as 

specified in paragraphs (i)(11)(i) through 

(iii) of this section. 

(i) In the event that an affected unit 

fails to meet an applicable standard, 

record the number of failures. For each 

failure, record the date, time and 

duration of each failure. 

(ii) For each failure to meet an 

applicable standard, record and retain a 

list of the affected sources or equipment, 

an estimate of the volume of each 

regulated pollutant emitted over any 

emission limit and a description of the 

method used to estimate the emissions. 

(iii) Record actions taken to minimize 

emissions in accordance with 

§ 63.642(n), and any corrective actions 

taken to return the affected unit to its 

normal or usual manner of operation. 

■ 27. Section 63.656 is amended by: 

■ a. Revising paragraph (c) introductory 

text; 

■ b. Revising paragraph (c)(1); and 

■ c. Adding paragraph (c)(5). 

The revisions and additions read as 

follows: 

§ 63.656 Implementation and enforcement. 

* * * * * 

(c) The authorities that cannot be 

delegated to state, local, or Tribal 

agencies are as specified in paragraphs 

(c)(1) through (5) of this section. 

(1) Approval of alternatives to the 

requirements in §§ 63.640, 63.642(g) 

through (l), 63.643, 63.646 through 

63.652, 63.654, 63.657 through 63.661, 

and 63.670. Where these standards 

reference another subpart, the cited 

provisions will be delegated according 

to the delegation provisions of the 

referenced subpart. Where these 

standards reference another subpart and 

modify the requirements, the 

requirements shall be modified as 

described in this subpart. Delegation of 

the modified requirements will also 

occur according to the delegation 

provisions of the referenced subpart. 

* * * * * 

(5) Approval of the corrective action 

plan under § 63.658(h). 

■ 28. Section 63.657 is added to read as 

follows: 

§ 63.657 Delayed coking unit decoking 

operation standards. 

(a) Each owner or operator of a 

delayed coking unit shall depressure 

each coke drum to a closed blowdown 

system until the coke drum vessel 

pressure is 2 pounds per square inch 

gauge (psig) or less prior to venting to 

the atmosphere, draining or deheading 

the coke drum at the end of the cooling 

cycle. 

(b) Each owner or operator of a 

delayed coking unit shall install, 

operate, calibrate, and maintain a 

continuous parameter monitoring 

system to determine the coke drum 

vessel pressure. The pressure 

monitoring system must be capable of 

measuring a pressure of 2 psig within 

±0.5 psig. 

(c) The owner or operator of a delayed 

coking unit shall determine the coke 

drum vessel pressure on a 5-minute 

rolling average basis while the coke 

drum is vented to the closed blowdown 

system to demonstrate compliance the 

requirement in paragraph (a) of this 

section. Pressure readings after 

initiating steps to isolate the coke drum 

from the closed blowdown system just 

prior to atmospheric venting, draining, 

or deheading the coke drum shall not be 

used in determining the average coke 

drum vessel pressure for the purpose of 

compliance with the requirement in 

paragraph (a) of this section. 

■ 29. Section 63.658 is added to read as 

follows: 

§ 63.658 Fenceline monitoring provisions. 

(a) The owner or operator shall 

conduct sampling along the facility 

property boundary and analyze the 

samples in accordance with Methods 

325A and 325B of Appendix A of this 

part. 

(b) The target analyte is benzene. 

(c) The owner or operator shall 

determine passive monitor locations in 

accordance with Section 8.2 of Method 

325A of Appendix A of this part. 

General guidance for siting passive 

monitors can be found in EPA–454/R– 

98–004, Quality Assurance Handbook 

for Air Pollution Measurement Systems, 

Volume II: Part 1: Ambient Air Quality 

Monitoring Program Quality System 

Development, August 1998 

(incorporated by reference—see § 63.14). 

Alternatively, the owner or operator 

may elect to place monitors at 2 

kilometers intervals as measured along 

the property boundary, provided 

additional monitors are located, if 

necessary, as required in Section 8.2.2.5 

in Method 325A of Appendix A of this 

part. 

(1) As it pertains to this subpart, 

known emission source, as used in 

Section 8.2.2.5 in Method 325A of 

Appendix A of this part for siting 

passive monitors means a wastewater 

treatment unit or a Group 1 storage 

vessel. 

(2) The owner or operator may collect 

one or more background samples if the 

owner or operator believes that an 

offsite upwind source or an onsite 

source excluded under § 63.640(g) may 

influence the sampler measurements. If 

the owner or operator elects to collect 

one or more background samples, the 

owner of operator must develop and 

submit a site-specific monitoring plan 

for approval according to the 

requirements in paragraph (i) of this 

section. Upon approval of the sitespecific monitoring plant, the 

background sampler(s) should be 


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operated co-currently with the routine 

samplers. 

(3) The owner or operator shall collect 

at least one co-located duplicate sample 

for every 10 field samples per sampling 

episode and at least two field blanks per 

sampling episode, as described in 

Section 9.3 in Method 325A of 

Appendix A of this part. The co-located 

duplicates may be collected at any one 

of the perimeter sampling locations. 

(4) The owner or operator shall follow 

the procedure in Section 9.6 of Method 

325B of Appendix A of this part to 

determine the detection limit of benzene 

for each sampler used to collect 

samples, background samples (if the 

owner or operator elects to do so), colocated samples and blanks. 

(d) The owner or operator shall use a 

dedicated meteorological station in 

accordance with Section 8.3 of Method 

325A of Appendix A of this part. 

(1) The owner or operator shall collect 

and record hourly average 

meteorological data, including wind 

speed, wind direction and temperature. 

(2) The owner or operator shall follow 

the calibration and standardization 

procedures for meteorological 

measurements in EPA–454/B–08–002, 

Quality Assurance Handbook for Air 

Pollution Measurement Systems, 

Volume IV: Meteorological 

Measurements, Version 2.0 (Final), 

March 2008 (incorporated by 

reference—see § 63.14). 

(e) The length of the sampling episode 

must be fourteen days, unless a shorter 

sampling episode is determined to be 

necessary under paragraph (g) or (i) of 

this section. A sampling episode is 

defined as the period during which the 

owner or operator collects the sample 

and does not include the time required 

to analyze the sample. 

(f) Within 30 days of completion of 

each sampling episode, the owner or 

operator shall determine whether the 

results are above or below the action 

level as follows: 

(1) For each sampling episode, the 

owner or operator shall determine the 

highest and lowest sample results for 

benzene from the sample pool and 

calculate the difference in concentration 

(Dc). 

(i) The owner or operator shall adhere 

to the following procedures when one or 

more samples for the sampling episode 

are below the method detection limit for 

benzene: 

(A) If the lowest detected value of 

benzene is below detection, the owner 

or operator shall use zero as the lowest 

sample result when calculating Dc. 

(B) If all sample results are below the 

method detection limit, the owner or 

operator shall use the method detection 

limit as the highest sample result. 

(ii) If the owner or operator identifies 

an offsite upwind source or an onsite 

source excluded under § 63.640(g) that 

contributes to the benzene 

concentration at any passive monitor 

and collects background samples 

according to an approved site-specific 

monitoring plan, the owner or operator 

shall determine Dc using the calculation 

protocols outlined in the approved sitespecific monitoring plan and in 

paragraph (i) of this section. 

(2) The owner or operator shall 

average the Dc values collected over the 

twelve months prior to and including 

the most recent sampling episode. The 

owner or operator shall update this 

value after receiving the results of each 

sampling episode. 

(3) The action level for benzene is 9 

micrograms per cubic meter (mg/m3). If 

the 12-month rolling average Dc value 

for benzene is less than 9 mg/m3, the 

concentration is below the action level. 

If the 12-month rolling average Dc value 

for benzene is equal to or greater than 

9 mg/m3, the concentration is above the 

action level, and the owner or operator 

shall conduct a root cause analysis and 

corrective action in accordance with 

paragraph (g) of this section. 

(g) Within 5 days of determining that 

the action level has been exceeded for 

any 12-month rolling average and no 

longer than 35 days after completion of 

the sampling episode, the owner or 

operator shall initiate a root cause 

analysis to determine the cause of such 

exceedance and to determine 

appropriate corrective action, as 

described in paragraphs (g)(1) through 

(4) of this section. The root cause 

analysis and corrective action analysis 

shall be completed no later than 45 days 

after determining there is an 

exceedance. Root cause analysis and 

corrective action may include, but is not 

limited to: 

(1) Leak inspection using Method 21 

of part 60, Appendix A–7 of this chapter 

and repairing any leaks found. 

(2) Leak inspection using optical gas 

imaging as specified in § 63.661 and 

repairing any leaks found. 

(3) Visual inspection to determine the 

cause of the high benzene emissions and 

implementing repairs to reduce the level 

of emissions. 

(4) Employing progressively more 

frequent sampling, analysis and 

meteorology (e.g., using shorter 

sampling episodes for Methods 325A 

and 325B of Appendix A of this part, or 

using active sampling techniques), or 

employing additional monitors to 

determine contributing offsite sources. 

(h) If, upon completion of the 

corrective actions described in 

paragraph (g) of this section, the action 

level is exceeded for the next sampling 

episode following the completion of the 

corrective action, the owner or operator 

shall develop a corrective action plan 

that describes the corrective action(s) 

completed to date, additional measures 

that the owner or operator proposes to 

employ to reduce fenceline 

concentrations below the action level, 

and a schedule for completion of these 

measures. The owner or operator shall 

submit the corrective action plan to the 

Administrator within 60 days after 

determining the action level was 

exceeded during the sampling episode 

following the completion of the initial 

corrective action. The Administrator 

shall approve or disapprove the plan in 

90 days. The plan shall be considered 

approved if the Administrator either 

approves the plan in writing, or fails to 

disapprove the plan in writing. The 90- 

day period shall begin when the 

Administrator receives the plan. 

(i) An owner or operator may request 

approval from the Administrator for a 

site-specific monitoring plan to account 

for offsite upwind sources or onsite 

sources excluded under § 63.640(g) 

according to the requirements in 

paragraphs (i)(1) through (4) of this 

section. 

(1) The owner or operator shall 

prepare and submit a site-specific 

monitoring plan and receive approval of 

the site-specific monitoring plan prior to 

using the near-field source alternative 

calculation for determining Dc provided 

in paragraph (i)(2) of this section. The 

site-specific monitoring plan shall 

include, at a minimum, the elements 

specified in paragraphs (i)(1)(i) through 

(v) of this section. 

(i) Identification of the near-field 

source or sources. For onsite sources, 

documentation that the onsite source is 

excluded under § 63.640(g) and 

identification of the specific provision 

in § 63.640(g) that applies to the source. 

(ii) Location of the additional 

monitoring stations that shall be used to 

determine the uniform background 

concentration and the near-field source 

concentration contribution. 

(iii) Identification of the fenceline 

monitoring locations impacted by the 

near-field source. If more than one nearfield source is present, identify for each 

monitoring location, the near field 

source or sources that are expected to 

contribute to fenceline concentration at 

that monitoring location. 

(iv) A description of (including 

sample calculations illustrating) the 

planned data reduction and calculations 

to determine the near-field source 


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concentration contribution for each 

monitoring location. 

(v) If more frequent monitoring is 

proposed or if a monitoring station other 

than a passive diffusive tub monitoring 

station is proposed, provide a detailed 

description of the measurement 

methods, measurement frequency, and 

recording frequency proposed for 

determining the uniform background or 

near-field source concentration 

contribution. 

(2) When an approved site-specific 

monitoring plan is used, the owner or 

operator shall determine Dc for 

comparison with the 9 mg/m3 action 

level using the requirements specified 

in paragraphs (2)(i) through (iii) of this 

section. 

(i) For each monitoring location, 

calculate Dci using the following 

equation. 

Dci = MCFi ¥ NFSi ¥ UB 

Where: 

Dci = The fenceline concentration, corrected 

for background, at measurement location 

i, micrograms per cubic meter (mg/m3). 

MFCi = The measured fenceline 

concentration at measurement location i, 

mg/m3. 

NFSi = The near-field source contributing 

concentration at measurement location i 

determined using the additional 

measurements and calculation 

procedures included in the site-specific 

monitoring plan, mg/m3. For monitoring 

locations that are not included in the 

site-specific monitoring plan as impacted 

by a near-field source, use NFSi = 0 mg/ 

m3. 

UB = The uniform background concentration 

determined using the additional 

measurements specified included in the 

site-specific monitoring plan, mg/m3. If 

no additional measurement location is 

specified in the site-specific monitoring 

plan for determining the uniform 

background concentration, use UB = 0 

mg/m3. 

(ii) When one or more samples for the 

sampling episode are below the method 

detection limit for benzene, adhere to 

the following procedures: 

(A) If the benzene concentration at the 

monitoring location used for the 

uniform background concentration is 

below detection, the owner or operator 

shall use zero for UB for that monitoring 

period. 

(B) If the benzene concentration at the 

monitoring location(s) used to 

determine the near-field source 

contributing concentration is below 

detection, the owner or operator shall 

use zero for the monitoring location 

concentration when calculating NFSi for 

that monitoring period. 

(C) If a fenceline monitoring location 

sample result is below the method 

detection limit, the owner or operator 

shall use the method detection limit as 

the sample result. 

(iii) Determine Dc for the monitoring 

period as the maximum value of Dci

from all of the fenceline monitoring 

locations for that monitoring period. 

(3) The site-specific monitoring plan 

shall be submitted and approved as 

described in paragraphs (i)(3)(i) through 

(iv) of this section. 

(i) The site-specific monitoring plan 

must be submitted to the Administrator 

for approval. 

(ii) The site-specific monitoring plan 

shall also be submitted to the following 

address: U.S. Environmental Protection 

Agency, Office of Air Quality Planning 

and Standards, Sector Policies and 

Programs Division, U.S. EPA Mailroom 

(E143–01), Attention: Refinery Sector 

Lead, 109 T.W. Alexander Drive, 

Research Triangle Park, NC 27711. 

Electronic copies in lieu of hard copies 

may also be submitted to refineryrtr@

epa.gov. 

(iii) The Administrator shall approve 

or disapprove the plan in 90 days. The 

plan shall be considered approved if the 

Administrator either approves the plan 

in writing, or fails to disapprove the 

plan in writing. The 90-day period shall 

begin when the Administrator receives 

the plan. 

(iv) If the Administrator finds any 

deficiencies in the site-specific 

monitoring plan and disapproves the 

plan in writing, the owner or operator 

may revise and resubmit the sitespecific monitoring plan following the 

requirements in paragraphs (i)(3)(i) and 

(ii) of this section. The 90-day period 

starts over with the resubmission of the 

revised monitoring plan. 

(4) The approval by the Administrator 

of a site-specific monitoring plan will be 

based on the completeness, accuracy 

and reasonableness of the request 

process for a site-specific monitoring 

plan. Factors that the EPA will consider 

in reviewing the request for a sitespecific monitoring plan include, but 

are not limited to, those described in 

paragraphs (i)(4)(i) through (v) of this 

section. 

(i) The identification of the near-field 

source or sources. For onsite sources, 

the documentation provided that the 

onsite source is excluded under 

§ 63.640(g). 

(ii) The monitoring location selected 

to determine the uniform background 

concentration or an indication that no 

uniform background concentration 

monitor will be used. 

(iii) The location(s) selected for 

additional monitoring to determine the 

near-field source concentration 

contribution. 

(iv) The identification of the fenceline 

monitoring locations impacted by the 

near-field source or sources. 

(v) The appropriateness of the 

planned data reduction and calculations 

to determine the near-field source 

concentration contribution for each 

monitoring location. 

(vi) If more frequent monitoring is 

proposed or if a monitoring station other 

than a passive diffusive tub monitoring 

station is proposed, the adequacy of the 

description of the measurement 

methods, measurement frequency, and 

recording frequency proposed and the 

adequacy of the rationale for using the 

alternative monitoring frequency or 

method. 

(j) The owner or operator shall 

comply with the applicable 

recordkeeping and reporting 

requirements in § 63.655(h) and (i). 

■ 30. Section 63.660 is added to read as 

follows: 

§ 63.660 Storage vessel provisions. 

On and after the applicable 

compliance date for a Group 1 storage 

vessel located at a new or existing 

source as specified in § 63.640(h), the 

owner or operator of a Group 1 storage 

vessel that is part of a new or existing 

source shall comply with the 

requirements in subpart WW or subpart 

SS of this part according to the 

requirements in paragraphs (a) through 

(i) of this section. 

(a) As used in this section, all terms 

not defined in § 63.641 shall have the 

meaning given them in subpart A, 

subpart WW, or subpart SS of this part. 

The definitions of ‘‘Group 1 storage 

vessel’’ (item 2) and ‘‘storage vessel’’ in 

§ 63.641 shall apply in lieu of the 

definition of ‘‘storage vessel’’ in 

§ 63.1061. 

(1) An owner or operator may use 

good engineering judgment or test 

results to determine the stored liquid 

weight percent total organic HAP for 

purposes of group determination. Data, 

assumptions, and procedures used in 

the determination shall be documented. 

(2) When an owner or operator and 

the Administrator do not agree on 

whether the annual average weight 

percent organic HAP in the stored liquid 

is above or below 4 percent for a storage 

vessel at an existing source or above or 

below 2 percent for a storage vessel at 

a new source, an appropriate method 

(based on the type of liquid stored) as 

published by EPA or a consensus-based 

standards organization shall be used. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 


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Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street NW., 6th Floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http://

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http://

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.naesb.org). 

(b) In addition to the options 

presented in §§ 63.1063(a)(2)(vii)(A), 

63.1063(a)(2)(vii)(B), and 63.1064, an 

external floating roof storage vessel may 

comply with § 63.1063(a)(2)(vii) using a 

flexible enclosure system as described 

in item 6 of Appendix I: Acceptable 

Controls for Slotted Guidepoles Under 

the Storage Tank Emissions Reduction 

Partnership Program (available at http:// 

www.epa.gov/ttn/atw/petrefine/

petrefpg.html). 

(c) For the purposes of this subpart, 

references shall apply as specified in 

paragraphs (c)(1) through (6) of this 

section. 

(1) All references to ‘‘the proposal 

date for a referencing subpart’’ and ‘‘the 

proposal date of the referencing 

subpart’’ in subpart WW of this part 

mean June 30, 2014. 

(2) All references to ‘‘promulgation of 

the referencing subpart’’ and ‘‘the 

promulgation date of the referencing 

subpart’’ in subpart WW of this part 

mean [THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER]. 

(3) All references to ‘‘promulgation 

date of standards for an affected source 

or affected facility under a referencing 

subpart’’ in subpart SS of this part mean 

[THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER]. 

(4) All references to ‘‘the proposal 

date of the relevant standard established 

pursuant to CAA section 112(f)’’ in 

subpart SS of this part mean June 30, 

2014. 

(5) All references to ‘‘the proposal 

date of a relevant standard established 

pursuant to CAA section 112(d)’’ in 

subpart SS of this part mean July 14, 

1994. 

(6) All references to the ‘‘required 

control efficiency’’ in subpart SS of this 

part mean reduction of organic HAP 

emissions by 95 percent or to an outlet 

concentration of 20 ppmv. 

(d) For an existing storage vessel fixed 

roof that meets the definition of Group 

1 storage vessel (item 2) in § 63.641 but 

not the definition of Group 1 storage 

vessel (item 1) in § 63.641, the 

requirements of § 63.1062 do not apply 

until the next time the storage vessel is 

completely emptied and degassed, or 

[THE DATE 10 YEARS AFTER 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], whichever occurs first. 

(e) Failure to perform inspections and 

monitoring required by this section 

shall constitute a violation of the 

applicable standard of this subpart. 

(f) References in § 63.1066(a) to initial 

startup notification requirements do not 

apply. 

(g) References to the Notification of 

Compliance Status in § 63.999(b) mean 

the Notification of Compliance Status 

required by § 63.655(f). 

(h) References to the Periodic Reports 

in §§ 63.1066(b) and 63.999(c) mean the 

Periodic Report required by § 63.655(g). 

(i) Owners or operators electing to 

comply with the requirements in 

subpart SS of this part for a Group 1 

storage vessel must comply with the 

requirements in paragraphs (c)(1) 

through (3) of this section. 

(1) If a flare is used as a control 

device, the flare shall meet the 

requirements of § 63.670 instead of the 

flare requirements in § 63.987. 

(2) If a closed vent system contains a 

bypass line, the owner or operator shall 

comply with the provisions of either 

§ 63.985(a)(3)(i) or (ii) for each closed 

vent system that contains bypass lines 

that could divert a vent stream to the 

atmosphere. Use of the bypass at any 

time to divert a Group 1 storage vessel 

to the atmosphere is an emissions 

standards violation. Equipment such as 

low leg drains and equipment subject to 

§ 63.648 are not subject to this 

paragraph. 

(3) If storage vessel emissions are 

routed to a fuel gas system or process, 

the fuel gas system or process shall be 

operating at all times when regulated 

emissions are routed to it. The 

exception in paragraph § 63.984(a)(1) 

does not apply. 

■ 31. Section 63.661 is added to read as 

follows: 

§ 63.661 Alternative means of emission 

limitation: Monitoring equipment leaks 

using optical gas imaging. 

(a) Applicability. The owner or 

operator may only use an optical gas 

imaging instrument to screen for leaking 

equipment, as required by § 63.648, if 

the requirements in paragraphs (a)(1) 

through (3) of this section are met. 

(1) The owner or operator may only 

use the optical gas imaging instrument 

as an alternative to provisions in 

§ 63.648 that would otherwise require 

monitoring according to § 60.485(b) or 

§ 63.180(b)(1) through (5), as applicable. 

The owner or operator shall continue to 

comply with all other requirements in 

§ 63.648 (e.g., weekly inspections of 

pumps; for relief valves, installation of 

a device that is capable of identifying 

and recording the time and duration of 

each pressure release, if applicable; 

sampling connection system 

requirements). 

(2) The owner or operator must be in 

compliance with the fenceline 

monitoring provisions of § 63.658. 

(3) The optical gas imaging 

instrument must be able to meet all of 

the criteria and requirements specified 

in part 60, Appendix K of this chapter, 

and the owner or operator shall conduct 

monitoring according to part 60, 

Appendix K of this chapter. 

(b) Compliance requirements. The 

owner or operator shall meet the 

requirements of paragraphs (b)(1) 

through (3) of this section. 

(1) The owner or operator shall 

identify the equipment and process 

units for which the optical gas imaging 

instrument will be used to identify 

leaks. 

(2) The owner or operator shall repair 

leaking equipment as required in the 

applicable section of part 60, subpart 

VV of this chapter or subpart H of this 

part. 

(3) Monitoring to confirm repair of 

leaking equipment must be conducted 

using the procedures referenced in 

paragraph (a)(2) of this section. 

(c) Recordkeeping. The owner or 

operator shall comply with the 

applicable requirements in § 63.655(i). 

■ 32. Section 63.670 is added to read as 

follows: 

§ 63.670 Requirements for flare control 

devices. 

On or before [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], the 

owner or operator of a flare used as a 

control device for an emission point 

subject to this subpart shall meet the 

applicable requirements for flares as 

specified in paragraphs (a) through (q) 

of this section and the applicable 

requirements in § 63.671. The owner or 

operator may elect to comply with the 

requirements of paragraph (r) of this 

section in lieu of the requirements in 

paragraphs (d) through (f) of this 

section, as applicable. 

(a) Halogenated vent streams. The 

owner or operator shall not use a flare 


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to control halogenated vent streams as 

defined in § 63.641. 

(b) Pilot flame presence. The owner or 

operator shall operate each flare with a 

pilot flame present at all times when 

regulated material is routed to the flare. 

The pilot system must be equipped with 

an automated device to relight the pilot 

if extinguished. The owner or operator 

shall monitor for the presence of a pilot 

flame as specified in paragraph (g) of 

this section. 

(c) Visible emissions. Each flare must 

be designed for and operated with no 

visible emissions, except for periods not 

to exceed a total of 5 minutes during 

any 2 consecutive hours. The owner or 

operator shall monitor for visible 

emissions from the flare as specified in 

paragraph (b) of this section. 

(d) Flare tip velocity. For each flare, 

the owner or operator shall comply with 

either paragraph (d)(1) or (d)(2) of this 

section, provided the appropriate 

monitoring systems are in-place. If a 

total hydrocarbon analyzer is used for 

compositional analysis as allowed 

under section (j)(4) of this section, then 

the owner or operator must comply with 

paragraph (d)(1) of this section. 

(1) Except as provided in paragraph 

(d)(2) of this section, the actual flare tip 

velocity (Vtip) must be less than 60 feet 

per second when regulated material is 

being routed to the flare. The owner or 

operator shall monitor Vtip using the 

procedures specified in paragraph (i) 

and (k) of this section. 

(2) Vtip must be less than 400 feet per 

second and also less than the maximum 

allowed flare tip velocity (Vmax) as 

calculated according to the following 

equation at all times regulated material 

is being routed to the flare. The owner 

or operator shall monitor Vtip using the 

procedures specified in paragraph (i) 

and (k) of this section and monitor gas 

composition and determine NHVvg

using the procedures specified in 

paragraphs (j) and (l) of this section. 

Where: 

Vmax = Maximum allowed flare tip velocity, 

ft/sec. 

NHVvg = Net heating value of flare vent gas, 

as determined by paragraph (l)(4) of this 

section, Btu/scf. 

1,212 = Constant. 

850 = Constant. 

(e) Target combustion zone gas 

properties. For each flare, the owner or 

operator shall comply with the 

applicable requirements in either 

paragraph (e)(1), (2), or (3) of this 

section. The owner or operator may 

elect to comply with any of these 

applicable requirements at any time 

(e.g., may elect to comply with the 

requirements in paragraph (e)(1) during 

certain flow conditions and comply 

with the requirements in paragraph 

(e)(2) or (e)(3) under different flow 

conditions) provided that the owner or 

operator has the appropriate monitoring 

equipment to determine compliance 

with the specified requirement. 

(1) The net heating value of flare 

combustion zone gas (NHVcz) must be 

greater than or equal to the target values 

in paragraphs (e)(1)(i) or (ii), as 

applicable, when regulated material is 

being routed to the flare. The owner or 

operator shall monitor and calculate 

NHVcz as specified in paragraph (m) of 

this section. 

(i) For flares meeting all three 

requirements in paragraph (e)(4) of this 

section, the target NHVcz value is 380 

British thermal units per standard cubic 

feet (Btu/scf). 

(ii) For all flares other than those 

meeting all three requirements in 

paragraph (e)(4) of this section, the 

target NHVcz value is 270 Btu/scf. 

(2) The lower flammability limit of 

the combustion zone gas (LFLcz) must be 

less than or equal to the target values in 

paragraphs (e)(2)(i) or (ii), as applicable, 

when regulated material is being routed 

to the flare. The owner or operator shall 

monitor and calculate LFLcz as specified 

in paragraph (m) of this section. 

(i) For flares meeting all three 

requirements in paragraph (e)(4) of this 

section, the target LFLcz value is 0.11 

volume fraction. 

(ii) For all flares other than those 

meeting all three requirements in 

paragraph (e)(4) of this section, the 

target LFLcz value is 0.15 volume 

fraction. 

(3) The total volumetric fraction of 

hydrogen and combustible organic 

components present in the combustion 

zone gas (Ccz), as propane, must be 

greater than or equal to the target values 

in paragraphs (e)(3)(i) or (ii), as 

applicable, when regulated material is 

being routed to the flare. The owner or 

operator shall monitor and calculate Ccz

as specified in paragraph (m) of this 

section. 

(i) For flares meeting all three 

requirements in paragraph (e)(4) of this 

section, the target Ccz value is 0.23 

volume fraction as propane. 

(ii) For all flares other than those 

meeting all three requirements in 

paragraph (e)(4) of this section, the 

target Ccz value is 0.18 volume fraction 

as propane. 

(4) More stringent combustion zone 

gas target properties apply only during 

those flare flow periods when all three 

conditions in paragraphs (e)(4)(i) 

through (iii) simultaneously exist. The 

owner or operator shall monitor and 

calculate hydrogen and cumulative 

olefin combustion zone concentrations 

as specified in paragraph (o) of this 

section: 

(i) The concentration of hydrogen in 

the combustion zone is greater than 1.2 

percent by volume. 

(ii) The cumulative concentration of 

olefins in the combustion zone is greater 

than 2.5 percent by volume. 

(iii) The cumulative concentration of 

olefins in the combustion zone plus the 

concentration of hydrogen in the 

combustion zone is greater than 7.4 

percent by volume. 

(f) Target dilution parameters for 

flares with perimeter assist air. For each 

flare actively receiving perimeter assist 

air, the owner or operator shall comply 

with the applicable requirements in 

either paragraph (f)(1), (2), or (3) of this 

section in addition to complying with 

the target combustion zone gas 

properties as specified in paragraph (e) 

of this section. The owner or operator 

may elect to comply with any of these 

applicable requirements at any time 

(e.g., may elect to comply with the 

requirements in paragraph (f)(1) during 

certain flow conditions and comply 

with the requirements in paragraph 

(f)(2) or (f)(3) under different flow 

conditions) provided that the owner or 

operator has the appropriate monitoring 

equipment to determine compliance 

with the specified requirement. 

(1) The net heating value dilution 

parameter (NHVdil) must be greater than 

or equal to the target values in 

paragraphs (f)(1)(i) or (ii), as applicable, 

when regulated material is being routed 

to the flare. The owner or operator shall 

monitor and calculate NHVdil as 

specified in paragraph (n) of this 

section. 

(i) For flares meeting all three 

requirements in paragraph (e)(4) of this 

section, the target NHVdil value is 31 


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British thermal units per square foot 

(Btu/ft2). 

(ii) For all flares other than those 

meeting all three requirements in 

paragraph (e)(4) of this section, the 

target NHVdil value is 22 Btu/ft2. 

(2) The lower flammability limit 

dilution parameter (LFLdil) must be less 

than or equal to the target values in 

paragraphs (f)(2)(i) or (ii), as applicable, 

when regulated material is being routed 

to the flare. The owner or operator shall 

monitor and calculate LFLdil as specified 

in paragraph (n) of this section. 

(i) For flares meeting all three 

requirements in paragraph (e)(4) of this 

section, the target LFLdil value is 1.6 

volume fraction per foot (volume 

fraction/ft). 

(ii) For all flares other than those 

meeting all three requirements in 

paragraph (e)(4) of this section, the 

target LFLdil value is 2.2 volume 

fraction/ft. 

(3) The combustibles concentration 

dilution parameter (Cdil) must be greater 

than or equal to the target values in 

paragraphs (f)(3)(i) or (ii), as applicable, 

when regulated material is being routed 

to the flare. The owner or operator shall 

monitor and calculate Cdil as specified 

in paragraph (n) of this section. 

(i) For flares meeting all three 

requirements in paragraph (e)(4) of this 

section, the target Cdil value is 0.015 

volume fraction-ft. 

(ii) For all flares other than those 

meeting all three requirements in 

paragraph (e)(4) of this section, the 

target Ccz value is 0.012 volume fractionft. 

(g) Pilot flame monitoring. The owner 

or operator shall continuously monitor 

the presence of the pilot flame(s) using 

a device (including, but not limited to, 

a thermocouple, ultraviolet beam 

sensor, or infrared sensor) capable of 

detecting that the pilot flame(s) is 

present. 

(h) Visible emissions monitoring. The 

owner or operator shall monitor visible 

emissions while regulated materials are 

vented to the flare. An initial visible 

emissions demonstration must be 

conducted using an observation period 

of 2 hours using Method 22 at 40 CFR 

part 60, Appendix A–7. Subsequent 

visible emissions observations must be 

conducted at a minimum of once per 

day using an observation period of 5 

minutes using Method 22 at 40 CFR part 

60, Appendix A–7. If at any time the 

owner or operator sees visible 

emissions, even if the minimum 

required daily visible emission 

monitoring has already been performed, 

the owner or operator shall immediately 

begin an observation period of 5 

minutes using Method 22 at 40 CFR part 

60, Appendix A–7. If visible emissions 

are observed for more than one 

continuous minute during any 5-minute 

observation period, the observation 

period using Method 22 at 40 CFR part 

60, Appendix A–7 must be extended to 

2 hours. 

(i) Flare vent gas, steam assist and air 

assist flow rate monitoring. The owner 

or operator shall install, operate, 

calibrate, and maintain a monitoring 

system capable of continuously 

measuring, calculating, and recording 

the volumetric flow rate in the flare 

header or headers that feed the flare. If 

assist air or assist steam is used, the 

owner or operator shall install, operate, 

calibrate, and maintain a monitoring 

system capable of continuously 

measuring, calculating, and recording 

the volumetric flow rate of assist air 

and/or assist steam used with the flare. 

If pre-mix assist air and perimeter assist 

are both used, the owner or operator 

shall install, operate, calibrate, and 

maintain a monitoring system capable of 

separately measuring, calculating, and 

recording the volumetric flow rate of 

premix assist air and perimeter assist air 

used with the flare. 

(1) The flow rate monitoring systems 

must be able to correct for the 

temperature and pressure of the system 

and output parameters in standard 

conditions (i.e., a temperature of 20 °C 

[68 °F] and a pressure of 1 atm). The 

flare vent gas flow rate monitoring 

system(s) must also be able to output 

flow in actual conditions for use in the 

flare tip velocity calculation. 

(2) Mass flow monitors may be used 

for determining volumetric flow rate of 

flare vent gas provided the molecular 

weight of the flare vent gas is 

determined using compositional 

analysis as specified in paragraph (j) of 

this section so that the mass flow rate 

can be converted to volumetric flow at 

standard conditions using the following 

equation. 

Where: 

Qvol = Volumetric flow rate, standard cubic 

feet per second. 

Qmass = Mass flow rate, pounds per second. 

385.3 = Conversion factor, standard cubic 

feet per pound-mole. 

MWt = Molecular weight of the gas at the 

flow monitoring location, pounds per 

pound-mole. 

(3) Mass flow monitors may be used 

for determining volumetric flow rate of 

assist air or assist steam. Use equation 

in paragraph (i)(2) of this section to 

convert mass flow rates to volumetric 

flow rates. Use a molecular weight of 18 

pounds per pound-mole for assist steam 

and use a molecular weight of 29 

pounds per pound-mole for assist air. 

(4) Continuous pressure/temperature 

monitoring system(s) and appropriate 

engineering calculations may be used in 

lieu of a continuous volumetric flow 

monitoring systems provided the 

molecular weight of the gas is known. 

For assist steam, use a molecular weight 

of 18 pounds per pound-mole. For assist 

air, use a molecular weight of 29 pounds 

per pound-mole. For flare vent gas, 

molecular weight must be determined 

using compositional analysis as 

specified in paragraph (j) of this section. 

(j) Flare vent gas composition 

monitoring. The owner or operator shall 

determine the concentration of 

individual components in the flare vent 

gas using either the methods provided 

in paragraphs (j)(1) or (j)(2) of this 

section, to assess compliance with the 

operating limits in paragraph (e) of this 

section and, if applicable, paragraphs 

(d) and (f) of this section. Alternatively, 

the owner or operator may elect to 

directly monitor the net heating value of 

the flare vent gas following the methods 

provided in paragraphs (j)(3) of this 

section or the combustibles 

concentration following the methods 

provided in paragraphs (j)(4) of this 

section.. The owner or operator electing 

to directly monitor the net heating value 

of the flare vent gas must comply with 

the net heating value operating limits in 

paragraph (e) and, if applicable, 

paragraph (f) of this section. The owner 

or operator electing to directly monitor 

the combustibles concentration in the 

flare vent gas must comply with the 

combustibles concentration operating 

limits in paragraph (e) and, if 

applicable, paragraph (f) of this section, 

and must comply with the maximum 

velocity requirements in paragraph 

(d)(1) of this section. 

(1) Except as provided in paragraph 

(j)(5) of this section, the owner or 

operator shall install, operate, calibrate, 

and maintain a monitoring system 

capable of continuously measuring (i.e., 

at least once every 15 minutes), 

calculating, and recording the 

individual component concentrations 

present in the flare vent gas. 

(2) Except as provided in paragraph 

(j)(5) of this section, the owner or 

operator shall install, operate, and 

maintain a grab sampling system 

capable of collecting an evacuated 

canister sample for subsequent 

compositional analysis at least once 

every eight hours while there is flow of 

regulated material to the flare. 

Subsequent compositional analysis of 

the samples must be performed 

according to Method 18 of 40 CFR part 


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Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36983 

60, Appendix A–6, ASTM D1945–03 

(Reapproved 2010) (incorporated by 

reference—see § 63.14), or ASTM 

UOP539–12 (incorporated by 

reference—see § 63.14). 

(3) The owner or operator shall 

install, operate, calibrate, and maintain 

a monitoring system capable of 

continuously measuring, calculating, 

and recording NHVvg. at standard 

conditions. 

(4) The owner or operator shall 

install, operate, calibrate, and maintain 

a monitoring system capable of 

continuously measuring, calculating, 

and recording total hydrocarbon content 

(as propane) as a surrogate for 

combustibles concentration. 

(5) Direct compositional monitoring is 

not required for pipeline quality natural 

gas streams. In lieu of monitoring the 

composition of a pipeline quality 

natural gas stream, the following 

composition can be used for any 

pipeline quality natural gas stream. 

(i) 93.2 volume percent (vol %) 

methane. 

(ii) 3.2 vol % ethane. 

(iii) 0.6 vol % propane. 

(iv) 0.3 vol % butane. 

(v) 2.0 vol % hydrogen. 

(vi) 0.7 vol % nitrogen. 

(k) Calculation methods for 

determining compliance with Vtip

operating limits. The owner or operator 

shall determine Vtip on a 15-minute 

block average basis according to the 

following requirements. 

(1) The owner or operator shall use 

design and engineering principles to 

determine the unobstructed cross 

sectional area of the flare tip. The 

unobstructed cross sectional area of the 

flare tip is the total tip area that vent gas 

can pass through. This area does not 

include any stability tabs, stability rings, 

and upper steam or air tubes because 

vent gas does not exit through them. 

(2) The owner or operator shall 

determine the cumulative volumetric 

flow of vent gas for each 15-minute 

block average period using the data from 

the continuous flow monitoring system 

required in paragraph (i) of this section 

according to the following requirements, 

as applicable. 

(i) Use set 15-minute time periods 

starting at 12 midnight to 12:15 a.m., 

12:15 a.m. to 12:30 a.m. and so on 

concluding at 11:45 p.m. to midnight 

when calculating 15-minute block 

average flow volumes. 

(ii) If continuous pressure/

temperature monitoring system(s) and 

engineering calculations are used as 

allowed under paragraph (i)(4) of this 

section, the owner of operator shall, at 

a minimum, determine the 15-minute 

block average temperature and pressure 

from the monitoring system and use 

those values to perform the engineering 

calculations to determine the 

cumulative flow over the 15-minute 

block average period. Alternatively, the 

owner or operator may divide the 15- 

minute block average period into equal 

duration subperiods (e.g., three 5- 

minute periods) and determine the 

average temperature and pressure for 

each subperiod, perform engineering 

calculations to determine the flow for 

each subperiod, then add the volumetric 

flows for the subperiods to determine 

the cumulative volumetric flow of vent 

gas for the 15-minute block average 

period. 

(3) The 15-minute block average Vtip

shall be calculated using the following 

equation. 

Where: 

Vtip = Flare tip velocity, feet per second. 

Qcum = Cumulative volumetric flow over 15- 

minute block average period, actual 

cubic feet. 

Area = Unobstructed area of the flare tip, 

square feet. 

900 = Conversion factor, seconds per 15- 

minute block average. 

(4) If the owner or operator chooses to 

comply with paragraph (d)(2) of this 

section, the owner or operator shall also 

determine the net heating value of the 

flare vent gas following the 

requirements in paragraph (j) and (l) of 

this section and calculate Vmax using the 

equation in paragraph (d)(2) of this 

section in order to compare Vtip to Vmax

on a 15-minute block average basis. 

(l) Calculation methods for 

determining flare vent gas parameters. 

The owner or operator shall determine 

the net heating value, lower 

flammability limit, and/or combustibles 

concentration vent gas of the flare 

(NHVvg, LFLvg, and/or Cvg, respectively) 

based on the composition monitoring 

data on a 15-minute block average basis 

according to the following requirements. 

(1) Use set 15-minute time periods 

starting at 12 midnight to 12:15 a.m., 

12:15 a.m. to 12:30 a.m. and so on 

concluding at 11:45 p.m. to midnight 

when calculating 15-minute block 

averages. 

(2) When a continuous monitoring 

system is used to determine flare vent 

gas composition, net heating value, or 

total hydrocarbon content: 

(i) Use the results from the first 

sample collected during an event, (for 

periodic flare vent gas flow events) for 

the first and second 15-minute block 

associated with that event. 

(ii) For all other 15-minute block 

periods, use the results that are 

available from the most recent sample 

prior to the 15-minute block period for 

that 15-minute block period. For the 

purpose of this requirement, use the 

time that the results become available 

rather than the time the sample was 

collected. For example, if a sample is 

collected at 12:25 a.m. and the analysis 

is completed at 12:38 a.m., the results 

are available at 12:38 a.m. and these 

results would be used to determine 

compliance during the 15-minute block 

period from 12:45 a.m. to 1:00 a.m. 

(3) When grab samples are used to 

determine flare vent gas composition: 

(i) Use the analytical results from the 

first grab sample collected for an event 

for all 15-minute periods from the start 

of the event through the 15-minute 

block prior to the 15-minute block in 

which a subsequent grab sample is 

collected. 

(ii) Use the results from subsequent 

grab sampling events for all 15 minute 

periods starting with the 15-minute 

block in which the sample was collected 

and ending with the 15-minute block 

prior to the 15-minute block in which 

the next grab sample is collected. For 

the purpose of this requirement, use the 

time the sample was collected rather 

than the time the analytical results 

become available. 

(4) The owner or operator shall 

determine NHVvg from compositional 

analysis data by using the following 

equation. If the owner or operator uses 

a monitoring system(s) capable of 

continuously measuring, calculating, 

and recording NHVvg, as provided in 

paragraph (j)(3) of this section, the 

owner or operator shall use the NHVvg

as determined by the continuous NHVvg

monitor. 

Where: 

NHVvg = Net heating value of flare vent gas, 

Btu/scf. 

i = Individual component in flare vent gas. 

n = Number of components in flare vent gas. 

xi = Concentration of component i in flare 

vent gas, volume fraction. 

NHVi = Net heating value of component i 

according to table 12 of this subpart, Btu/ 

scf. If the component is not specified in 

table 12 of this subpart, the heats of 

combustion may be determined using 

any published values where the net 

enthalpy per mole of offgas is based on 

combustion at 25 °C and 1 atmosphere 

(or constant pressure) with offgas water 

in the gaseous state, but the standard 

temperature for determining the volume 

corresponding to one mole of vent gas is 

20 °C. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP30JN14.007</GPH> EP30JN14.008</GPH>
36984 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

(5) The owner or operator shall 

calculate LFLvg using the following 

equation: 

Where: 

LFLvg = Lower flammability limit of flare 

vent gas, volume fraction. 

n = Number of components in the vent gas. 

i = Individual component in the vent gas. 

ci = Concentration of component i in the vent 

gas, volume percent (vol %). 

LFLi = Lower flammability limit of 

component i according to table 12 of this 

subpart, vol %. If the component is not 

specified in table 12 of this subpart, the 

owner or operator shall use the LFL 

value as published in Appendix A of 

Flammability Characteristics of 

Combustible Gases and Vapors, U.S. 

Bureau of Mines, Bulletin 627, 1965 

(incorporated by reference—see § 63.14). 

All inerts, including nitrogen, shall be 

assumed to have an infinite lower 

flammability limit (e.g., LFLN2 = ∞, so 

that cN2/LFLN2 = 0). 

(6) The owner or operator shall 

calculate Cvg using the following 

equation. If the owner or operator uses 

a total hydrocarbon analyzer, the owner 

or operator may substitute the ‘‘èci’’ 

term in the following equation with the 

total volumetric hydrocarbon 

concentration present in the flare vent 

gas (vol % as propane), and the owner 

or operator may choose to ignore the 

concentration of hydrogen in the flare 

vent gas. 

Where: 

Cvg = Total volumetric fraction of hydrogen 

and combustible organic components 

present in the flare vent gas, volume 

fraction. For the purposes of Cvg, carbon 

dioxide is not considered to be a 

combustible organic component, but 

carbon monoxide may be included in 

Cvg. 

n = Number of individual combustible 

organic components in flare vent gas. 

i = Individual combustible organic 

component in flare vent gas. 

ci = Concentration of combustible organic 

component i in flare vent gas, vol %. 

CMNi = Carbon mole number of combustible 

organic component i in flare vent gas, 

mole carbon atoms per mole of 

compound. E.g., CMN for ethane (C2H6) 

is 2; CMN for propane (C3H8) is 3. 

ch = Concentration of hydrogen in flare vent 

gas, vol %. 

100% = Constant, used to convert volume 

percent to volume fraction. 

(m) Calculation methods for 

determining combustion zone 

parameters. The owner or operator shall 

determine the net heating value, lower 

flammability limit and combustibles 

concentration of the combustion zone 

gas (NHVcz, LFLcz, and Ccz, respectively) 

based on the vent gas and assist gas flow 

rates on a 15-minute block average basis 

according to the following requirements. 

For periods when there is no assist 

steam flow or premix assist air flow, the 

combustion zone parameters are equal 

to the vent gas parameters. 

(1) The owner or operator shall 

calculate NHVcz using the following 

equation: 

Where: 

NHVcz = Net heating value of combustion 

zone gas, Btu/scf. 

NHVvg = Net heating value of flare vent gas 

for the 15-minute block period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

(2) The owner or operator shall 

calculate LFLcz using the following 

equation: 

Where: 

LFLcz = Lower flammability limit of 

combustion zone gas, volume fraction. 

LFLvg = Lower flammability limit of flare 

vent gas determined for the 15-minute 

block period, volume fraction. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

(3) The owner or operator shall 

calculate Ccz using the following 

equation: 

Where: 

Ccz = Combustibles concentration in the 

combustion zone gas, volume fraction. 

Cvg = Combustibles concentration of flare 

vent gas determined for the 15-minute 

block period, volume fraction. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

(n) Calculation methods for 

determining dilution parameters. The 

owner or operator shall determine the 

net heating value, lower flammability 

limit and combustibles concentration 

dilution parameters (NHVdil, LFLdil, and 

Cdil, respectively) based on the vent gas 

and perimeter assist air flow rates on a 

15-minute block average basis according 

to the following requirements only 

during periods when perimeter assist air 

is used. For 15-minute block periods 

when there is no cumulative volumetric 

flow of perimeter assist air, the dilution 

parameters do not need to be calculated. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP30JN14.009</GPH> EP30JN14.010</GPH> EP30JN14.011</GPH> EP30JN14.012</GPH> EP30JN14.013</GPH>
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36985 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP30JN14.014</GPH>
36986 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

(o) Special provisions for assessing 

olefins and hydrogen combustion zone 

concentrations. The owner or operator 

shall determine the olefins and 

hydrogen content of the flare vent gas 

and calculate the combustion zone 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP30JN14.015</GPH>
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36987 

concentrations for the purposes of 

assessing the criteria in paragraph (e)(4) 

of this section on a 15-minute block 

average according to the following 

requirements. 

(1) The olefins concentration shall be 

determined as the cumulative sum of 

the following flare gas constituents: 

ethylene, acetylene, propylene, 

propadiene, all isomers of n- or isobutene, and all isomers of butadiene. 

(2) If individual component 

concentrations are determined following 

the methods specified in paragraphs 

(j)(1) or (j)(2) of this section, the 

measured vent gas concentrations shall 

be used to determine the hydrogen, 

olefins, and hydrogen plus olefins 

concentration in the combustion zone 

using the following general equation. 

The methods specified in paragraphs 

(l)(1) through (3) of this section, as 

applicable, shall be used to assign the 

vent gas concentration results to a 

specific 15-minute block period. 

Where: 

Acz = Concentration of target compound(s) 

‘‘A’’ (representing either the olefins 

concentration, the hydrogen 

concentration, or the sum of the olefins 

and hydrogen concentration) in the 

combustion zone gas, volume fraction. 

Avg = Concentration of target compound(s) 

‘‘A’’ (representing either the olefins 

concentration, the hydrogen 

concentration, or the sum of the olefins 

and hydrogen concentration) in the flare 

vent gas determined for the 15-minute 

block period, volume fraction. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa, premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

(3) If NHVvg or total hydrocarbon 

monitoring systems are used as 

provided in paragraphs (j)(3) or (j)(4) of 

this section, the owner or operator may 

elect to determine the hydrogen and 

olefins concentrations using any of the 

following methods. 

(i) The owner or operator may elect to 

assume the hydrogen concentration, the 

olefins concentration, and the olefins 

plus hydrogen concentration in the 

combustion zone gas exceed all three 

criteria in (e)(4) at all times without 

making specific measurements of olefins 

or hydrogen concentrations. 

(ii) The owner or operator may elect 

to use process knowledge and 

engineering calculations to determine 

the highest flare vent gas concentrations 

of olefins and hydrogen that can 

reasonably be expected to be discharged 

to the flare and the highest 

concentration of olefins plus hydrogen 

that can reasonably be expected to be 

discharged to the flare while the flare 

vent gas concentrations exceed the 

target combustion zone concentrations 

in paragraphs (e)(4)(i) and (ii) of this 

section at the same time. The owner or 

operator shall take daily flare vent gas 

samples for fourteen days or for 7 flaring 

events, whichever results in the greatest 

number of grab samples to verify that 

the calculated values are representative 

of the highest concentrations that 

reasonably be expected to be discharged 

to the flare. 

(A) If the highest flare vent gas 

concentrations of olefins, hydrogen, and 

olefins plus hydrogen that can 

reasonably be expected to be discharged 

to the flare do not exceed all three 

combustion zone concentration criteria 

in paragraph (e)(4) of this section, for 

example, if the flare does not service 

any process units that contain olefins, 

then the engineering assessment is 

sufficient to document that all three 

criteria in paragraph (e)(4) of this 

section are not met and that the more 

stringent operating limits do not apply 

at any time. 

(B) If the highest flare vent gas 

concentrations of olefins, hydrogen, and 

olefins plus hydrogen that can 

reasonably be expected to be discharged 

to the flare exceed all three combustion 

zone concentration criteria in paragraph 

(e)(4), then the owner or operator will 

use the concentrations determined from 

the engineering analysis as the vent gas 

concentrations that exist in the vent gas 

at all times and use the equation in 

paragraph (o)(2) of this section to 

determine the combustion zone 

concentrations of olefins. 

(C) If the operation of process units 

connected to the flares change or new 

connections are made to the flare and 

these changes can reasonably be 

expected to alter the highest vent gas 

concentrations of olefins, hydrogen, 

and/or olefins plus hydrogen received 

by the flare, a new engineering 

assessment and sampling period for 

verification will be conducted following 

the requirements of paragraph (o)(3)(ii) 

of this section. 

(p) Flare monitoring records. The 

owner or operator shall keep the records 

specified in § 63.655(i)(9). 

(q) Reporting. The owner or operator 

shall comply with the reporting 

requirements specified in 

§ 63.655(g)(11). 

(r) Alternative means of emissions 

limitation. An owner or operator may 

request approval from the Administrator 

for site-specific operating limits that 

shall apply specifically to a selected 

flare. Site-specific operating limits 

include alternative threshold values for 

the parameters specified in paragraphs 

(d) through (f) of this section as well as 

threshold values for operating 

parameters other than those specified in 

paragraphs (d) through (f) of this 

section. The owner or operator must 

demonstrate that the flare achieves 96.5 

percent combustion efficiency (or 98 

percent destruction efficiency) using the 

site-specific operating limits based on a 

performance test as described in 

paragraph (r)(1) of this section. The 

request shall include information as 

described in paragraph (r)(2) of this 

section. The request shall be submitted 

and followed as described in paragraph 

(r)(3) of this section. 

(1) The owner or operator shall 

prepare and submit a site-specific test 

plan and receive approval of the sitespecific test plan prior to conducting 

any flare performance test intended for 

use in developing site-specific operating 

limits. The site-specific test plan shall 

include, at a minimum, the elements 

specified in paragraphs (r)(1)(i) through 

(ix) of this section. Upon approval of the 

site-specific test plan, the owner or 

operator shall conduct a performance 

test for the flare following the 

procedures described in the site-specific 

test plan. 

(i) The design and dimensions of the 

flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted, 

pressure-assisted, or non-assisted), and 

description of gas being flared, 

including quantity of gas flared, 

frequency of flaring events (if periodic), 

expected net heating value of flare vent 

gas, minimum total steam assist rate. 

(ii) The operating conditions (vent gas 

compositions, vent gas flow rates and 

assist flow rates, if applicable) likely to 

be encountered by the flare during 

normal operations and the operating 

conditions for the test period. 

(iii) A description of (including 

sample calculations illustrating) the 

planned data reduction and calculations 

to determine the flare combustion or 

destruction efficiency. 

(iv) Site-specific operating parameters 

to be monitored continuously during the 

flare performance test. These parameters 

may include but are not limited to vent 

gas flow rate, steam and/or air assist 

flow rates, and flare vent gas 

composition. If new operating 

parameters are proposed for use other 

than those specified in paragraphs (d) 

through (f) of this section, an 

explanation of the relevance of the 

proposed operating parameter(s) as an 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP30JN14.017</GPH>
36988 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

indicator of flare combustion 

performance and why the alternative 

operating parameter(s) can adequately 

ensure that the flare achieves the 

required combustion efficiency. 

(v) A detailed description of the 

measurement methods, monitored 

pollutant(s), measurement locations, 

measurement frequency, and recording 

frequency proposed for both emission 

measurements and flare operating 

parameters. 

(vi) A description of (including 

sample calculations illustrating) the 

planned data reduction and calculations 

to determine the flare operating 

parameters. 

(vii) The minimum number and 

length of test runs and range of 

operating values to be evaluated during 

the performance test. A sufficient 

number of test runs shall be conducted 

to identify the point at which the 

combustion/destruction efficiency of the 

flare deteriorates. 

(viii) If the flare can receive vent gases 

containing olefins and hydrogen above 

the levels specified for the combustion 

zone gas in paragraph (e)(4) of this 

section, a sufficient number of tests 

must be conducted while exceeding 

these limits to assess whether more 

stringent operating limits are required 

under these conditions. 

(ix) Test schedule. 

(2) The request for flare-specific 

operating limits shall include sufficient 

and appropriate data, as determined by 

the Administrator, to allow the 

Administrator to confirm that the 

selected site-specific operating limit(s) 

adequately ensures that the flare 

destruction efficiency is 98 percent or 

greater or that the flare combustion 

efficiency is 96.5 percent or greater at all 

times. At a minimum, the request shall 

contain the information described in 

paragraphs (r)(2)(i) through (iv) of this 

section. 

(i) The design and dimensions of the 

flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted, 

pressure-assisted, or non-assisted), and 

description of gas being flared, 

including quantity of gas flared, 

frequency of flaring events (if periodic), 

expected net heating value of flare vent 

gas, minimum total steam assist rate. 

(ii) Results of each performance test 

run conducted, including, at a 

minimum: 

(A) The measured combustion/

destruction efficiency. 

(B) The measured or calculated 

operating parameters for each test run. 

If operating parameters are calculated, 

the raw data from which the parameters 

are calculated must be included in the 

test report. 

(C) Measurement location 

descriptions for both emission 

measurements and flare operating 

parameters. 

(D) Description of sampling and 

analysis procedures (including number 

and length of test runs) and any 

modifications to standard procedures. If 

there were deviations from the approved 

test plan, a detailed description of the 

deviations and rationale why the test 

results or calculation procedures used 

are appropriate. 

(E) Operating conditions (e.g., vent 

gas composition, assist rates, etc.) that 

occurred during the test. 

(F) Quality assurance procedures. 

(G) Records of calibrations. 

(H) Raw data sheets for field 

sampling. 

(I) Raw data sheets for field and 

laboratory analyses. 

(J) Documentation of calculations. 

(iii) The selected flare-specific 

operating limit values based on the 

performance test results, including the 

averaging time for the operating limit(s), 

and rationale why the selected values 

and averaging times are sufficiently 

stringent to ensure proper flare 

performance. If new operating 

parameters or averaging times are 

proposed for use other than those 

specified in paragraphs (d) through (f) of 

this section, an explanation of why the 

alternative operating parameter(s) or 

averaging time(s) adequately ensures the 

flare achieves the required combustion 

efficiency. 

(iv) The means by which the owner or 

operator will document on-going, 

continuous compliance with the 

selected flare-specific operating limit(s), 

including the specific measurement 

location and frequencies, calculation 

procedures, and records to be 

maintained. 

(3) The request shall be submitted as 

described in paragraphs (r)(3)(i) through 

(iv) of this section. 

(i) The owner or operator may request 

approval from the Administrator at any 

time upon completion of a performance 

test conducted following the methods in 

an approved site-specific test plan for an 

operating limit(s) that shall apply 

specifically to that flare. 

(ii) The request must be submitted to 

the Administrator for approval. The 

owner or operator must continue to 

comply with the applicable standards 

for flares in this subpart until the 

requirements in 40 CFR 63.6(g)(1) are 

met and a notice is published in the 

Federal Register allowing use of such 

an alternative means of emission 

limitation. 

(iii) The request shall also be 

submitted to the following address: U.S. 

Environmental Protection Agency, 

Office of Air Quality Planning and 

Standards, Sector Policies and Programs 

Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also 

be submitted to refineryrtr@epa.gov. 

(iv) If the Administrator finds any 

deficiencies in the request, the request 

must be revised to address the 

deficiencies and be re-submitted for 

approval within 45 days of receipt of the 

notice of deficiencies. The owner or 

operator must comply with the revised 

request as submitted until it is 

approved. 

(4) The approval process for a request 

for a flare-specific operating limit(s) is 

described in paragraphs (r)(4)(i) through 

(iii) of this section. 

(i) Approval by the Administrator of 

a flare-specific operating limit(s) request 

will be based on the completeness, 

accuracy and reasonableness of the 

request. Factors that the EPA will 

consider in reviewing the request for 

approval include, but are not limited to, 

those described in paragraphs 

(r)(4)(i)(A) through (C) of this section. 

(A) The description of the flare design 

and operating characteristics. 

(B) If a new operating parameter(s) 

other than those specified in paragraphs 

(d) through (f) of this section is 

proposed, the explanation of how the 

proposed operating parameter(s) serves 

a good indicator(s) of flare combustion 

performance. 

(C) The results of the flare 

performance test and the establishment 

of operating limits that ensures that the 

flare destruction efficiency is 98 percent 

or greater or that the flare combustion 

efficiency is 96.5 percent or greater at all 

times. 

(D) The completeness of the flare 

performance test report. 

(ii) If the request is approved by the 

Administrator, a flare-specific operating 

limit(s) will be established at the level(s) 

demonstrated in the approved request. 

(iii) If the Administrator finds any 

deficiencies in the request, the request 

must be revised to address the 

deficiencies and be re-submitted for 

approval. 

33. Section 63.671 is added to read as 

follows: 

§ 63.671 Requirements for flare monitoring 

systems. 

(a) Operation of CPMS. For each 

CPMS installed to comply with 

applicable provisions in § 63.670, the 

owner or operator shall install, operate, 

calibrate, and maintain the CPMS as 


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Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36989 

specified in paragraphs (a)(1) through 

(8) of this section. 

(1) All monitoring equipment must 

meet the minimum accuracy, calibration 

and quality control requirements 

specified in table 13 of this subpart. 

(2) The owner or operator shall ensure 

the readout (that portion of the CPMS 

that provides a visual display or record) 

or other indication of the monitored 

operating parameter from any CPMS 

required for compliance is readily 

accessible onsite for operational control 

or inspection by the operator of the 

source. 

(3) All CPMS must complete a 

minimum of one cycle of operation 

(sampling, analyzing and data 

recording) for each successive 15- 

minute period. 

(4) Except for maintenance periods, 

instrument adjustments or checks to 

maintain precision and accuracy, 

calibration checks, and zero and span 

adjustments, the owner or operator shall 

operate all CPMS and collect data 

continuously when regulated emissions 

are routed to the flare. 

(5) The owner or operator shall 

operate, maintain, and calibrate each 

CPMS according to the CPMS 

monitoring plan specified in paragraph 

(b) of this section. 

(6) For each CPMS, the owner or 

operator shall comply with the out-ofcontrol procedures described in 

paragraphs (c) of this section. The CPMS 

monitoring plan must be submitted to 

the Administrator for approval upon 

request. 

(7) The owner or operator shall reduce 

data from a CPMS as specified in 

paragraph (d) of this section. 

(8) The CPMS must be capable of 

measuring the appropriate parameter 

over the range of values expected for 

that measurement location. The data 

recording system associated with each 

CPMS must have a resolution that is 

equal to or better than the required 

system accuracy. 

(b) CPMS monitoring plan. The owner 

or operator shall develop and 

implement a CPMS quality control 

program documented in a CPMS 

monitoring plan. The owner or operator 

shall have the CPMS monitoring plan 

readily available on-site at all times and 

shall submit a copy of the CPMS 

monitoring plan to the Administrator 

upon request by the Administrator. The 

CPMS monitoring plan must contain the 

information listed in paragraphs (b)(1) 

through (5) of this section. 

(1) Identification of the specific flare 

being monitored and the flare type (airassisted only, steam-assisted only, airand steam-assisted, pressure-assisted, or 

non-assisted). 

(2) Identification of the parameter to 

be monitored by the CPMS and the 

expected parameter range, including 

worst case and normal operation. 

(3) Description of the monitoring 

equipment, including the information 

specified in (c)(3)(i) through (viii) of this 

section. 

(i) Manufacturer and model number 

for all monitoring equipment 

components. 

(ii) Performance specifications, as 

provided by the manufacturer, and any 

differences expected for this installation 

and operation. 

(iii) The location of the CPMS 

sampling probe or other interface and a 

justification of how the location meets 

the requirements of paragraph (a)(1) of 

this section. 

(iv) Placement of the CPMS readout, 

or other indication of parameter values, 

indicating how the location meets the 

requirements of paragraph (a)(2) of this 

section. 

(v) Span of the analyzer. The span 

must encompass all expected 

concentrations and meet the 

requirements of paragraph (b)(10) of this 

section. 

(vi) How data outside of the analyzer’s 

span will be handled and the corrective 

action that will be taken to reduce and 

eliminate such occurrences in the 

future. 

(vii) Identification of the parameter 

detected by the parametric signal 

analyzer and the algorithm used to 

convert these values into the operating 

parameter monitored to demonstrate 

compliance, if the parameter detected is 

different from the operating parameter 

monitored. 

(4) Description of the data collection 

and reduction systems, including the 

information specified in paragraphs 

(b)(4)(i) through (iii) of this section. 

(i) A copy of the data acquisition 

system algorithm used to reduce the 

measured data into the reportable form 

of the standard and to calculate the 

applicable averages. 

(ii) Identification of whether the 

algorithm excludes data collected 

during CPMS breakdowns, out-ofcontrol periods, repairs, maintenance 

periods, instrument adjustments or 

checks to maintain precision and 

accuracy, calibration checks, and zero 

(low-level), mid-level (if applicable) and 

high-level adjustments. 

(iii) If the data acquisition algorithm 

does not exclude data collected during 

CPMS breakdowns, out-of-control 

periods, repairs, maintenance periods, 

instrument adjustments or checks to 

maintain precision and accuracy, 

calibration checks, and zero (low-level), 

mid-level (if applicable) and high-level 

adjustments, a description of the 

procedure for excluding this data when 

the averages calculated as specified in 

paragraph (e) of this section are 

determined. 

(5) Routine quality control and 

assurance procedures, including 

descriptions of the procedures listed in 

paragraphs (c)(5)(i) through (vi) of this 

section and a schedule for conducting 

these procedures. The routine 

procedures must provide an assessment 

of CPMS performance. 

(i) Initial and subsequent calibration 

of the CPMS and acceptance criteria. 

(ii) Determination and adjustment of 

the calibration drift of the CPMS. 

(iii) Daily checks for indications that 

the system is responding. If the CPMS 

system includes an internal system 

check, the owner or operator may use 

the results to verify the system is 

responding, as long as the owner or 

operator checks the internal system 

results daily for proper operation and 

the results are recorded. 

(iv) Preventive maintenance of the 

CPMS, including spare parts inventory. 

(v) Data recording, calculations and 

reporting. 

(vi) Program of corrective action for a 

CPMS that is not operating properly. 

(c) Out-of-control periods. For each 

CPMS, the owner or operator shall 

comply with the out-of-control 

procedures described in paragraphs 

(c)(1) and (2) of this section. 

(1) A CPMS is out-of-control if the 

zero (low-level), mid-level (if 

applicable) or high-level calibration 

drift exceeds two times the accuracy 

requirement of table 13 of this subpart. 

(2) When the CPMS is out of control, 

the owner or operator shall take the 

necessary corrective action and repeat 

all necessary tests that indicate the 

system is out of control. The owner or 

operator shall take corrective action and 

conduct retesting until the performance 

requirements are below the applicable 

limits. The beginning of the out-ofcontrol period is the hour a performance 

check (e.g., calibration drift) that 

indicates an exceedance of the 

performance requirements established 

in this section is conducted. The end of 

the out-of-control period is the hour 

following the completion of corrective 

action and successful demonstration 

that the system is within the allowable 

limits. The owner or operator shall not 

use data recorded during periods the 

CPMS is out of control in data averages 

and calculations, used to report 

emissions or operating levels, as 

specified in paragraph (d)(3) of this 

section. 

(d) CPMS data reduction. The owner 

or operator shall reduce data from a 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36990 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

CPMS as specified in paragraphs (d)(1) 

through (3) of this section. 

(1) The owner or operator may round 

the data to the same number of 

significant digits used in that operating 

limit. 

(2) Periods of non-operation of the 

process unit (or portion thereof) 

resulting in cessation of the emissions to 

which the monitoring applies must not 

be included in the 15-minute block 

averages. 

(3) Periods when the CPMS is out of 

control must not be included in the 15- 

minute block averages. 

(e) Additional requirements for gas 

chromatographs. For monitors used to 

determine compositional analysis for 

net heating value per § 63.670(j)(1), the 

gas chromatograph must also meet the 

requirements of paragraphs (e)(1) 

through (3) of this section. 

(1) The quality assurance 

requirements are in table 13 of this 

subpart. 

(2) The calibration gases must meet 

one of the following options: 

(i) The owner or operator must use a 

calibration gas or multiple gases that 

include all of the compounds that exist 

in the flare gas stream. All of the 

calibration gases may be combined in 

one cylinder. If multiple calibration 

gases are necessary to cover all 

compounds, the owner or operator must 

calibrate the instrument on all of the 

gases. 

(ii) The owner or operator must use a 

surrogate calibration gas consisting of 

C1 through C7 normal hydrocarbons. 

All of the calibration gases may be 

combined in one cylinder. If multiple 

calibration gases are necessary to cover 

all compounds, the owner or operator 

must calibrate the instrument on all of 

the gases. 

(3) If the owner or operator chooses to 

use a surrogate calibration gas under 

paragraph (e)(2)(ii) of this section, the 

owner or operator must comply with the 

following paragraphs. 

(i) Use the response factor for the 

nearest normal hydrocarbon (i.e., nalkane) in the calibration mixture to 

quantify unknown components detected 

in the analysis. 

(ii) Unknown compounds that elute 

after n-heptane must either be identified 

and quantified using an identical 

compound standard, or the owner or 

operator must extend the calibration 

range to include the additional normal 

hydrocarbons necessary to perform the 

unknown hydrocarbon quantitation 

procedure. 

■ 34. Table 6 to Subpart CC is amended 

by: 

■ a. Revising the entry ‘‘63.5(d)(1)(ii)’’; 

■ b. Revising the entry ‘‘63.5(f)’’; 

■ c. Removing the entry ‘‘63.6(e)’’; 

■ d. Adding, in numerical order, the 

entries ‘‘63.6(e)(1)(i) and (ii)’’ and 

‘‘63.6(e)(1)(iii)’’; 

■ e. Revising the entries ‘‘63.6(e)(3)(i)’’ 

and ‘‘63.6(e)(3)(iii)–63.6(e)(3)(ix)’’; 

■ f. Revising the entry ‘‘63.6(f)(1)’’; 

■ g. Removing the entry ‘‘63.6(f)(2) and 

(3)’’; 

■ h. Adding, in numerical order, the 

entries ‘‘63.6(f)(2)’’ and ‘‘63.6(f)(3)’’; 

■ i. Removing the entry ‘‘63.6(h)(1) and 

63.6(h)(2)’’; 

■ j. Adding, in numerical order, the 

entries ‘‘63.6(h)(1)’’ and ‘‘63.6(h)(2)’’; 

■ k. Revising the entry ‘‘63.7(b)’’; 

■ l. Revising the entry ‘‘63.7(e)(1)’’; 

■ m. Removing the entry ‘‘63.8(a)’’; 

■ n. Adding, in numerical order, the 

entries ‘‘63.8(a)(1) and (2),’’ ‘‘63.8(a)(3)’’ 

and ‘‘63.8(a)(4)’’; 

■ o. Revising the entry ‘‘63.8(c)(1)’’; 

■ p. Adding, in numerical order, the 

entries ‘‘63.8(c)(1)(i)’’ and 

‘‘63.8(c)(1)(iii)’’; 

■ q. Revising the entries ‘‘63.8(c)(4)’’ 

and ‘‘63.8(c)(5)–63.8(c)(8)’’; 

■ r. Revising the entries ‘‘63.8(d)’’ and 

‘‘63.8(e)’’; 

■ s. Revising the entry ‘‘63.8(g)’’; 

■ t. Revising the entries ‘‘63.10(b)(2)(i)’’ 

and ‘‘63.10(b)(2)(ii)’’; 

■ u. Revising the entries 

‘‘63.10(b)(2)(iv)’’ and ‘‘63.10(b)(2)(v)’’; 

■ v. Revising the entry 

‘‘63.10(b)(2)(vii)’’; 

■ w. Removing the entry ‘‘63.10(c)(9)– 

63.10(c)(15)’’; 

■ x. Adding, in numerical order, the 

entries ‘‘63.10(c)(9),’’ ‘‘63.10(c)(10)– 

63.10(c)(11)’’, and ‘‘63.10(c)(12)– 

63.10(c)(15)’’; 

■ y. Removing the entries 

‘‘63.10(d)(5)(i)’’ and ‘‘63.10(d)(5)(ii)’’; 

■ z. Adding, in numerical order, the 

entry ‘‘63.10(d)(5)’’; 

■ aa. Removing the entry ‘‘63.11– 

63.16’’; 

■ bb. Adding, in numerical order, the 

entries ‘‘63.11’’ and ‘‘63.12–63.16’’; 

■ cc. Removing footnote b. 

The revisions and additions read as 

follows: 

TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a

Reference Applies to 

subpart CC Comment 

*******

63.5(d)(1)(ii) .............................. Yes ............ Except that for affected sources subject to subpart CC, emission estimates specified in 

§ 63.5(d)(1)(ii)(H) are not required, and § 63.5(d)(1)(ii)(G) and (I) are Reserved and do not 

apply. 

* * * * * * * 

63.5(f) ....................................... Yes ............ Except that the cross-reference in § 63.5(f)(2) to § 63.9(b)(2) does not apply. 

* * * * * * * 

63.6(e)(1)(i) and (ii) .................. No .............. See § 63.642(n) for general duty requirement. 

63.6(e)(1)(iii) ............................. Yes.

* * * * * * * 

63.6(e)(3)(i) ............................... No.

* * * * * * * 

63.6(e)(3)(iii)–63.6(e)(3)(ix) ...... No.

63.6(f)(1) ................................... No.

63.6(f)(2) ................................... Yes ............ Except the phrase ‘‘as specified in § 63.7(c)’’ in § 63.6(f)(2)(iii)(D) does not apply because subpart CC does not require a site-specific test plan. 

63.6(f)(3) ................................... Yes ............ Except the cross-references to § 63.6(f)(1) and § 63.6(e)(1)(i) are changed to § 63.642(n). 

*******

63.6(h)(1) .................................. No.


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36991 

TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a—Continued 

Reference Applies to 

subpart CC Comment 

63.6(h)(2) .................................. Yes ............ Except § 63.6(h)(2)(ii), which is reserved. 

* * * * * * * 

63.7(b) ...................................... Yes ............ Except subpart CC requires notification of performance test at least 30 days (rather than 60 

days) prior to the performance test. 

*******

63.7(e)(1) .................................. No .............. See § 63.642(d)(3). 

*******

63.8(a)(1) and (2) ..................... Yes.

63.8(a)(3) .................................. No .............. Reserved. 

63.8(a)(4) .................................. Yes ............ Except that for a flare complying with § 63.670, the cross-reference to § 63.11 in this paragraph 

does not include § 63.11(b). 

*******

63.8(c)(1) .................................. Yes ............ Except § 63.8(c)(1)(i) and § 63.8(c)(iii). 

63.8(c)(1)(i) ............................... No .............. See § 63.642(n). 

63.8(c)(1)(iii) ............................. No.

*******

63.8(c)(4) .................................. Yes ............ Except that for sources other than flares, subpart CC specifies the monitoring cycle frequency 

specified in § 63.8(c)(4)(ii) is ‘‘once every hour’’ rather than ‘‘for each successive 15-minute 

period.’’ 

63.8(c)(5)–63.8(c)(8) ................. No .............. Subpart CC specifies continuous monitoring system requirements. 

63.8(d) ...................................... No .............. Subpart CC specifies quality control procedures for continuous monitoring systems. 

63.8(e) ...................................... Yes.

*******

63.8(g) ...................................... No .............. Subpart CC specifies data reduction procedures in §§ 63.655(i)(3) and 63.671(d). 

*******

63.10(b)(2)(i) ............................. No.

63.10(b)(2)(ii) ............................ No .............. See § 63.655(i)(11) for recordkeeping of (1) date, time and duration; (2) listing of affected 

source or equipment, and an estimate of the volume of each regulated pollutant emitted over 

the standard; and (3) actions to minimize emissions and correct the failure. 

*******

63.10(b)(2)(iv) ........................... No.

63.10(b)(2)(v) ............................ No.

*******

63.10(b)(2)(vii) .......................... No .............. § 63.655(i) of subpart CC specifies records to be kept for parameters measured with continuous 

monitors. 

*******

63.10(c)(9) ................................ No .............. Reserved. 

63.10(c)(10)–63.10(c)(11) ......... No .............. See § 63.655(i)(11) for malfunctions recordkeeping requirements. 

63.10(c)(12)–63.10(c)(15) ......... No.

*******

63.10(d)(5) ................................ No .............. See § 63.655(g)(12) for malfunctions reporting requirements. 

*******

63.11 ......................................... Yes ............ Except that flares complying with § 63.670 are not subject to the requirements of § 63.11(b). 

63.12–63.16 .............................. Yes.

aWherever subpart A specifies ‘‘postmark’’ dates, submittals may be sent by methods other than the U.S. Mail (e.g., by fax or courier). Submittals shall be sent by the specified dates, but a postmark is not required. 

■ 35. Table 10 to Subpart CC is 

amended by: 

■ a. Redesignating the entry ‘‘Flare’’ as 

‘‘Flare (if meeting the requirements of 

63.643 and 63.644)’’; 

■ b. Adding the entry ‘‘Flare (if meeting 

the requirements of 63.670 and 63.671)’’ 

after the newly redesignated entry 

‘‘Flare (if meeting the requirements of 

63.643 and 63.644)’’; 

■ c. Revising the entry ‘‘All control 

devices’’; and 

■ d. Revising footnote i. 

The revisions and additions read as 

follows: 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
36992 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR

COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS

PER MILLION BY VOLUME

Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored 

parameters 

*******

Flare (if meeting the requirements of 

63.670 and 63.671).

The parameters specified in 63.670 ...... 1. Records as specified in 63.655(i)(9). 

2. Report information as specified in 63.655(g)(11)—PR g. 

All control devices .................................. Volume of the gas stream diverted to 

the atmosphere from the control device (63.644(c)(1)) or 

1. Continuous records c. 

2. Record and report the times and durations of all periods 

when the vent stream is diverted through a bypass line or 

the monitor is not operating—PR g. 

Monthly inspections of sealed valves 

(63.644(c)(2)).

1. Records that monthly inspections were performed. 

2. Record and report all monthly inspections that show the 

valves are not closed or the seal has been changed— 

PR g. 

a Regulatory citations are listed in parentheses. 

c ‘‘Continuous records’’ is defined in § 63.641. 

gPR = Periodic Reports described in § 63.655(g). 

iProcess vents that are routed to refinery fuel gas systems are not regulated under this subpart provided that on and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas 

from that fuel gas system are in compliance with § 63.670. No monitoring, recordkeeping, or reporting is required for boilers and process heaters 

that combust refinery fuel gas. 

■ 36. Table 11 is added to Subpart CC 

to read as follows: 

TABLE 11—COMPLIANCE DATES AND REQUIREMENTS

If the construction/reconstruction date a is . . . Then the owner or operator must 

comply with . . . 

And the owner or operator must 

achieve compliance . . . Except as provided in . . . 

(1) After June 30, 2014 (i) Requirements for new sources in 

§§ 63.640 through 63.642, § 63.647, 

§§ 63.650 through 63.653, and 

§§ 63.656 through 63.660.

(a) Upon initial startup or [THE DATE 

OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], whichever is later.

(1) § 63.640(k), (l) and (m). 

(ii) The new source requirements in 

§ 63.654 for heat exchange systems.

(a) Upon initial startup or October 28, 

2009, whichever is later.

(1) § 63.640(k), (l) and (m). 

(2) After September 4, 

2007 but on or before 

June 30, 2014.

(i) Requirements for new sources in 

§§ 63.640 through 63.653 and 

63.656 b c.

(a) Upon initial startup ............................ (1) § 63.640(k), (l) and (m). 

(ii) Requirements for new sources in 

§§ 63.640 through 63.645, §§ 63.647 

through 63.653, and §§ 63.656, 

through 63.658 b.

(a) On or before [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].

(1) § 63.640(k), (l) and (m). 

(iii) Requirements for new sources in 

§ 63.660 c.

(a) On or before [THE DATE 90 DAYS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].

(1) § 63.640(k), (l) and (m). 

(iv) The new source requirements in 

§ 63.654 for heat exchange systems.

(a) Upon initial startup or October 28, 

2009, whichever is later.

(1) § 63.640(k), (l) and (m). 

(3) After July 14, 1994 

but on or before September 4, 2007.

(i) Requirements for new sources in 

§§ 63.640 through 63.653 and 

63.656 d e.

(a) Upon initial startup or August 18, 

1995, whichever is later.

(1) § 63.640(k), (l) and (m). 

(ii) Requirements for new sources in 

§§ 63.640 through 63.645, §§ 63.647 

through 63.653, and §§ 63.656, 

through 63.658 d.

(a) On or before [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].

(1) § 63.640(k), (l) and (m). 

(iii) Requirements for new sources in 

§ 63.660 e.

(a) On or before [THE DATE 90 DAYS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].

(1) § 63.640(k), (l) and (m). 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36993 

TABLE 11—COMPLIANCE DATES AND REQUIREMENTS—Continued 

If the construction/reconstruction date a is . . . Then the owner or operator must 

comply with . . . 

And the owner or operator must 

achieve compliance . . . Except as provided in . . . 

(iv) The existing source requirements in 

§ 63.654 for heat exchange systems.

(a) On or before October 29, 2012 ........ (1) § 63.640(k), (l) and (m). 

(4) On or before July 14, 

1994.

(i) Requirements for existing sources in 

§§ 63.640 through 63.653 and 

63.656 f g.

(a) On or before August 18, 1998 .......... (1) § 63.640(k), (l) and (m) 

(2) § 63.6(c)(5) of subpart A of 

this part or unless an extension has been granted by the 

Administrator as provided in 

§ 63.6(i) of subpart A of this 

part. 

(ii) Requirements for existing sources in 

§§ 63.640 through 63.645, §§ 63.647 

through 63.653, and §§ 63.656 

through 63.658 f.

(a) On or before [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].

(1) § 63.640(k), (l) and (m). 

(iii) Requirements for existing sources in 

§ 63.660 g.

(a) On or before [THE DATE 90 DAYS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].

(1) § 63.640(k), (l) and (m). 

(iii) The existing source requirements in 

§ 63.654 for heat exchange systems.

(a) On or before October 29, 2012 ........ (1) § 63.640(k), (l) and (m). 

aFor purposes of this table, the construction/reconstruction date means the date of construction or reconstruction of an entire affected source 

or the date of a process unit addition or change meeting the criteria in § 63.640(i) or (j). If a process unit addition or change does not meet the 

criteria in § 63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources. bBetween the compliance dates in items (2)(i)(a) and (2)(ii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(ii) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the 

requirements in item (2)(ii) of this table. cBetween the compliance dates in items (2)(i)(a) and (2)(iii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(iii) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with 

the requirements in item (2)(iii) of this table. dBetween the compliance dates in items (3)(i)(a) and (3)(ii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(ii) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the 

requirements in item (3)(ii) of this table. eBetween the compliance dates in items (3)(i)(a) and (3)(iii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(iii) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with 

the requirements in item (3)(iii) of this table. fBetween the compliance dates in items (4)(i)(a) and (4)(ii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the 

requirements in item (4)(ii) of this table. gBetween the compliance dates in items (4)(i)(a) and (4)(iii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(iii) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with 

the requirements in item (4)(iii) of this table. 

■ 37. Table 12 is added to Subpart CC 

to read as follows: 

TABLE 12—INDIVIDUAL COMPONENT PROPERTIES

Component Molecular 

formula 

MWi

(pounds per 

pound-mole) 

CMNi

(mole per mole) 

NHVi

(British thermal 

units per standard cubic foot) 

LFLi

(volume %) 

Acetylene ........................................................ C2H2 .................... 26.04 2 1,404 2.5 

Benzene ......................................................... C6H6 .................... 78.11 6 3,591 1.3 

1,2-Butadiene ................................................. C4H6 .................... 54.09 4 2,794 2.0 

1,3-Butadiene ................................................. C4H6 .................... 54.09 4 2,690 2.0 

iso-Butane ...................................................... C4H10 ................... 58.12 4 2,957 1.8 

n-Butane ......................................................... C4H10 ................... 58.12 4 2,968 1.8 

cis-Butene ...................................................... C4H8 .................... 56.11 4 2,830 1.6 

iso-Butene ...................................................... C4H8 .................... 56.11 4 2,928 1.8 

trans-Butene ................................................... C4H8 .................... 56.11 4 2,826 1.7 

Carbon Dioxide .............................................. CO2 ..................... 44.01 1 0 ∞ 

Carbon Monoxide ........................................... CO ....................... 28.01 1 316 12.5 

Cyclopropane ................................................. C3H6 .................... 42.08 3 2,185 2.4 

Ethane ............................................................ C2H6 .................... 30.07 2 1,595 3.0 

Ethylene ......................................................... C2H4 .................... 28.05 2 1,477 2.7 

Hydrogen ........................................................ H2 ........................ 2.02 0 274 4.0 

Methane ......................................................... CH4 ...................... 16.04 1 896 5.0 


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36994 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 12—INDIVIDUAL COMPONENT PROPERTIES—Continued 

Component Molecular 

formula 

MWi

(pounds per 

pound-mole) 

CMNi

(mole per mole) 

NHVi

(British thermal 

units per standard cubic foot) 

LFLi

(volume %) 

Methyl-Acetylene ............................................ C3H4 .................... 40.06 3 2,088 1.7 

Nitrogen .......................................................... N2 ........................ 28.01 0 0 ∞ 

Oxygen ........................................................... O2 ........................ 32.00 0 0 ∞ 

Pentane+ (C5+) .............................................. C5H12 ................... 72.15 5 3,655 1.4 

Propadiene ..................................................... C3H4 .................... 40.06 3 2,066 2.16 

Propane .......................................................... C3H8 .................... 44.10 3 2,281 2.1 

Propylene ....................................................... C3H6 .................... 42.08 3 2,150 2.4 

Water .............................................................. H2O ..................... 18.02 0 0 ∞ 

■ 38. Table 13 is added to Subpart CC 

to read as follows: 

TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS 

Parameter Accuracy requirements Calibration requirements 

Temperature ................... ±1 percent over the normal range of 

temperature measured or 2.8 degrees Celsius (5 degrees Fahrenheit), whichever is greater, for 

non-cryogenic temperature ranges.

Performance evaluation annually and following any period of more than 24 

hours throughout which the temperature exceeded the maximum rated 

temperature of the sensor, or the data recorder was off scale. Visual inspections and checks of CPMS operation every 3 months, unless the 

CPMS has a redundant temperature sensor. 

±2.5 percent over the normal range of 

temperature measured or 2.8 degrees Celsius (5 degrees Fahrenheit), whichever is greater, for 

cryogenic temperature ranges.

Select a representative measurement location. 

Flow Rate ....................... ±5 percent over the normal range of 

flow measured or 1.9 liters per 

minute (0.5 gallons per minute), 

whichever is greater, for liquid flow 

rate.

Performance evaluation annually and following any period of more than 24 

hours throughout which the flow rate exceeded the maximum rated flow 

rate of the sensor, or the data recorder was off scale. Checks of all mechanical connections for leakage monthly. Visual inspections and checks 

of CPMS operation every 3 months, unless the CPMS has a redundant 

flow sensor. 

±5 percent over the normal range of 

flow measured or 280 liters per 

minute (10 cubic feet per minute), 

whichever is greater, for gas flow 

rate.

Select a representative measurement location where swirling flow or abnormal velocity distributions due to upstream and downstream disturbances 

at the point of measurement are minimized. 

±5 percent over the normal range 

measured for mass flow rate.

Pressure ......................... ±5 percent over the normal range 

measured or 0.12 kilopascals (0.5 

inches of water column), whichever 

is greater.

Checks for obstructions at least once each process operating day (e.g., 

pressure tap pluggage). 

Performance evaluation annually and following any period of more than 24 

hours throughout which the pressure exceeded the maximum rated pressure of the sensor, or the data recorder was off scale. Checks of all mechanical connections for leakage monthly. Visual inspection of all components for integrity, oxidation and galvanic corrosion every 3 months, unless the CPMS has a redundant pressure sensor. 

Select a representative measurement location that minimizes or eliminates 

pulsating pressure, vibration, and internal and external corrosion. 

Net Heating Value by 

Calorimeter.

±2 percent of span .............................. Specify calibration requirements in your site specific CPMS monitoring plan. 

Calibration requirements should follow manufacturer’s recommendations 

at a minimum. 

Temperature control (heated and/or cooled as necessary) the sampling system to ensure proper year-round operation. 

Where feasible, select a sampling location at least two equivalent diameters 

downstream from and 0.5 equivalent diameters upstream from the nearest 

disturbance. Select the sampling location at least two equivalent duct diameters from the nearest control device, point of pollutant generation, air 

in-leakages, or other point at which a change in the pollutant concentration or emission rate occurs. 

Net Heating Value by 

Gas Chromatograph.

As specified in Performance Specification 9 of 40 CFR part 60, Appendix B.Follow the procedure in Performance Specification 9 of 40 CFR part 60, Appendix B 


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TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS—Continued 

Parameter Accuracy requirements Calibration requirements 

Net Heating Value by 

Total Hydrocarbon 

Monitor.

Calibration drift ≤3% of instrument 

span at each level.

Calibration drift check daily. Follow the procedure in Sections 4.1 and 4.2 of 

Procedure 1 in 40 CFR part 60, Appendix F. 

Cylinder Gas Audit Accuracy ≤5% of 

instrument span at each level.

Cylinder gas audit quarterly. Follow the procedure in Section 5.1.2 of Procedure 1 in 40 CFR part 60, Appendix F, except the audit shall be performed every quarter. 

For both the calibration drift and error tests, the calibration gases should be 

injected into the sampling system as close to the sampling probe outlet as 

practical and must pass through all filters, scrubbers, conditioners, and 

other monitor components used during normal sampling. 

Select a measurement location that meets the requirements of Section 3.1 

of Performance Specification 8A of Appendix B to 40 CFR part 60. 

Subpart UUU—[Amended] 

■ 39. Section 63.1562 is amended by: 

■ (a) Revising paragraph (b)(3) and 

■ (b) Revising paragraph (f)(5). 

The revisions read as follows: 

§ 63.1562 What parts of my plant are 

covered by this subpart? 

* * * * * 

(b) * * * 

(3) The process vent or group of 

process vents on Claus or other types of 

sulfur recovery plant units or the tail gas 

treatment units serving sulfur recovery 

plants that are associated with sulfur 

recovery. 

* * * * * 

(f) * * * 

(5) Gaseous streams routed to a fuel 

gas system, provided that on and after 

[THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], any flares 

receiving gas from the fuel gas system 

are in compliance with § 63.670. 

■ 40. Section 63.1564 is amended by: 

■ a. Revising paragraph (a)(1) 

introductory text; 

■ b. Revising paragraph (a)(1)(i); 

■ c. Revising paragraph (a)(1)(ii); 

■ d. Revising paragraph (a)(1)(iv); 

■ e. Adding paragraph (a)(5); 

■ f. Revising paragraph (b)(4)(i); 

■ g. Revising paragraph (b)(4)(ii); 

■ h. Revising paragraph (b)(4)(iv); 

■ i. Adding paragraph (c)(5). 

The revisions and additions read as 

follows: 

§ 63.1564 What are my requirements for 

metal HAP emissions from catalytic 

cracking units? 

(a) * * * 

(1) Meet each emission limitation in 

Table 1 of this subpart that applies to 

you. If your catalytic cracking unit is 

subject to the NSPS for PM in § 60.102 

or is subject to § 60.102a(b)(1) of this 

chapter, you must meet the emission 

limitations for NSPS units. If your 

catalytic cracking unit is not subject to 

the NSPS for PM, you can choose from 

the four options in paragraphs (a)(1)(i) 

through (iv) of this section: 

(i) You can elect to comply with the 

PM per coke burn-off emission limit 

(Option 1); 

(ii) You can elect to comply with the 

PM concentration emission limit 

(Option 2); 

* * * * * 

(iv) You can elect to comply with the 

Ni per coke burn-off emission limit 

(Option 4). 

* * * * * 

(5) During periods of startup only, if 

your catalytic cracking unit is followed 

by an electrostatic precipitator, you can 

choose from the two options in 

paragraphs (a)(5)(i) and (ii) of this 

section: 

(i) You can elect to comply with the 

requirements paragraphs (a)(1) and (2) 

of this section; or 

(ii) You can elect to maintain the 

opacity in the exhaust gas from your 

catalyst regenerator at or below 30 

percent opacity on a 6-minute average 

basis. 

(b) * * * 

(4) * * * 

(i) If you elect Option 1 in paragraph 

(a)(1)(i) of this section, compute the PM 

emission rate (lb/1,000 lb of coke burnoff) for each run using Equations 1, 2, 

and 3 (if applicable) of this section and 

the site-specific opacity limit, if 

applicable, using Equation 4 of this 

section as follows: 

Where: 

Rc = Coke burn-off rate, kg/hr (lb/hr); 

Qr = Volumetric flow rate of exhaust gas from 

catalyst regenerator before adding air or 

gas streams. Example: You may measure 

upstream or downstream of an 

electrostatic precipitator, but you must 

measure upstream of a carbon monoxide 

boiler, dscm/min (dscf/min). You may 

use the alternative in either 

§ 63.1573(a)(1) or (a)(2), as applicable, to 

calculate Qr; 

Qa = Volumetric flow rate of air to catalytic 

cracking unit catalyst regenerator, as 

determined from instruments in the 

catalytic cracking unit control room, 

dscm/min (dscf/min); 

%CO2 = Carbon dioxide concentration in 

regenerator exhaust, percent by volume 

(dry basis); 

%CO = Carbon monoxide concentration in 

regenerator exhaust, percent by volume 

(dry basis); 

%O2 = Oxygen concentration in regenerator 

exhaust, percent by volume (dry basis); 

K1 = Material balance and conversion factor, 

0.2982 (kg-min)/(hr-dscm-%) (0.0186 (lbmin)/(hr-dscf-%)); 

K2 = Material balance and conversion factor, 

2.088 (kg-min)/(hr-dscm) (0.1303 (lbmin)/(hr-dscf)); 

K3 = Material balance and conversion factor, 

0.0994 (kg-min)/(hr-dscm-%) (0.0062 (lbmin)/(hr-dscf-%)); 

Qoxy = Volumetric flow rate of oxygenenriched air stream to regenerator, as 

determined from instruments in the 

catalytic cracking unit control room, 

dscm/min (dscf/min); and 

%Oxy = Oxygen concentration in oxygenenriched air stream, percent by volume 

(dry basis). 


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36996 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

Where: 

E = Emission rate of PM, kg/1,000 kg (lb/

1,000 lb) of coke burn-off; 

Cs = Concentration of PM, g/dscm (lb/dscf); 

Qsd = Volumetric flow rate of the catalytic 

cracking unit catalyst regenerator flue 

gas as measured by Method 2 in 

appendix A to part 60 of this chapter, 

dscm/hr (dscf/hr); 

Rc = Coke burn-off rate, kg coke/hr (1,000 lb 

coke/hr); and 

K = Conversion factor, 1.0 (kg2/g)/(1,000 kg) 

(1,000 lb/(1,000 lb)). 

Where: 

Es = Emission rate of PM allowed, kg/1,000 

kg (1b/1,000 lb) of coke burn-off in 

catalyst regenerator; 

1.0 = Emission limitation, kg coke/1,000 kg 

(lb coke/1,000 lb); 

A = Allowable incremental rate of PM 

emissions. Before [THE DATE 18 

MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], A=0.18 g/million cal (0.10 

lb/million Btu). On or after [THE DATE 

18 MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], A=0 g/million cal (0 lb/

million Btu); 

H = Heat input rate from solid or liquid fossil 

fuel, million cal/hr (million Btu/hr). 

Make sure your permitting authority 

approves procedures for determining the 

heat input rate; 

Rc = Coke burn-off rate, kg coke/hr (1,000 lb 

coke/hr) determined using Equation 1 of 

this section; and 

K′ = Conversion factor to units to standard, 

1.0 (kg2/g)/(1,000 kg) (103 lb/(1,000 lb)). 

Where: 

Opacity Limit = Maximum permissible 

hourly average opacity, percent, or 10 

percent, whichever is greater; 

Opacityst = Hourly average opacity measured 

during the source test, percent; and 

PMEmRst = PM emission rate measured 

during the source test, lb/1,000 lb coke 

burn. 

(ii) If you elect Option 2 in paragraph 

(a)(1)(ii) of this section, the PM 

concentration emission limit, determine 

the average PM concentration from the 

initial performance test used to certify 

your PM CEMS. 

* * * * * 

(iv) If you elect Option 4 in paragraph 

(a)(1)(iv) of this section, the Ni per coke 

burn-off emission limit, compute your 

Ni emission rate using Equations 1 and 

8 of this section and your site-specific 

Ni operating limit (if you use a 

continuous opacity monitoring system) 

using Equations 9 and 10 of this section 

as follows: 

Where: ENi2 = Normalized mass emission rate of Ni, 

mg/kg coke (lb/1,000 lb coke). 

Where: 

Opacity2 = Opacity value for use in Equation 

10 of this section, percent, or 10 percent, 

whichever is greater; and 

NiEmR2st = Average Ni emission rate 

calculated as the arithmetic average Ni 

emission rate using Equation 8 of this 

section for each of the performance test 

runs, mg/kg coke. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP30JN14.019</GPH> EP30JN14.020</GPH> EP30JN14.021</GPH> EP30JN14.022</GPH> EP30JN14.023</GPH> EP30JN14.024</GPH>
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36997 

Where: 

Ni Operating Limit2 = Maximum permissible 

hourly average Ni operating limit, 

percent-ppmw-acfm-hr/kg coke, i.e., 

your site-specific Ni operating limit; and 

Rc,st = Coke burn rate from Equation 1 of this 

section, as measured during the initial 

performance test, kg coke/hr. 

* * * * * 

(c) * * * 

(5) During periods of startup only, if 

you elect to comply with the alternative 

limit in paragraph (a)(5)(ii) of this 

section, determine continuous 

compliance by: collecting opacity 

readings using either a continuous 

opacity monitoring system according to 

§ 63.1572 or manual opacity 

observations following EPA Method 9 in 

Appendix A–4 to part 60 of this chapter; 

and maintaining each 6-minute average 

opacity at or below 30 percent. 

■ 41. Section 63.1565 is amended by: 

■ a. Adding paragraph (a)(5); 

■ b. Adding paragraph (b)(1)(iv); and 

■ c. Adding paragraph (c)(3). 

The additions read as follows: 

§ 63.1565 What are my requirements for 

organic HAP emissions from catalytic 

cracking units? 

(a) * * * 

(5) During periods of startup only, if 

your catalytic cracking unit is not 

followed by a CO boiler, thermal 

oxidizer, incinerator, flare or similar 

combustion device, you can choose 

from the two options in paragraphs 

(a)(5)(i) and (ii) of this section: 

(i) You can elect to comply with the 

requirements in paragraphs (a)(1) and 

(2) of this section; or 

(ii) You can elect to maintain the 

oxygen (O2) concentration in the 

exhaust gas from your catalyst 

regenerator at or above 1 volume 

percent (dry basis). 

(b) * * * 

(1) * * * 

(iv) If you elect to comply with the 

alternative limit for periods of startup in 

paragraph (a)(5)(ii) of this section, you 

must also install, operate, and maintain 

a continuous parameter monitoring 

system to measure and record the 

oxygen content (percent, dry basis) in 

the catalyst regenerator vent. 

* * * * * 

(c) * * * 

(3) Demonstrate continuous 

compliance with the alternative limit in 

paragraph (a)(5)(ii) of this section by 

collecting the hourly average oxygen 

concentration monitoring data 

according to § 63.1572 and maintaining 

the hourly average oxygen concentration 

at or above 1 volume percent (dry basis). 

■ 42. Section 63.1566 is amended by: 

■ a. Revising paragraph (a)(1) 

introductory text; 

■ b. Revising paragraph (a)(1)(i); and 

■ c. Revising paragraph (a)(4). 

The revisions read as follows: 

§ 63.1566 What are my requirements for 

organic HAP emissions from catalytic 

reforming units? 

(a) * * * 

(1) Meet each emission limitation in 

Table 15 of this subpart that applies to 

you. You can choose from the two 

options in paragraphs (a)(1)(i) and (ii) of 

this section. 

(i) You can elect to vent emissions of 

total organic compounds (TOC) to a 

flare (Option 1). On and after [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet the 

requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet the 

control device requirements in 

§ 63.11(b) or the requirements of 

§ 63.670. 

* * * * * 

(4) The emission limitations in Tables 

15 and 16 of this subpart do not apply 

to emissions from process vents during 

passive depressuring when the reactor 

vent pressure is 5 pounds per square 

inch gauge (psig) or less. The emission 

limitations in Tables 15 and 16 of this 

subpart do apply to emissions from 

process vents during active purging 

operations (when nitrogen or other 

purge gas is actively introduced to the 

reactor vessel) or active depressuring 

(using a vacuum pump, ejector system, 

or similar device) regardless of the 

reactor vent pressure. 

* * * * * 

■ 43. Section 63.1568 is amended by: 

■ a. Revising paragraph (a)(1) 

introductory text; 

■ b. Revising paragraph (a)(1)(i); 

■ c. Adding paragraph (a)(4); 

■ d. Revising paragraph (b)(1); and 

■ e. Adding paragraphs (c)(3) and (4). 

The revisions and additions read as 

follows: 

§ 63.1568 What are my requirements for 

HAP emissions from sulfur recovery units? 

(a) * * * 

(1) Meet each emission limitation in 

Table 29 of this subpart that applies to 

you. If your sulfur recovery unit is 

subject to the NSPS for sulfur oxides in 

§ 60.104 or in § 60.102a(f)(1) of this 

chapter, you must meet the emission 

limitations for NSPS units. If your sulfur 

recovery unit is not subject to one of 

these NSPS for sulfur oxides, you can 

choose from the options in paragraphs 

(a)(1)(i) through (ii) of this section: 

(i) You can elect to meet the NSPS 

requirements in § 60.104(a)(2) or in 

§ 60.102a(f)(1) of this chapter (Option 1); 

or 

* * * * * 

(4) During periods of shutdown only, 

you can choose from the three options 

in paragraphs (a)(4)(i) through (iii) of 

this section. 

(i) You can elect to comply with the 

requirements in paragraphs (a)(1) and 

(2) of this section. 

(ii) You can elect to send any 

shutdown purge gases to a flare. On and 

after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare must 

meet the requirements of § 63.670. Prior 

to [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare must 

meet the design and operating 

requirements in § 63.11(b) or the 

requirements of § 63.670. 

(iii) You can elect to send any 

shutdown purge gases to a to 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). 

(b) * * * 

(1) Install, operate, and maintain a 

continuous monitoring system 

according to the requirements in 

§ 63.1572 and Table 31 of this subpart. 

Except: 

(i) If you elect to comply with the 

alternative limit for periods of 

shutdown in paragraph (a)(4)(ii) of this 

section, then on and after [THE DATE 

3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], you must also install, 

operate, calibrate, and maintain 

monitoring systems as specified in 

§§ 63.670 and 63.671. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], you must either install, 

operate, and maintain continuous 

parameter monitoring systems following 

the requirements in § 63.11 (to detect 

the presence of a flame; to measure and 

record the net heating value of the gas 

being combusted; and to measure and 

record the volumetric flow of the gas 

being combusted) or install, operate, 

calibrate, and maintain monitoring 

systems as specified in §§ 63.670 and 

63.671. 

(ii) If you elect to comply with the 

alternative limit for periods of 


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36998 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

shutdown in paragraph (a)(4)(iii) of this 

section, you must also install, operate, 

and maintain continuous parameter 

monitoring system to measure and 

record the temperature and oxygen 

content (percent, dry basis) in the vent 

from the thermal oxidizer or incinerator. 

* * * * * 

(c) * * * 

(3) Demonstrate continuous 

compliance with the alternative limit in 

paragraph (a)(4)(ii) of this section by 

meeting the requirements of either 

paragraph (c)(3)(i) or (ii) of this section. 

(i) On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], you 

must meet the requirements of 

paragraphs (c)(3)(i)(A) through (C) of 

this section. 

(A) Collect the flare monitoring data 

according to §§ 63.670 and 63.671. 

(B) Keep the records specified in 

§ 63.655(i)(9). 

(C) Maintain the selected operating 

parameters as specified in § 63.670. 

(ii) Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], you 

must either meet the requirements of 

paragraph (c)(3)(i) of this section or 

meet the requirements of paragraphs 

(c)(3)(ii)(A) through (D) of this section. 

(A) Collect the flare monitoring data 

according to § 63.1572. 

(B) Record for each 1-hour period 

whether the monitor was continuously 

operating and the pilot light was 

continuously present during each 1- 

hour period. 

(C) Maintain the net heating value of 

the gas being combusted at or above the 

applicable limits in § 63.11. 

(D) Maintain the exit velocity at or 

below the applicable maximum exit 

velocity specified in § 63.11. 

(4) Demonstrate continuous 

compliance with the alternative limit in 

paragraph (a)(4)(iii) of this section by 

collecting the hourly average 

temperature and oxygen concentration 

monitoring data according to § 63.1572; 

maintaining the hourly average 

temperature at or above 1,200 degrees 

Fahrenheit; and maintaining the hourly 

average oxygen concentration at or 

above 2 volume percent (dry basis). 

■ 44. Section 63.1570 is amended by: 

■ a. Revising paragraphs (a) through (d); 

and 

■ b. Removing and reserving paragraph 

(g). 

The revisions read as follows: 

§ 63.1570 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

all of the non-opacity standards in this 

subpart at all times. 

(b) You must be in compliance with 

the opacity and visible emission limits 

in this subpart at all times. 

(c) At all times, you must operate and 

maintain any affected source, including 

associated air pollution control 

equipment and monitoring equipment, 

in a manner consistent with safety and 

good air pollution control practices for 

minimizing emissions. The general duty 

to minimize emissions does not require 

you to make any further efforts to 

reduce emissions if levels required by 

the applicable standard have been 

achieved. Determination of whether a 

source is operating in compliance with 

operation and maintenance 

requirements will be based on 

information available to the 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

(d) During the period between the 

compliance date specified for your 

affected source and the date upon which 

continuous monitoring systems have 

been installed and validated and any 

applicable operating limits have been 

set, you must maintain a log detailing 

the operation and maintenance of the 

process and emissions control 

equipment. 

* * * * * 

■ 45. Section 63.1571 is amended by: 

■ a. Adding paragraph (a)(5); 

■ b. Revising paragraph (b)(1); 

■ c. Removing paragraph (b)(4); 

■ d. Redesignating paragraph (b)(5) as 

(b)(4); 

■ e. Revising paragraphs (d)(2) and 

(d)(4). 

The revisions and additions read as 

follows: 

§ 63.1571 How and when do I conduct a 

performance test or other initial compliance 

demonstration? 

(a) * * * 

(5) Conduct a performance test for PM 

or Ni, as applicable, from catalytic 

cracking units at least once every 5 

years for those units monitored with 

CPMS, BLD, or COMS. You must 

conduct the first periodic performance 

test no later than [THE DATE 18 

MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER]. Those units monitoring PM 

concentration with a PM CEMS are not 

required to conduct a periodic PM 

performance test. 

(b) * * * 

(1) Conduct performance tests under 

such conditions as the Administrator 

specifies to you based on representative 

performance of the affected source for 

the period being tested. Representative 

conditions exclude periods of startup 

and shutdown unless specified by the 

Administrator or an applicable subpart. 

You may not conduct performance tests 

during periods of malfunction. You 

must record the process information 

that is necessary to document operating 

conditions during the test and include 

in such record an explanation to 

support that such conditions represent 

normal operation. Upon request, you 

must make available to the 

Administrator such records as may be 

necessary to determine the conditions of 

performance tests. 

* * * * * 

(d) * * * 

(2) If you must meet the HAP metal 

emission limitations in § 63.1564, you 

elect the option in paragraph (a)(1)(iv) 

in § 63.1564 (Ni per coke burn-off), and 

you use continuous parameter 

monitoring systems, you must establish 

an operating limit for the equilibrium 

catalyst Ni concentration based on the 

laboratory analysis of the equilibrium 

catalyst Ni concentration from the 

initial performance test. Section 

63.1564(b)(2) allows you to adjust the 

laboratory measurements of the 

equilibrium catalyst Ni concentration to 

the maximum level. You must make this 

adjustment using Equation 2 of this 

section as follows: 


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Where: 

NiEmR2st = Average Ni emission rate 

calculated as the arithmetic average Ni 

emission rate using Equation 8 of 

§ 63.1564 for each performance test run, 

mg/kg coke burn-off. 

* * * * * 

(4) Except as specified in paragraph 

(d)(3) of this section, if you use 

continuous parameter monitoring 

systems, you may adjust one of your 

monitored operating parameters (flow 

rate, total power and secondary current, 

pressure drop, liquid-to-gas ratio) from 

the average of measured values during 

the performance test to the maximum 

value (or minimum value, if applicable) 

representative of worst-case operating 

conditions, if necessary. This 

adjustment of measured values may be 

done using control device design 

specifications, manufacturer 

recommendations, or other applicable 

information. You must provide 

supporting documentation and rationale 

in your Notification of Compliance 

Status, demonstrating to the satisfaction 

of your permitting authority, that your 

affected source complies with the 

applicable emission limit at the 

operating limit based on adjusted 

values. 

* * * * * 

■ 46. Section 63.1572 is amended by: 

■ a. Revising paragraphs (c) 

introductory text, (c)(1), (c)(3) and (c)(4); 

and 

■ b. Revising paragraphs (d)(1) and (2). 

The revisions read as follows: 

§ 63.1572 What are my monitoring 

installation, operation, and maintenance 

requirements? 

* * * * * 

(c) Except for flare monitoring 

systems, you must install, operate, and 

maintain each continuous parameter 

monitoring system according to the 

requirements in paragraphs (c)(1) 

through (5) of this section. For flares, on 

and after [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you must install, 

operate, calibrate, and maintain 

monitoring systems as specified in 

§§ 63.670 and 63.671. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], you must either meet the 

monitoring system requirements in 

paragraphs (c)(1) through (5) of this 

section or meet the requirements in 

§§ 63.670 and 63.671. 

(1) You must install, operate, and 

maintain each continuous parameter 

monitoring system according to the 

requirements in Table 41 of this subpart. 

You must also meet the equipment 

specifications in Table 41 of this subpart 

if pH strips or colormetric tube 

sampling systems are used. You must 

meet the requirements in Table 41 of 

this subpart for BLD systems. 

* * * * * 

(3) Each continuous parameter 

monitoring system must have valid 

hourly average data from at least 75 

percent of the hours during which the 

process operated, except for BLD 

systems. 

(4) Each continuous parameter 

monitoring system must determine and 

record the hourly average of all recorded 

readings and if applicable, the daily 

average of all recorded readings for each 

operating day, except for BLD systems. 

The daily average must cover a 24-hour 

period if operation is continuous or the 

number of hours of operation per day if 

operation is not continuous, except for 

BLD systems. 

* * * * * 

(d) * * * 

(1) You must conduct all monitoring 

in continuous operation (or collect data 

at all required intervals) at all times the 

affected source is operating. 

(2) You may not use data recorded 

during required quality assurance or 

control activities (including, as 

applicable, calibration checks and 

required zero and span adjustments) for 

purposes of this regulation, including 

data averages and calculations, for 

fulfilling a minimum data availability 

requirement, if applicable. You must 

use all the data collected during all 

other periods in assessing the operation 

of the control device and associated 

control system. 

■ 47. Section 63.1573 is amended by: 

■ a. Redesignating paragraphs (b), (c), 

(d), (e) and (f) as paragraphs (c), (d), (e), 

(f) and (g); 

■ b. Adding paragraph (b); 

■ c. Revising newly redesignated 

paragraph (c) introductory text; 

■ d. Revising newly redesignated 

paragraph (d) introductory text; 

■ e. Revising newly redesignated 

paragraph (f) introductory text; and 

■ f. Revising newly redesignated 

paragraph (g)(1). 

The revisions and additions read as 

follows: 

§ 63.1573 What are my monitoring 

alternatives? 

* * * * * 

(b) What is the approved alternative 

for monitoring pressure drop? You may 

use this alternative to a continuous 

parameter monitoring system for 

pressure drop if you operate a jet ejector 

type wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles. You shall: 

(1) Conduct a daily check of the air or 

water pressure to the spray nozzles; 

(2) Maintain records of the results of 

each daily check; and 

(3) Repair or replace faulty (e.g., 

leaking or plugged) air or water lines 

within 12 hours of identification of an 

abnormal pressure reading. 

(c) What is the approved alternative 

for monitoring pH or alkalinity levels? 

You may use the alternative in 

paragraph (c)(1) or (2) of this section for 

a catalytic reforming unit. 

* * * * * 

(d) Can I use another type of 

monitoring system? You may request 

approval from your permitting authority 

to use an automated data compression 

system. An automated data compression 

system does not record monitored 

operating parameter values at a set 

frequency (e.g., once every hour) but 

records all values that meet set criteria 

for variation from previously recorded 

values. Your request must contain a 

description of the monitoring system 

and data recording system, including 

the criteria used to determine which 

monitored values are recorded and 

retained, the method for calculating 

daily averages, and a demonstration that 

the system meets all of the criteria in 

paragraphs (d)(1) through (5) of this 

section: 

* * * * * 

(f) How do I request to monitor 

alternative parameters? You must 

submit a request for review and 

approval or disapproval to the 

Administrator. The request must 

include the information in paragraphs 

(f)(1) through (5) of this section. 

* * * * * 

(g) * * * 

(1) You may request alternative 

monitoring requirements according to 

the procedures in this paragraph if you 

meet each of the conditions in 

paragraphs (g)(1)(i) through (iii) of this 

section: 

* * * * * 

■ 48. Section 63.1574 is amended by 

revising (a)(3) to read as follows: 

§ 63.1574 What notifications must I submit 

and when? 

(a) * * * 

(3) If you are required to conduct an 

initial performance test, performance 

evaluation, design evaluation, opacity 

observation, visible emission 

observation, or other initial compliance 

demonstration, you must submit a 

notification of compliance status 

according to § 63.9(h)(2)(ii). You can 

submit this information in an operating 


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permit application, in an amendment to 

an operating permit application, in a 

separate submission, or in any 

combination. In a State with an 

approved operating permit program 

where delegation of authority under 

section 112(l) of the CAA has not been 

requested or approved, you must 

provide a duplicate notification to the 

applicable Regional Administrator. If 

the required information has been 

submitted previously, you do not have 

to provide a separate notification of 

compliance status. Just refer to the 

earlier submissions instead of 

duplicating and resubmitting the 

previously submitted information. 

* * * * * 

■ 49. Section 63.1575 is amended by: 

■ a. Revising paragraphs (d) 

introductory text, (d)(1) and (2); 

■ b. Adding paragraph (d)(4); 

■ c. Revising paragraph (e) introductory 

text; 

■ d. Removing and reserving paragraph 

(e)(1); 

■ e. Revising paragraphs (e)(4) and 

(e)(6); 

■ f. Revising paragraphs (f)(1) and (2); 

■ g. Removing and reserving paragraph 

(h); and 

■ h. Adding paragraph (k). 

The revisions and additions read as 

follows: 

§ 63.1575 What reports must I submit and 

when? 

* * * * * 

(d) For each deviation from an 

emission limitation and for each 

deviation from the requirements for 

work practice standards that occurs at 

an affected source where you are not 

using a continuous opacity monitoring 

system or a continuous emission 

monitoring system to comply with the 

emission limitation or work practice 

standard in this subpart, the semiannual 

compliance report must contain the 

information in paragraphs (c)(1) through 

(3) of this section and the information 

in paragraphs (d)(1) through (4) of this 

section. 

(1) The total operating time of each 

affected source during the reporting 

period and identification of the sources 

for which there was a deviation. 

(2) Information on the number, date, 

time, duration, and cause of deviations 

(including unknown cause, if 

applicable). 

* * * * * 

(4) The applicable operating limit or 

work practice standard from which you 

deviated and either the parameter 

monitor reading during the deviation or 

a description of how you deviated from 

the work practice standard. 

(e) For each deviation from an 

emission limitation occurring at an 

affected source where you are using a 

continuous opacity monitoring system 

or a continuous emission monitoring 

system to comply with the emission 

limitation, you must include the 

information in paragraphs (c)(1) through 

(3) of this section, in paragraphs (d)(1) 

through (3) of this section, and in 

paragraphs (e)(2) through (13) of this 

section. 

(1) [Reserved] 

* * * * * 

(4) An estimate of the quantity of each 

regulated pollutant emitted over the 

emission limit during the deviation, and 

a description of the method used to 

estimate the emissions. 

* * * * * 

(6) A breakdown of the total duration 

of the deviations during the reporting 

period and into those that are due to 

control equipment problems, process 

problems, other known causes, and 

other unknown causes. 

* * * * * 

(f) * * * 

(1) You must include the information 

in paragraph (c)(1)(i) or (c)(1)(ii) of this 

section, if applicable. 

(i) If you are complying with 

paragraph (k)(1) of this section, a 

summary of the results of any 

performance test done during the 

reporting period on any affected unit. 

Results of the performance test include 

the identification of the source tested, 

the date of the test, the percentage of 

emissions reduction or outlet pollutant 

concentration reduction (whichever is 

needed to determine compliance) for 

each run and for the average of all runs, 

and the values of the monitored 

operating parameters. 

(ii) If you are not complying with 

paragraph (k)(1) of this section, a copy 

of any performance test done during the 

reporting period on any affected unit. 

The report may be included in the next 

semiannual compliance report. The 

copy must include a complete report for 

each test method used for a particular 

kind of emission point tested. For 

additional tests performed for a similar 

emission point using the same method, 

you must submit the results and any 

other information required, but a 

complete test report is not required. A 

complete test report contains a brief 

process description; a simplified flow 

diagram showing affected processes, 

control equipment, and sampling point 

locations; sampling site data; 

description of sampling and analysis 

procedures and any modifications to 

standard procedures; quality assurance 

procedures; record of operating 

conditions during the test; record of 

preparation of standards; record of 

calibrations; raw data sheets for field 

sampling; raw data sheets for field and 

laboratory analyses; documentation of 

calculations; and any other information 

required by the test method. 

(2) Any requested change in the 

applicability of an emission standard 

(e.g., you want to change from the PM 

standard to the Ni standard for catalytic 

cracking units or from the HCl 

concentration standard to percent 

reduction for catalytic reforming units) 

in your compliance report. You must 

include all information and data 

necessary to demonstrate compliance 

with the new emission standard 

selected and any other associated 

requirements. 

* * * * * 

(k) Electronic submittal of 

performance test and CEMS 

performance evaluation data. On and 

after [THE DATE 3 YEARS AFTER 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], if required to 

submit the results of a performance test 

or CEMS performance evaluation, you 

must submit the results using EPA’s 

Electronic Reporting Tool (ERT) 

according to the procedures in 

paragraphs (k)(1) and (2) of this section. 

(1) Within 60 days after the date of 

completing each performance test as 

required by this subpart, you must 

submit the results of the performance 

tests according to the method specified 

by either paragraph (k)(1)(i) or (k)(1)(ii) 

of this section. 

(i) For data collected using test 

methods supported by the EPA’s ERT as 

listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/

index.html), you must submit the results 

of the performance test to the 

Compliance and Emissions Data 

Reporting Interface (CEDRI) accessed 

through the EPA’s Central Data 

Exchange (CDX) (http://cdx.epa.gov/

epa_home.asp), unless the 

Administrator approves another 

approach. Performance test data must be 

submitted in a file format generated 

through use of the EPA’s ERT. If you 

claim that some of the performance test 

information being submitted is 

confidential business information (CBI), 

you must submit a complete file 

generated through the use of the EPA’s 

ERT, including information claimed to 

be CBI, on a compact disc or other 

commonly used electronic storage 

media (including, but not limited to, 

flash drives) by registered letter to the 

EPA. The electronic media must be 

clearly marked as CBI and mailed to 


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U.S. EPA/OAQPS/CORE CBI Office, 

Attention: WebFIRE Administrator, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same ERT file with the 

CBI omitted must be submitted to the 

EPA via CDX as described earlier in this 

paragraph. 

(ii) For data collected using test 

methods that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT 

Web site, you must submit the results of 

the performance test to the 

Administrator at the appropriate 

address listed in § 63.13. 

(2) Within 60 days after the date of 

completing each CEMS performance 

evaluation test required by § 63.1571(a) 

and (b), you must submit the results of 

the performance evaluation according to 

the method specified by either 

paragraph (k)(2)(i) or (k)(2)(ii) of this 

section. 

(i) For data collection of relative 

accuracy test audit (RATA) pollutants 

that are supported by the EPA’s ERT as 

listed on the ERT Web site, the owner 

or operator must submit the results of 

the performance evaluation to the 

CEDRI that is accessed through the 

EPA’s CDX, unless the Administrator 

approves another approach. 

Performance evaluation data must be 

submitted in a file format generated 

through the use of the EPA’s ERT. If an 

owner or operator claims that some of 

the performance evaluation information 

being submitted is CBI, the owner or 

operator must submit a complete file 

generated through the use of the EPA’s 

ERT, including information claimed to 

be CBI, on a compact disc or other 

commonly used electronic storage 

media (including, but not limited to, 

flash drives) by registered letter to the 

EPA. The electronic media must be 

clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, 

Attention: WebFIRE Administrator, MD 

C404–02, 4930 Old Page Rd., Durham, 

NC 27703. The same ERT file with the 

CBI omitted must be submitted to the 

EPA via CDX as described earlier in this 

paragraph. 

(ii) For any performance evaluation 

data with RATA pollutants that are not 

supported by the EPA’s ERT as listed on 

the EPA’s ERT Web site, you must 

submit the results of the performance 

evaluation to the Administrator at the 

appropriate address listed in § 63.13. 

■ 50. Section 63.1576 is amended by: 

■ a. Revising paragraph (a)(2); 

■ b. Revising paragraphs (b)(3) and (5). 

The revisions read as follows: 

§ 63.1576 What records must I keep, in 

what form, and for how long? 

(a) * * * 

(2) The records specified in 

paragraphs (a)(2)(i) through (iv) of this 

section. 

(i) Record the date, time, and duration 

of each startup and/or shutdown period, 

recording the periods when the affected 

source was subject to the standard 

applicable to startup and shutdown. 

(ii) In the event that an affected unit 

fails to meet an applicable standard, 

record the number of failures. For each 

failure record the date, time and 

duration of each failure. 

(iii) For each failure to meet an 

applicable standard, record and retain a 

list of the affected sources or equipment, 

an estimate of the volume of each 

regulated pollutant emitted over any 

emission limit and a description of the 

method used to estimate the emissions. 

(iv) Record actions taken to minimize 

emissions in accordance with 

§ 63.1570(c) and any corrective actions 

taken to return the affected unit to its 

normal or usual manner of operation. 

* * * * * 

(b) * * * 

(3) The performance evaluation plan 

as described in § 63.8(d)(2) for the life 

of the affected source or until the 

affected source is no longer subject to 

the provisions of this part, to be made 

available for inspection, upon request, 

by the Administrator. If the performance 

evaluation plan is revised, you must 

keep previous (i.e., superseded) versions 

of the performance evaluation plan on 

record to be made available for 

inspection, upon request, by the 

Administrator, for a period of 5 years 

after each revision to the plan. The 

program of corrective action should be 

included in the plan required under 

§ 63.8(d)(2). 

* * * * * 

(5) Records of the date and time that 

each deviation started and stopped. 

* * * * * 

■ 51. Section 63.1579 is amended by: 

■ a. Revising section introductory text 

and 

■ b. Revising the definitions of 

‘‘Deviation,’’ and ‘‘PM.’’ 

The revisions read as follows: 

§ 63.1579 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act (CAA), in 

40 CFR 63.2, the General Provisions of 

this part (§§ 63.1 through 63.15), and in 

this section as listed. If the same term 

is defined in subpart A and in this 

section, it shall have the meaning given 

in this section for purposes of this 

subpart. 

* * * * * 

Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(1) Fails to meet any requirement or 

obligation established by this subpart, 

including but not limited to any 

emission limit, operating limit, or work 

practice standard; or 

(2) Fails to meet any term or condition 

that is adopted to implement an 

applicable requirement in this subpart 

and that is included in the operating 

permit for any affected source required 

to obtain such a permit. 

* * * * * 

PM means, for the purposes of this 

subpart, emissions of particulate matter 

that serve as a surrogate measure of the 

total emissions of particulate matter and 

metal HAP contained in the particulate 

matter, including but not limited to: 

antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, 

nickel, and selenium as measured by 

Methods 5, 5B or 5F in Appendix A–3 

to part 60 of this chapter or by an 

approved alternative method. 

* * * * * 

■ 52. Table 1 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(a)(1), you shall 

meet each emission limitation in the 

following table that applies to you. 


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TABLE 1 TO SUBPART UUU OF PART 63—METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS

For each new or existing catalytic cracking unit . . . You shall meet the following emission limits for each catalyst regenerator vent . . . 

1. Subject to new source performance standard (NSPS) for PM in 40 

CFR 60.102.

PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/

1,000 lb) of coke burn-off. Before [THE DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], if the discharged gases 

pass through an incinerator or waste heat boiler in which you burn 

auxiliary or in supplemental liquid or solid fossil fuel, the incremental 

rate of PM emissions must not exceed 43.0 grams per Gigajoule (g/

GJ) or 0.10 pounds per million British thermal units (lb/million Btu) of 

heat input attributable to the liquid or solid fossil fuel; and the opacity 

of emissions must not exceed 30 percent, except for one 6-minute 

average opacity reading in any 1-hour period. 

2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i) .......................... PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke 

burn-off or, if a PM CEMS is used, 0.040 grain per dry standard 

cubic feet (gr/dscf) corrected to 0 percent excess air. 

3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) .......................... PM emissions must not exceed 0.5 g/kg coke burn-off (0.5 lb/1000 lb 

coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 

percent excess air. 

4. Option 1: PM per coke burn-off limit, not subject to the NSPS for PM 

in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1).

PM emissions must not exceed the limits specified in Item 1 of this 

table. 

5. Option 2: PM concentration limit, not subject to the NSPS for PM in 

40 CFR 60.102 or in 40 CFR 60.102a(b)(1).

PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent 

excess air. 

6. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 

60.102 or in 40 CFR 60.102a(b)(1).

Nickel (Ni) emissions must not exceed 13,000 milligrams per hour (mg/

hr) (0.029 lb/hr). 

7. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM 

in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1).

Ni emissions must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) of coke 

burn-off in the catalyst regenerator. 

■ 53. Table 2 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(a)(2), you shall 

meet each operating limit in the 

following table that applies to you. 

TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

1. Subject to the NSPS for PM in 

40 CFR 60.102.

a. Continuous opacity monitoring 

system used to comply with the 

30 percent opacity limit in 40 

CFR 60.102 before [THE DATE 

18 MONTHS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER].

Not applicable ............................... Not applicable. 

b. Continuous opacity monitoring 

system used to comply with a 

site-specific opacity limit.

Cyclone, fabric filter, or electrostatic precipitator.Maintain the 3-hour rolling average opacity of emissions from 

your catalyst regenerator vent 

no higher than the site-specific 

opacity limit established during 

the performance test. 

c. Continuous parameter monitoring systems.Electrostatic precipitator ............... Maintain the daily average coke 

burn-off rate or daily average 

flow rate no higher than the 

limit established in the performance test; and maintain the 3- 

hour rolling average total power 

and secondary current above 

the limit established in the performance test. 

d. Continuous parameter monitoring systems.Wet scrubber ................................ Maintain the 3-hour rolling average pressure drop above the 

limit established in the performance test; and maintain the 3- 

hour rolling average liquid-togas ratio above the limit established in the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

e. Bag leak detection (BLD) system.Fabric filter .................................... Maintain particulate loading below 

the BLD alarm set point established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i).

a. PM CEMS ................................. Not applicable ............................... Not applicable. 

b. Continuous opacity monitoring 

system used to comply with a 

site-specific opacity limit.

Cyclone or electrostatic precipitator.Maintain the 3-hour rolling average opacity of emissions from 

your catalyst regenerator vent 

no higher than the site-specific 

opacity limit established during 

the performance test. 

c. Continuous parameter monitoring systems.Electrostatic precipitator ............... Maintain the daily average coke 

burn-off rate or daily average 

flow rate no higher than the 

limit established in the performance test; and maintain the 3- 

hour rolling average total power 

and secondary current above 

the limit established in the performance test. 

d. Continuous parameter monitoring systems.Wet scrubber ................................ Maintain the 3-hour rolling average pressure drop above the 

limit established in the performance test; and maintain the 3- 

hour rolling average liquid-togas ratio above the limit established in the performance test. 

e. Bag leak detection (BLD) system.Fabric filter .................................... Maintain particulate loading below 

the BLD alarm set point established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii).

Any ................................................ Any ................................................ The applicable operating limits in 

Item 2 of this table. 

4. Option 1: PM per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102 or 40 

CFR 60.102a(b)(1).

a. Continuous opacity monitoring 

system used to comply with a 

site-specific opacity limit.

Cyclone, fabric filter, or electrostatic precipitator.Maintain the 3-hour rolling average opacity of emissions from 

your catalyst regenerator vent 

no higher than the site-specific 

opacity limit established during 

the performance test. Alternatively, before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

you may maintain the hourly 

average opacity of emissions 

from your catalyst generator 

vent no higher than the sitespecific opacity limit established 

during the performance test. 

b. Continuous parameter monitoring systems.i. Electrostatic precipitator ............ (1) Maintain the daily average gas 

flow rate or daily average coke 

burn-off rate no higher than the 

limit established in the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37004 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

(2) Maintain the 3-hour rolling average total power and secondary current above the limit 

established in the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may maintain 

the daily average voltage and 

secondary current (or total 

power input) above the limit established in the performance 

test. 

ii. Wet scrubber ............................ (1) Maintain the 3-hour rolling average pressure drop above the 

limit established in the performance test. Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

maintain the daily average 

pressure drop above the limit 

established in the performance 

test (not applicable to a wet 

scrubber of the non-venturi jetejector design). 

(2) Maintain the 3-hour rolling average liquid-to-gas ratio above 

the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

maintain the daily average liquid-to-gas ratio above the limit 

established in the performance 

test. 

c. Bag leak detection (BLD) system.Fabric filter .................................... Maintain particulate loading below 

the BLD alarm set point established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

5. Option 2: PM concentration limit 

not subject to the NSPS for PM 

in 40 CFR 60.102 or 40 CFR 

60.102a(b)(1).

PM CEMS ..................................... Any ................................................ Not applicable. 

6. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 

CFR 60.102.

a. Continuous opacity monitoring 

system.

Cyclone, fabric filter, or electrostatic precipitator.Maintain the 3-hour rolling average Ni operating value no higher than the limit established 

during the performance test. Alternatively, before [THE DATE 

18 MONTHS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may maintain 

the daily average Ni operating 

value no higher than the limit 

established during the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37005 

TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

b. Continuous parameter monitoring systems.i. Electrostatic precipitator ............ (1) Maintain the daily average gas 

flow rate or daily average coke 

burn-off rate no higher than the 

limit established during the performance test. 

(2) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(3) Maintain the 3-hour rolling average total power and secondary current above the limit 

established in the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may maintain 

the daily average voltage and 

secondary current (or total 

power input) above the established during the performance 

test. 

ii. Wet scrubber ............................ (1) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(2) Maintain the 3-hour rolling average pressure drop above the 

limit established in the performance test. Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

maintain the daily average 

pressure drop above the limit 

established during the performance test (not applicable to a 

non-venturi wet scrubber of the 

jet-ejector design). 

(3) Maintain the 3-hour rolling average liquid-to-gas ratio above 

the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

maintain the daily average liquid-to-gas ratio above the limit 

established during the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37006 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

7. Option 4: Ni per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102.

a. Continuous opacity monitoring 

system.

Cyclone, baghouse, or electrostatic precipitator.Maintain the 3-hour rolling average Ni operating value no higher than Ni operating limit established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may elect to 

maintain the daily average Ni 

operating value no higher than 

the Ni operating limit established during the performance 

test. 

b. Continuous parameter monitoring systems.i. Electrostatic precipitator ............ (1) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(2) Maintain the 3-hour rolling average total power and secondary current above the limit 

established in the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may maintain 

the daily average voltage and 

secondary current (or total 

power input) above the limit established during the performance test. 

ii. Wet scrubber ............................ (1) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(2) Maintain the 3-hour rolling average pressure drop above the 

limit established in the performance test. Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

maintain the daily average 

pressure drop above the limit 

established during the performance test (not applicable to a 

non-venturi wet scrubber of the 

jet-ejector design). 

(3) Maintain the 3-hour rolling average liquid-to-gas ratio above 

the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

maintain the daily average liquid-to-gas ratio above the limit 

established during the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37007 

■ 54. Table 3 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(b)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS

For each new or existing catalytic cracking 

unit . . . 

If you use this type of control device 

for your vent . . . You shall install, operate, and maintain a . . . 

1. Subject to the NSPS for PM in 40 CFR 

60.102.

a. Cyclone ......................................... Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent. 

b. Electrostatic precipitator ................ Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent; or continuous parameter monitoring 

systems to measure and record the coke burn-off 

rate or the gas flow rate entering or exiting the control device 1 and the total power and secondary current to the control device. 

c. Wet scrubber ................................. Continuous parameter monitoring system to measure 

and record the pressure drop across the scrubber,2

coke burn-off rate or the gas flow rate entering or 

exiting the control device,1 and total liquid (or scrubbing liquor) flow rate to the control device. Alternatively, before [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent. 

d. Fabric Filter ................................... Continuous bag leak detection system to measure and 

record increases in relative particulate loading from 

each catalyst regenerator vent or a continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator 

vent. 

2. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(i) electing to meet the PM per 

coke burn-off limit.

a. Cyclone ......................................... Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent. 

b. Electrostatic precipitator ................ Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent; or continuous parameter monitoring 

systems to measure and record the coke burn-off 

rate or the gas flow rate entering or exiting the control device,1 the voltage, current, and secondary current to the control device. 

c. Wet scrubber ................................. Continuous parameter monitoring system to measure 

and record the pressure drop across the scrubber,2

the coke burn-off rate or the gas flow rate entering or 

exiting the control device,1 and total liquid (or scrubbing liquor) flow rate to the control device. 

d. Fabric Filter ................................... Continuous bag leak detection system to measure and 

record increases in relative particulate loading from 

each catalyst regenerator vent. 

3. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(i) electing to meet the PM 

concentration limit.

Any .................................................... Continuous emission monitoring system to measure 

and record the concentration of PM and oxygen from 

each catalyst regenerator vent. 

4. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(ii) electing to meet the PM per 

coke burn-off limit.

Any .................................................... See item 2 of this table. 

5. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(ii) electing to meet the PM 

concentration limit.

Any .................................................... See item 3 of this table. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37008 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic cracking 

unit . . . 

If you use this type of control device 

for your vent . . . You shall install, operate, and maintain a . . . 

6. Option 1: PM per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 

or 40 CFR 60.120a(b)(1).

Any .................................................... See item 1 of this table. 

7. Option 2: PM concentration limit not subject 

to the NSPS for PM in 40 CFR 60.102 or 40 

CFR 60.120a(b)(1).

Any .................................................... See item 3 of this table. 

8. Option 3: Ni lb/hr limit not subject to the 

NSPS for PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1).

a. Cyclone ......................................... Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring 

system to measure and record the coke burn-off rate 

or the gas flow rate entering or exiting the control device.1

b. Electrostatic precipitator ................ Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring 

system to measure and record the coke burn-off rate 

or the gas flow rate entering or exiting the control device;1 or continuous parameter monitoring systems to 

measure and record the coke burn-off rate or the gas 

flow rate entering or exiting the control device 1 and 

the voltage and current [to measure the total power 

to the system] and secondary current to the control 

device. 

c. Wet scrubber ................................. Continuous parameter monitoring system to measure 

and record the pressure drop across the scrubber,2

gas flow rate entering or exiting the control device,1

and total liquid (or scrubbing liquor) flow rate to the 

control device. 

d. Fabric Filter ................................... Continuous bag leak detection system to measure and 

record increases in relative particulate loading from 

each catalyst regenerator vent or the monitoring systems specified in item 8.a of this table. 

9. Option 4: Ni lb/1,000 lbs of coke burn-off 

limit not subject to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 60.102a(b)(1).

a. Cyclone ......................................... Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring 

system to measure and record the gas flow rate entering or exiting the control device.1

b. Electrostatic precipitator ................ Continuous opacity monitoring system to measure and 

record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring 

system to measure and record the coke burn-off rate 

or the gas flow rate entering or exiting the control device;1 or continuous parameter monitoring systems to 

measure and record the coke burn-off rate or the gas 

flow rate entering or exiting the control device 1 and 

voltage and current [to measure the total power to 

the system] and secondary current to the control device. 

c. Wet scrubber ................................. Continuous parameter monitoring system to measure 

and record the pressure drop across the scrubber,2

gas flow rate entering or exiting the control device,1

and total liquid (or scrubbing liquor) flow rate to the 

control device. 

d. Fabric Filter ................................... Continuous bag leak detection system to measure and 

record increases in relative particulate loading from 

each catalyst regenerator vent or the monitoring systems specified in item 9.a of this table. 

1 If applicable, you can use the alternative in § 63.1573(a)(1) instead of a continuous parameter monitoring system for gas flow rate. 2 If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in 

§ 63.1573(b) instead of a continuous parameter monitoring system for pressure drop across the scrubber. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37009 

■ 55. Table 4 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(b)(2), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM) 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

1. Any ............................................. a. Select sampling port’s location 

and the number of traverse 

ports.

Method 1 or 1A in Appendix A–1 

to part 60 of this chapter.

Sampling sites must be located at 

the outlet of the control device 

or the outlet of the regenerator, 

as applicable, and prior to any 

releases to the atmosphere. 

b. Determine velocity and volumetric flow rate.Method 2, 2A, 2C, 2D, 2F in Appendix A–1 to part 60 of this 

chapter, or 2G in Appendix A–2 

to part 60 of this chapter, as 

applicable.

c. Conduct gas molecular weight 

analysis.

Method 3, 3A, or 3B in Appendix 

A–2 to part 60 of this chapter, 

as applicable.

d. Measure moisture content of 

the stack gas.

Method 4 in Appendix A–3 to part 

60 of this chapter.

e. If you use an electrostatic precipitator, record the total number of fields in the control system and how many operated 

during the applicable performance test.

f. If you use a wet scrubber, 

record the total amount (rate) of 

water (or scrubbing liquid) and 

the amount (rate) of make-up 

liquid to the scrubber during 

each test run.

2. Option 1: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1).

a. Measure PM emissions ............ Method 5, 5B, or 5F (40 CFR part 

60, Appendix A–3) to determine 

PM emissions and associated 

moisture content for units without wet scrubbers. Method 5 or 

5B (40 CFR part 60, Appendix 

A–3) to determine PM emissions and associated moisture 

content for unit with wet scrubber.

You must maintain a sampling 

rate of at least 0.15 dry standard cubic meters per minute 

(dscm/min) (0.53 dry standard 

cubic feet per minute (dscf/

min). 

b. Compute coke burn-off rate 

and PM emission rate (lb/1,000 

lb of coke burn-off).

Equations 1, 2, and 3 of 

§ 63.1564 (if applicable).

c. Measure opacity of emissions .. Continuous opacity monitoring 

system.

You must collect opacity monitoring data every 10 seconds 

during the entire period of the 

Method 5, 5B, or 5F performance test and reduce the data 

to 6-minute averages. 

3. Option 2: PM concentration 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1).

a. Measure PM concentration ...... Method 5, 5B, or 5F (40 CFR part 

60, Appendix A–3) to determine 

PM concentration and associated moisture content for units 

without wet scrubbers Method 5 

or 5B (40 CFR part 60, Appendix A–3) to determine PM concentration and associated moisture content for unit with wet 

scrubber.

You must maintain a sampling 

rate of at least 0.15 dry standard cubic meters per minute 

(dscm/min) (0.53 dry standard 

cubic feet per minute (dscf/

min). 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37010 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

4. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

60.102a(b)(1).

a. Measure concentration of Ni .... Method 29 (40 CFR part 60, Appendix A–8).

b. Compute Ni emission rate (lb/

hr).

Equation 5 of § 63.1564.

c. Determine the equilibrium catalyst Ni concentration.XRF procedure in Appendix A to 

this subpart; 1 or EPA Method 

6010B or 6020 or EPA Method 

7520 or 7521 in SW–846; 2 or 

an alternative to the SW–846 

method satisfactory to the Administrator.

You must obtain 1 sample for 

each of the 3 runs; determine 

and record the equilibrium catalyst Ni concentration for each of 

the 3 samples; and you may 

adjust the laboratory results to 

the maximum value using 

Equation 2 of § 63.1571. 

d. If you use a continuous opacity 

monitoring system, establish 

your site-specific Ni operating 

limit.

i. Equations 6 and 7 of § 63.1564 

using data from continuous 

opacity monitoring system, gas 

flow rate, results of equilibrium 

catalyst Ni concentration analysis, and Ni emission rate from 

Method 29 test.

(1) You must collect opacity monitoring data every 10 seconds 

during the entire period of the 

initial Ni performance test; reduce the data to 6-minute averages; and determine and record 

the hourly average opacity from 

all the 6-minute averages. 

(2) You must collect gas flow rate 

monitoring data every 15 minutes during the entire period of 

the initial Ni performance test; 

measure the gas flow as near 

as practical to the continuous 

opacity monitoring system; and 

determine and record the hourly 

average actual gas flow rate 

from all the readings. 

5. Option 4: Ni per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1).

a. Measure concentration of Ni .... Method 29 (40 CFR part 60, Appendix A–8).

b. Compute Ni emission rate (lb/

1,000 lb of coke burn-off).

Equations 1 and 8 of § 63.1564.

c. Determine the equilibrium catalyst Ni concentration.See item 4.c. of this table ............ You must obtain 1 sample for 

each of the 3 runs; determine 

and record the equilibrium catalyst Ni concentration for each of 

the 3 samples; and you may 

adjust the laboratory results to 

the maximum value using 

Equation 2 of § 63.1571. 

d. If you use a continuous opacity 

monitoring system, establish 

your site-specific Ni operating 

limit.

i. Equations 9 and 10 of 

§ 63.1564 with data from continuous opacity monitoring system, coke burn-off rate, results 

of equilibrium catalyst Ni concentration analysis, and Ni 

emission rate from Method 29 

test.

(1) You must collect opacity monitoring data every 10 seconds 

during the entire period of the 

initial Ni performance test; reduce the data to 6-minute averages; and determine and record 

the hourly average opacity from 

all the 6-minute averages. 

(2) You must collect gas flow rate 

monitoring data every 15 minutes during the entire period of 

the initial Ni performance test; 

measure the gas flow rate as 

near as practical to the continuous opacity monitoring system; and determine and record 

the hourly average actual gas 

flow rate from all the readings. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37011 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

e. Record the catalyst addition 

rate for each test and schedule 

for the 10-day period prior to 

the test.

6. If you elect Option 1 in item 4 in 

Table 1, Option 3 in item 6 in 

Table 1, or Option 4 in item 7 in 

Table 1 of this subpart and you 

use continuous parameter monitoring systems.

a. Establish each operating limit in 

Table 2 of this subpart that applies to you.

Data from the continuous parameter monitoring systems and 

applicable performance test 

methods.

b. Electrostatic precipitator or wet 

scrubber: gas flow rate.

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect gas flow rate 

monitoring data every 15 minutes during the entire period of 

the initial performance test. 

(2) You must determine and 

record the 3-hr average gas 

flow rate from all the readings. 

Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may determine and record the maximum 

hourly average gas flow rate 

from all the readings. 

c. Electrostatic precipitator: voltage and secondary current (or 

total power input).

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect voltage, current, and secondary current 

monitoring data every 15 minutes during the entire period of 

the performance test. Alternatively, before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

you may collect voltage and 

secondary current (or total 

power input) monitoring data 

every 15 minutes during the entire period of the initial performance test. 

(2) You must determine and 

record the 3-hr average total 

power to the system and the 3- 

hr average secondary current. 

Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may determine and record the minimum 

hourly average voltage and 

secondary current (or total 

power input) from all the readings. 

d. Electrostatic precipitator or wet 

scrubber: equilibrium catalyst Ni 

concentration.

Results of analysis for equilibrium 

catalyst Ni concentration.

You must determine and record 

the average equilibrium catalyst 

Ni concentration for the 3 runs 

based on the laboratory results. 

You may adjust the value using 

Equation 1 or 2 of § 63.1571 as 

applicable. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37012 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

e. Wet scrubber: pressure drop 

(not applicable to non-venturi 

scrubber of jet ejector design).

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect pressure 

drop monitoring data every 15 

minutes during the entire period 

of the initial performance test. 

(2) You must determine and 

record the 3-hr average pressure drop from all the readings. 

Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you may determine and record the minimum 

hourly average pressure drop 

from all the readings. 

f. Wet scrubber: liquid-to-gas ratio i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect gas flow rate 

and total water (or scrubbing 

liquid) flow rate monitoring data 

every 15 minutes during the entire period of the initial performance test. 

(2) You must determine and 

record the hourly average liquid-to-gas ratio from all the 

readings. Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

determine and record the hourly 

average gas flow rate and total 

water (or scrubbing liquid) flow 

rate from all the readings. 

(3) You must determine and 

record the 3-hr average liquidto-gas ratio. Alternatively, before [THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you may 

determine and record the minimum liquid-to-gas ratio. 

g. Alternative procedure for gas 

flow rate.

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect air flow rate 

monitoring data or determine 

the air flow rate using control 

room instrumentation every 15 

minutes during the entire period 

of the initial performance test. 

(2) You must determine and 

record the 3-hr average rate of 

all the readings. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

you may determine and record 

the hourly average rate of all 

the readings. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37013 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

(3) You must determine and 

record the maximum gas flow 

rate using Equation 1 of 

§ 63.1573. 

1 Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure). 

2EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, and EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration are 

included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW– 

846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government 

Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, 

Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air 

Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 

700, Washington, DC. 

■ 56. Table 5 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(b)(5), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS

For each new and existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

For the following emission limit . . . You have demonstrated initial compliance if . . . 

1. Subject to the NSPS for PM in 40 

CFR 60.102.

PM emissions must not exceed 1.0 gram per 

kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff. Before [THE DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], if the discharged gases pass 

through an incinerator or waste heat boiler in 

which you burn auxiliary or supplemental liquid 

or solid fossil fuel, the incremental rate of PM 

must not exceed 43.0 grams per Gigajoule (g/

GJ) or 0.10 pounds per million British thermal 

units (lb/million Btu) of heat input attributable to 

the liquid or solid fossil fuel; and the opacity of 

emissions must not exceed 30 percent, except 

for one 6-minute average opacity reading in 

any 1-hour period.

You have already conducted a performance test 

to demonstrate initial compliance with the 

NSPS and the measured PM emission rate is 

less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) 

of coke burn-off in the catalyst regenerator. As 

part of the Notification of Compliance Status, 

you must certify that your vent meets the PM 

limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your BLD; CO2, 

O2, or CO monitor; or continuous opacity monitoring system meets the requirements in 

§ 63.1572. 

2. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(i), electing to meet the 

PM per coke burn-off limit.

PM emissions must not exceed 0.5 g/kg (0.5 lb 

PM/1,000 lb) of coke burn-off or, 

You have already conducted a performance test 

to demonstrate initial compliance with the 

NSPS and the measured PM emission rate is 

less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) 

of coke burn-off in the catalyst regenerator. As 

part of the Notification of Compliance Status, 

you must certify that your vent meets the PM 

limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your BLD; CO2, 

O2, or CO monitor; or continuous opacity monitoring system meets the requirements in 

§ 63.1572. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37014 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

For the following emission limit . . . You have demonstrated initial compliance if . . . 

3. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(ii), electing to meet the 

PM per coke burn-off limit.

PM emissions must not exceed 1.0 g/kg coke 

burn-off (1 lb/1000 lb coke burn-off).

You have already conducted a performance test 

to demonstrate initial compliance with the 

NSPS and the measured PM emission rate is 

less than or equal to 0.5 kg/1,000 kg (0.5 lb/

1,000 lb) of coke burn-off in the catalyst regenerator. As part of the Notification of Compliance Status, you must certify that your vent 

meets the PM limit. You are not required to do 

another performance test to demonstrate initial 

compliance. As part of your Notification of 

Compliance Status, you certify that your BLD; 

CO2, O2, or CO monitor; or continuous opacity 

monitoring system meets the requirements in 

§ 63.1572. 

4. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(i), electing to meet the 

PM concentration limit.

If a PM CEMS is used, 0.020 grain per dry 

standard cubic feet (gr/dscf) corrected to 0 percent excess air.

You have already conducted a performance test 

to demonstrate initial compliance with the 

NSPS and the measured PM concentration is 

less than or equal to 0.020 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent 

excess air. As part of the Notification of Compliance Status, you must certify that your vent 

meets the PM limit. You are not required to do 

another performance test to demonstrate initial 

compliance. As part of your Notification of 

Compliance Status, you certify that your PM 

CEMS meets the requirements in § 63.1572. 

5. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(ii), electing to meet the 

PM concentration limit.

If a PM CEMS is used, 0.040 gr/dscf corrected to 

0 percent excess air.

You have already conducted a performance test 

to demonstrate initial compliance with the 

NSPS and the measured PM concentration is 

less than or equal to 0.040 gr/dscf corrected to 

0 percent excess air. As part of the Notification 

of Compliance Status, you must certify that 

your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that 

your PM CEMS meets the requirements in 

§ 63.1572. 

6. Option 1: PM per coke burn-off limit 

not subject to the NSPS for PM in 40 

CFR 60.102 or 40 CFR 60.120a(b)(1).

PM emissions must not exceed 1.0 gram per 

kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff. Before [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], PM emission must not exceed 1.0 

g/kg (1.0 lb/1,000 lb) of coke burn-off in the 

catalyst regenerator; if the discharged gases 

pass through an incinerator or waste heat boiler in which you burn auxiliary or supplemental 

liquid or solid fossil fuel, the incremental rate of 

PM must not exceed 43.0 g/GJ (0.10 lb/million 

Btu) of heat input attributable to the liquid or 

solid fossil fuel; and the opacity of emissions 

must not exceed 30 percent, except for one 6- 

minute average opacity reading in any 1-hour 

period.

The average PM emission rate, measured using 

EPA Method 5, 5B, or 5F (for a unit without a 

wet scrubber) or 5 or 5B (for a unit with a wet 

scrubber), over the period of the initial performance test, is no higher than 1.0 g/kg coke 

burn-off (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission rate is calculated 

using Equations 1, 2, and 3 of § 63.1564. If 

you use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets 

the applicable requirements in § 63.1572. 

7. Option 2: PM concentration limit, not 

subject to the NSPS for PM in 40 CFR 

60.102 or in 40 CFR 60.102a(b)(1).

PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air.The average PM concentration, measured using 

EPA Method 5, 5B, or 5F (for a unit without a 

wet scrubber) or Method 5 or 5B (for a unit 

with a wet scrubber), over the period of the initial performance test, is less than or equal to 

0.040 gr/dscf corrected to 0 percent excess air. 

Your performance evaluation shows your PM 

CEMS meets the applicable requirements in 

§ 63.1572. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37015 

TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

For the following emission limit . . . You have demonstrated initial compliance if . . . 

8. Option 3: not subject to the NSPS for 

PM.

Nickel (Ni) emissions from your catalyst regenerator vent must not exceed 13,000 mg/hr 

(0.029 lb/hr).

The average Ni emission rate, measured using 

Method 29 over the period of the initial performance test, is not more than 13,000 mg/hr 

(0.029 lb/hr). The Ni emission rate is calculated 

using Equation 5 of § 63.1564; and if you use a 

BLD; CO2, O2, or CO monitor; or continuous 

opacity monitoring system, your performance 

evaluation shows the system meets the applicable requirements in § 63.1572. 

9. Option 4: Ni per coke burn-off limit not 

subject to the NSPS for PM.

Ni emissions from your catalyst regenerator vent 

must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) 

of coke burn-off in the catalyst regenerator.

The average Ni emission rate, measured using 

Method 29 over the period of the initial performance test, is not more than 1.0 mg/kg 

(0.001 lb/1,000 lb) of coke burn-off in the catalyst regenerator. The Ni emission rate is calculated using Equation 8 of § 63.1564; and if 

you use a BLD; CO2, O2, or CO monitor; or 

continuous opacity monitoring system, your 

performance evaluation shows the system 

meets the applicable requirements in 

§ 63.1572. 

■ 57. Table 6 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS

For each new and existing catalytic 

cracking unit . . . 

Subject to this emission limit for your catalyst regenerator vent . . . You shall demonstrate continuous compliance 

by . . . 

1. Subject to the NSPS for PM in 40 

CFR 60.102.

a. PM emissions must not exceed 1.0 gram per 

kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff. Before [THE DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], if the discharged gases pass 

through an incinerator or waste heat boiler in 

which you burn auxiliary or supplemental liquid 

or solid fossil fuel, the incremental rate of PM 

must not exceed 43.0 g/GJ (0.10 lb/million Btu) 

of heat input attributable to the liquid or solid 

fossil fuel; and the opacity of emissions must 

not exceed 30 percent, except for one 6- 

minute average opacity reading in any 1-hour 

period.

i. Determining and recording each day the average coke burn-off rate (thousands of kilograms 

per hour) using Equation 1 in § 63.1564 and 

the hours of operation for each catalyst regenerator. 

ii. Maintaining PM emission rate below 1.0 g/kg 

(1.0 lb/1,000 lb) of coke burn-off. 

iii. Conducting a performance test before [THE 

DATE 18 MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] and 

once every five years thereafter. 

iv. Collecting the applicable continuous parametric monitoring system data according to 

§ 63.1572 and maintaining each rolling 3-hr average above or below (as applicable) the average determined during the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37016 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit . . . 

Subject to this emission limit for your catalyst regenerator vent . . . You shall demonstrate continuous compliance 

by . . . 

v. Collecting the continuous opacity monitoring 

data for each catalyst regenerator vent according to § 63.1572 and maintaining each 6- 

minute average at or below the site-specific 

opacity determined during the performance 

test. Alternatively, before [THE DATE 18 

MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], collecting the 

continuous opacity monitoring data for each 

catalyst regenerator vent according to 

§ 63.1572 and maintaining each 6-minute average at or below 30 percent, except that one 6- 

minute average during a 1-hour period can exceed 30 percent. 

vi. Before [THE DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], if applicable, determining and recording each day the rate of combustion of liquid or solid fossil fuels (liters/hour or kilograms/

hour) and the hours of operation during which 

liquid or solid fossil-fuels are combusted in the 

incinerator-waste heat boiler; if applicable, 

maintaining the incremental rate of PM at or 

below 43 g/GJ (0.10 lb/million Btu) of heat 

input attributable to the solid or liquid fossil 

fuel. 

2. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(i), electing to meet the 

PM per coke burn-off limit..

PM emissions must not exceed 0.5 g/kg (0.5 lb 

PM/1,000 lb) of coke burn-off.

Determining and recording each day the average 

coke burn-off rate (thousands of kilograms per 

hour) using Equation 1 in § 63.1564 and the 

hours of operation for each catalyst regenerator; maintaining PM emission rate below 0.5 

g/kg (0.5 lb PM/1,000 lb) of coke burn-off; conducting a performance test once every year; 

collecting the applicable continuous parametric 

monitoring system data according to § 63.1572 

and maintaining each rolling 3-hr average 

above or below (as applicable) the average determined during the performance test; collecting the continuous opacity monitoring data 

for each regenerator vent according to 

§ 63.1572 and maintaining each 6-minute average at or below the site-specific opacity determined during the performance test. 

3. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(ii), electing to meet the 

PM per coke burn-off limit.

PM emissions must not exceed 1.0 g/kg coke 

burn-off (1 lb/1,000 lb coke burn-off).

Determining and recording each day the average 

coke burn-off rate (thousands of kilograms per 

hour) using Equation 1 in § 63.1564 and the 

hours of operation for each catalyst regenerator; maintaining PM emission rate below 1.0 

g/kg (1.0 lb/1,000 lb) of coke burn-off; conducting a performance test once every year; 

collecting the applicable continuous parametric 

monitoring system data according to § 63.1572 

and maintaining each rolling 3-hr average 

above or below (as applicable) the average determined during the performance test; collecting the continuous opacity monitoring data 

for each regenerator vent according to 

§ 63.1572 and maintaining each 6-minute average at or below the site-specific opacity determined during the performance test. 

4. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(i), electing to meet the 

PM concentration limit.

If a PM CEMS is used, 0.020 grain per dry 

standard cubic feet (gr/dscf) corrected to 0 percent excess air.

Maintaining PM concentration below 0.020 gr/

dscf corrected to 0 percent excess air. 

5. Subject to NSPS for PM in 40 CFR 

60.102a(b)(1)(ii), electing to meet the 

PM concentration limit.

If a PM CEMS is used, 0.040 gr/dscf corrected to 

0 percent excess air.

Maintaining PM concentration below 0.040 gr/

dscf corrected to 0 percent excess air. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37017 

TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit . . . 

Subject to this emission limit for your catalyst regenerator vent . . . You shall demonstrate continuous compliance 

by . . . 

6. Option 1: PM per coke burn-off limit, 

not subject to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

60.102a(b)(1).

See item 1 of this table ......................................... See item 1 of this table. 

7. Option 2: PM concentration limit, not 

subject to the NSPS for PM in 40 CFR 

60.102 or in 40 CFR 60.102a(b)(1).

PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air.See item 5 of this table. 

8. Option 3: Ni lb/hr limit, not subject to 

the NSPS for PM in 40 CFR 60.102 or 

in 40 CFR 60.102a(b)(1).

Ni emissions must not exceed 13,000 mg/hr 

(0.029 lb/hr).

Maintaining Ni emission rate below 13,000 mg/hr 

(0.029 lb/hr); conducting a performance test 

before [THE DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER] and once every five years thereafter; and collecting the applicable continuous 

parametric monitoring system data according 

to § 63.1572 and maintaining each rolling 3-hr 

average above or below (as applicable) the average determined during the performance test. 

9. Option 4: Ni per coke burn-off limit, 

not subject to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

60.102a(b)(1).

Ni emissions must not exceed 1.0 mg/kg (0.001 

lb/1,000 lb) of coke burn-off in the catalyst regenerator.

Determining and recording each day the average 

coke burn-off rate (thousands of kilograms per 

hour) and the hours of operation for each catalyst regenerator by Equation 1 of § 63.1564 

(you can use process data to determine the 

volumetric flow rate); and maintaining Ni emission rate below 1.0 mg/kg (0.001 lb/1,000 lb) of 

coke burn-off in the catalyst regenerator; conducting a performance test before [THE DATE 

18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] and 

once every five years thereafter; and collecting 

the applicable continuous parametric monitoring system data according to § 63.1572 and 

maintaining each rolling 3-hr average above or 

below (as applicable) the average determined 

during the performance test. 

■ 58. Table 7 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

1. Subject to NSPS for PM in 40 

CFR 60.102.

a. Continuous opacity monitoring 

system used to comply with 30 

percent opacity limit..

Not applicable ............................... Complying with Table 6 of this 

subpart. 

b. Continuous parametric monitoring systems—electrostatic 

precipitator.

The average gas flow rate entering or exiting the control device 

must not exceed the operating 

limit established during the performance test..

Collecting the hourly and 3-hr rolling average gas flow rate monitoring data according to 

§ 63.1572; and maintaining the 

3-hr rolling average gas flow 

rate at or below the limit established during the performance 

test. 

The average total power and secondary current to the control 

device must not fall below the 

operating limit established during the performance test.

Collecting the hourly and 3-hr rolling average total power and 

secondary current monitoring 

data according to § 63.1572; 

and maintaining the 3-hr rolling 

average total power and secondary current at or above the 

limit established during the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37018 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

c. Continuous parametric monitoring systems—wet scrubber.The average pressure drop 

across the scrubber must not 

fall below the operating limit established during the performance test.

Collecting the hourly and 3-hr rolling average pressure drop 

monitoring data according to 

§ 63.1572; and maintaining the 

3-hr rolling average pressure 

drop at or above the limit established during the performance 

test. 

The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test.

Collecting the hourly and 3-hr rolling average gas flow rate and 

scrubber liquid flow rate monitoring data according to 

§ 63.1572; determining and recording the 3-hr liquid-to-gas 

ratio; and maintaining the 3-hr 

rolling average liquid-to-gas 

ratio at or above the limit established during the performance 

test. 

d. BLD—fabric filter ...................... Increases in relative particulate .... Collecting and maintaining 

records of BLD system output; 

determining the cause of the 

alarm within 1 hour of the 

alarm; and alleviating the cause 

of the alarm within 3 hours by 

corrective action. 

e. Continuous opacity monitoring 

system, used for site-specific 

opacity limit—Cyclone or electrostatic precipitator.

The average opacity must not exceed the opacity established 

during the performance test.

Collecting the hourly and 3-hr rolling average opacity monitoring 

data according to § 63.1572; 

maintaining the 3-hr rolling average opacity at or above the 

limit established during the performance test. 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii), electing to 

meet the PM per coke burn-off 

limit.

Any ................................................ Any ................................................ See items 1.b, 1.c, 1.d, and 1.e of 

this table. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1), electing to 

meet the PM concentration limit.

PM CEMS ..................................... Not applicable. .............................. Complying with Table 6 of this 

subpart. 

4. Option 1: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1).

a. Continuous opacity monitoring 

system.

The opacity of emissions from 

your catalyst regenerator vent 

must not exceed the site-specific opacity operating limit established during the performance test.

Collecting the 3-hr rolling average 

continuous opacity monitoring 

system data according to 

§ 63.1572; and maintaining the 

3-hr rolling average opacity at 

or below the site-specific limit. 

Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], collecting the 

hourly average continuous 

opacity monitoring system data 

according to § 63.1572; and 

maintaining the hourly average 

opacity at or below the site-specific limit. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37019 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

b. Continuous parameter monitoring systems—electrostatic 

precipitator.

i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during 

the performance test.

Collecting the hourly and 3-hr rolling average gas flow rate monitoring data according to 

§ 63.1572; and maintaining the 

3-hr rolling average gas flow 

rate at or below the limit established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], collecting the 

hourly and daily average gas 

flow rate monitoring data according to § 63.1572; 1 and 

maintaining the daily average 

gas flow rate at or below the 

limit established during the performance test. 

ii. The average voltage and secondary current (or total power 

input) to the control device 

must not fall below the operating limit established during 

the performance test..

Collecting the hourly and 3-hr rolling average total power and 

secondary current monitoring 

data according to § 63.1572; 

and maintaining the 3-hr rolling 

average total power and secondary current at or above the 

limit established during the performance test. Alternatively, before [THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], collecting 

the hourly and daily average 

voltage and secondary current 

(or total power input) monitoring 

data according to § 63.1572; 

and maintaining the daily average voltage and secondary current (or total power input) at or 

above the limit established during the performance test. 

c. Continuous parameter monitoring systems—wet scrubber.i. The average pressure drop 

across the scrubber must not 

fall below the operating limit established during the performance test.

Collecting the hourly and 3-hr rolling average pressure drop 

monitoring data according to 

§ 63.1572; and maintaining the 

3-hr rolling average pressure 

drop at or above the limit established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], collecting the 

hourly and daily average pressure drop monitoring data according to § 63.1572; and maintaining the daily average pressure drop above the limit established during the performance 

test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37020 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

ii. The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test.

Collecting the hourly and 3-hr rolling average gas flow rate and 

scrubber liquid flow rate monitoring data according to 

§ 63.1572; determining and recording the 3-hr liquid-to-gas 

ratio; and maintaining the 3-hr 

rolling average liquid-to-gas 

ratio at or above the limit established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], collecting the 

hourly average gas flow rate 

and water (or scrubbing liquid) 

flow rate monitoring data according to § 63.1572; 1 determining and recording the hourly 

average liquid-to-gas ratio; determining and recording the 

daily average liquid-to-gas ratio; 

and maintaining the daily average liquid-to-gas ratio above 

the limit established during the 

performance test. 

d. BLD—fabric filter ...................... Increases in relative particulate .... Collecting and maintaining 

records of BLD system output; 

determining the cause of the 

alarm within 1 hour of the 

alarm; and alleviating the cause 

of the alarm within 3 hours by 

corrective action. 

e. Continuous opacity monitoring 

system, used for site-specific 

opacity limit—Cyclone or electrostatic precipitator.

The average opacity must not exceed the opacity established 

during the performance test.

Collecting the hourly and 3-hr rolling average opacity monitoring 

data according to § 63.1572; 

maintaining the 3-hr rolling average opacity at or above the 

limit established during the performance test. 

5. Option 2: PM concentration 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1)..

PM CEMS ..................................... Not applicable ............................... Complying with Table 6 of this 

subpart. 

6. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 

CFR 60.102.

a. Continuous opacity monitoring 

system.

i. The daily average Ni operating 

value must not exceed the sitespecific Ni operating limit established during the performance 

test.

(1) Collecting the hourly average 

continuous opacity monitoring 

system data according to 

§ 63.1572; determining and recording equilibrium catalyst Ni 

concentration at least once a 

week; 2 collecting the hourly average gas flow rate monitoring 

data according to § 63.1572; 1

and determining and recording 

the hourly average Ni operating 

value using Equation 11 of 

§ 63.1564. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37021 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

(2) Determining and recording the 

3-hour rolling average Ni operating value and maintaining the 

3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], determining and 

recording the daily average Ni 

operating value and maintaining 

the daily average Ni operating 

value below the site-specific Ni 

operating limit established during the performance test. 

b. Continuous parameter monitoring systems—electrostatic 

precipitator.

i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during 

the performance test.

See item 4.b.i of this table. 

ii. The average voltage and secondary current (or total power 

input) must not fall below the 

level established in the performance test.

See item 4.b.ii of this table. 

iii. The monthly rolling average of 

the equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

Determining and recording the 

equilibrium catalyst Ni concentration at least once a 

week; 2 determining and recording the monthly rolling average 

of the equilibrium catalyst Ni 

concentration once each week 

using the weekly or most recent 

value; and maintaining the 

monthly rolling average below 

the limit established in the performance test. 

c. Continuous parameter monitoring systems—wet scrubber.i. The average pressure drop 

must not fall below the operating limit established in the 

performance test.

See item 4.c.i of this table. 

ii. The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test.

See item 4.c.ii of this table. 

iii. The monthly rolling average 

equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

Determining and recording the 

equilibrium catalyst Ni concentration at least once a 

week; 2 determining and recording the monthly rolling average 

of equilibrium catalyst Ni concentration once each week 

using the weekly or most recent 

value; and maintaining the 

monthly rolling average below 

the limit established in the performance test. 

d. BLD—fabric filter ...................... Increases in relative particulate .... See item 4.d of this table. 

e. Continuous opacity monitoring 

system, used for site-specific 

opacity limit—Cyclone or electrostatic precipitator.

The average opacity must not exceed the opacity established 

during the performance test.

See item 4.e of this table. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37022 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

7. Option 4: Ni per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102..

a. Continuous opacity monitoring 

system..

i. The daily average Ni operating 

value must not exceed the sitespecific Ni operating limit established during the performance 

test.

(1) Collecting the hourly average 

continuous opacity monitoring 

system data according to 

§ 63.1572; collecting the hourly 

average gas flow rate monitoring data according to 

§ 63.1572; 1 determining and recording equilibrium catalyst Ni 

concentration at least once a 

week; 2 and determining and recording the hourly average Ni 

operating value using Equation 

12 of § 63.1564. 

(2) Determining and recording the 

3-hour rolling average Ni operating value and maintaining the 

3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], determining and 

recording the daily average Ni 

operating value and maintaining 

the daily average Ni operating 

value below the site-specific Ni 

operating limit established during the performance test. 

b. Continuous parameter monitoring systems—electrostatic 

precipitator.

i. The daily average gas flow rate 

to the control device must not 

exceed the level established in 

the performance test.

See item 4.b.i of this table. 

ii. The daily average voltage and 

secondary current (or total 

power input) must not fall below 

the level established in the performance test.

See item 4.b.ii of this table. 

iii. The monthly rolling average 

equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

See item 6.b.iii of this table. 

c. Continuous parameter monitoring systems—wet scrubber.i. The daily average pressure 

drop must not fall below the operating limit established in the 

performance test.

See item 4.c.i of this table. 

.................................................. ii. The daily average liquid-to-gas 

ratio must not fall below the operating limit established during 

the performance test.

See item 4.c.ii of this table. 

.................................................. iii. The monthly rolling average 

equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

See item 6.c.iii of this table. 

d. BLD—fabric filter ...................... Increases in relative particulate .... See item 4.d of this table. 

e. Continuous opacity monitoring 

system, used for site-specific 

opacity limit—Cyclone or electrostatic precipitator.

The average opacity must not exceed the opacity established 

during the performance test.

See item 4.e of this table. 

1 If applicable, you can use the alternative in § 63.1573(a)(1) for gas flow rate instead of a continuous parameter monitoring system if you used 

the alternative method in the initial performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37023 

2The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in Appendix A to this subpart; or by EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, or 

EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, or 7521 satisfactory to 

the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical 

Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for 

purchase from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the 

EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or 

at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at http://

www.epa.gov/epaoswer/hazwaste/test/main.htm. 

■ 59. Table 8 to subpart UUU of part 63 

is amended by revising the entry for 

item 2 to read as follows: 

* * * * * 

TABLE 8 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS

For each new and existing catalytic 

cracking unit . . . You shall meet the following emission limit for each catalyst regenerator vent . . . 

*******

2. Not subject to the NSPS for CO 

in 40 CFR 60.103.

a. CO emissions from the catalyst regenerator vent or CO boiler serving the catalytic cracking unit must 

not exceed 500 ppmv (dry basis). 

b. If you use a flare to meet the CO limit, then on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must 

meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the 

requirements for control devices in § 63.11(b) and visible emissions must not exceed a total of 5 minutes 

during any 2 consecutive hours, or the flare must meet the requirements of § 63.670. 

■ 60. Table 9 to subpart UUU of part 63 

is amended by revising the entry for 

item 2 to read as follows: 

* * * * * 

TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

*******

2. Not subject to the NSPS for CO 

in 40 CFR 60.103.

a. Continuous emission monitoring 

system.

Not applicable ............................... Not applicable. 

b. Continuous parameter monitoring systems.i. Thermal incinerator .................... Maintain the daily average combustion zone temperature above 

the limit established during the 

performance test; and maintain 

the daily average oxygen concentration in the vent stream 

(percent, dry basis) above the 

limit established during the performance test. 

ii. Boiler or process heater with a 

design heat input capacity 

under 44 MW or a boiler or 

process heater in which all vent 

streams are not introduced into 

the flame zone.

Maintain the daily average combustion zone temperature above 

the limit established in the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37024 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

iii. Flare ......................................... On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the 

flare must meet the requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare pilot light 

must be present at all times and 

the flare must be operating at 

all times that emissions may be 

vented to it, or the flare must 

meet the requirements of 

§ 63.670. 

■ 61. Table 10 to subpart UUU of part 

63 is amended by revising the entry for 

item 2 to read as follows: 

* * * * * 

TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS

For each new or existing catalytic 

cracking unit . . . 

And you use this type of control device for your 

vent . . . 

You shall install, operate, and maintain this type 

of continuous monitoring system . . . 

*******

2. Not subject to the NSPS for CO in 40 

CFR 60.103.

a. Thermal incinerator ............................................ Continuous emission monitoring system to measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent; or continuous parameter 

monitoring systems to measure and record the 

combustion zone temperature and oxygen content (percent, dry basis) in the incinerator vent 

stream. 

b. Process heater or boiler with a design heat 

input capacity under 44 MW or process heater 

or boiler in which all vent streams are not introduced into the flame zone.

Continuous emission monitoring system to measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent; or continuous parameter 

monitoring systems to measure and record the 

combustion zone temperature. 

c. Flare ................................................................... On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the monitoring systems required in 

§§ 63.670 and 63.671. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], monitoring device such 

as a thermocouple, an ultraviolet beam sensor, 

or infrared sensor to continuously detect the 

presence of a pilot flame, or the monitoring systems required in §§ 63.670 and 63.671. 

d. No control device ............................................... Continuous emission monitoring system to measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37025 

■ 62. Table 11 to subpart UUU of part 

63 is amended by revising revising the 

entry for item 3 to read as follows: 

* * * * * 

TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON

MONOXIDE (CO) 

For . . . You must . . . Using . . . According to these 

requirements . . . 

*******

3. Each catalytic cracking unit catalyst regenerator vent if you use 

continuous parameter monitoring systems.

a. Measure the CO concentration 

(dry basis) of emissions exiting 

the control device.

Method 10, 10A, or 10B in appendix A to part 60 of this chapter, 

as applicable.

b. Establish each operating limit in 

Table 9 of this subpart that applies to you.

Data from the continuous parameter monitoring systems.

c. Thermal incinerator combustion 

zone temperature.

Data from the continuous parameter monitoring systems.Collect temperature monitoring 

data every 15 minutes during 

the entire period of the CO initial performance test; and determine and record the minimum 

hourly average combustion 

zone temperature from all the 

readings. 

d. Thermal incinerator: oxygen, 

content (percent, dry basis) in 

the incinerator vent stream.

Data from the continuous parameter monitoring systems.Collect oxygen concentration (percent, dry basis) monitoring data 

every 15 minutes during the entire period of the CO initial performance test; and determine 

and record the minimum hourly 

average percent excess oxygen 

concentration from all the readings. 

e. If you use a process heater or 

boiler with a design heat input 

capacity under 44 MW or process heater or boiler in which all 

vent streams are not introduced 

into the flame zone, establish 

operating limit for combustion 

zone temperature.

Data from the continuous parameter monitoring systems.Collect the temperature monitoring 

data every 15 minutes during 

the entire period of the CO initial performance test; and determine and record the minimum 

hourly average combustion 

zone temperature from all the 

readings. 

f. If you use a flare, conduct visible emission observations.Method 22 (40 CFR part 60, appendix A).On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], meet 

the requirements of § 63.670. 

Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], maintain a 

2-hour observation period; and 

record the presence of a flame 

at the pilot light over the full period of the test or meet the requirements of § 63.670. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37026 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON

MONOXIDE (CO)—Continued 

For . . . You must . . . Using . . . According to these 

requirements . . . 

g. If you use a flare, determine 

that the flare meets the requirements for net heating value of 

the gas being combusted and 

exit velocity.

40 CFR 63.11(b)(6) through (8) .... On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the 

flare must meet the requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must 

meet the control device requirements in § 63.11(b) or the requirements of § 63.670. 

■ 63. Table 12 to subpart UUU of part 

63 is amended by revising the entry for 

item 2 to read as follows: 

* * * * * 

TABLE 12 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS

For each new and existing catalytic 

cracking unit . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 

*******

2. Not subject to the NSPS for CO in 40 

CFR 60.103.

a. CO emissions from your catalyst regenerator 

vent or CO boiler serving the catalytic cracking 

unit must not exceed 500 ppmv (dry basis).

i. If you use a continuous parameter monitoring 

system, the average CO emissions measured 

by Method 10 over the period of the initial performance test are less than or equal to 500 

ppmv (dry basis). 

ii. If you use a continuous emission monitoring 

system, the hourly average CO emissions over 

the 24-hour period for the initial performance 

test are not more than 500 ppmv (dry basis); 

and your performance evaluation shows your 

continuous emission monitoring system meets 

the applicable requirements in § 63.1572. 

b. If you use a flare, visible emissions must not 

exceed a total of 5 minutes during any 2 operating hours.

On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare meets the requirements 

of § 63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], visible emissions, measured by Method 22 during the 2-hour observation period during the initial performance test, 

are no higher than 5 minutes, or the flare 

meets the requirements of § 63.670. 

■ 64. Table 13 to subpart UUU of part 

63 is amended by revising the entry for 

item 2 to read as follows: 

* * * * * 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37027 

TABLE 13 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR

CATALYTIC CRACKING UNITS

For each new and existing 

catalytic cracking unit . . . 

Subject to this emission limit for 

your catalyst regenerator 

vent . . . 

If you must . . You shall demonstrate continuous 

compliance by . . . 

*******

2. Not subject to the NSPS for CO 

in 40 CFR 60.103.

i. CO emissions from your catalyst 

regenerator vent or CO boiler 

serving the catalytic cracking 

unit must not exceed 500 ppmv 

(dry basis).

Continuous emission monitoring 

system.

Same as above. 

ii. CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking 

unit must not exceed 500 ppmv 

(dry basis).

Continuous parameter monitoring 

system.

Maintaining the hourly average 

CO concentration below 500 

ppmv (dry basis). 

iii. Visible emissions from a flare 

must not exceed a total of 5 

minutes during any 2-hour period.

Control device-flare ....................... On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], meeting the requirements of 

§ 63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], maintaining visible emissions below 

a total of 5 minutes during any 

2-hour operating period, or 

meeting the requirements of 

§ 63.670. 

■ 65. Table 14 to subpart UUU of part 

63 is amended by revising the entry for 

item 2 to read as follows: 

* * * * * 

TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS

For each new existing 

catalytic cracking 

unit . . . 

If you use . . . For this operating limit . . . You shall demonstrate continuous 

compliance by . . . 

*******

2. Not subject to the 

NSPS for CO in 40 

CFR 60.103.

a. Continuous emission monitoring 

system.

Not applicable ..................................... Complying with Table 13 of this subpart. 

b. Continuous parameter monitoring 

systems—thermal incinerator.

i. The daily average combustion zone 

temperature must not fall below the 

level established during the performance test.

Collecting the hourly and daily average temperature monitoring data 

according to § 63.1572; and maintaining the daily average combustion zone temperature above the 

limit established during the performance test. 

ii. The daily average oxygen concentration in the vent stream (percent, dry basis) must not fall below 

the level established during the 

performance test.

Collecting the hourly and daily average oxygen concentration monitoring data according to § 63.1572; 

and maintaining the daily average 

oxygen concentration above the 

limit established during the performance test. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37028 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new existing 

catalytic cracking 

unit . . . 

If you use . . . For this operating limit . . . You shall demonstrate continuous 

compliance by . . . 

c. Continuous parameter monitoring 

systems—boiler or process heater 

with a design heat input capacity 

under 44 MW or boiler or process 

heater in which all vent streams 

are not introduced into the flame 

zone.

The daily combustion zone temperature must not fall below the level 

established in the performance test.

Collecting the average hourly and 

daily temperature monitoring data 

according to § 63.1572; and maintaining the daily average combustion zone temperature above the 

limit established during the performance test. 

d. Continuous parameter monitoring 

system—flare.

The flare pilot light must be present 

at all times and the flare must be 

operating at all times that emissions may be vented to it.

On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], meeting the requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], collecting the flare monitoring data according to § 63.1572 and recording 

for each 1-hour period whether the 

monitor was continuously operating 

and the pilot light was continuously 

present during each 1-hour period, 

or meeting the requirements of 

§ 63.670. 

■ 66. Table 15 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 15 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS

For each applicable process vent 

for a new or existing catalytic 

reforming unit . . . 

You shall meet this emission limit during initial catalyst depressuring and catalyst purging operations . . . 

1. Option 1 ...................................... On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE

AMENDMENTS IN THE FEDERAL REGISTER], vent emissions to a flare that meets the requirements 

of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], vent emissions to a flare that meets the requirements 

for control devices in § 63.11(b) and visible emissions from a flare must not exceed a total of 5 minutes 

during any 2-hour operating period, or vent emissions to a flare that meets the requirements of § 63.670. 

*******

■ 67. Table 16 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37029 

TABLE 16 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC

REFORMING UNITS

For each new or existing catalytic 

reforming unit . . . For this type of control device . . . You shall meet this operating limit during initial catalyst depressuring and purging operations . . . 

1. Option 1: vent to flare ................ Flare ............................................... On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet the requirements of § 63.670. 

Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare pilot light must be present at all times and 

the flare must be operating at all times that emissions may be vented to it, or the flare must meet the requirements of § 63.670. 

* * * * * * * 

■ 68. Table 17 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 17 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM

CATALYTIC REFORMING UNITS

For each applicable process vent 

for a new or existing catalytic 

reforming unit . . . 

If you use this type of control 

device . . . 

You shall install and operate this type of continuous monitoring 

system . . . 

1. Option 1: vent to a flare ............. Flare ............................................... On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the monitoring systems required in §§ 63.670 and 

63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], monitoring device such as a thermocouple, 

an ultraviolet beam sensor, or infrared sensor to continuously detect the presence of a pilot flame, or the monitoring systems required in §§ 63.670 and 63.671. 

* * * * * * * 

■ 69. Table 18 to subpart UUU of part 

63 is amended by: 

■ a. Revising the column headings and 

■ b. Revising the entry for item 1. 

The revisions read as follows: 

* * * * * 

TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS

For each new or 

existing catalytic 

reforming unit . . . 

You must . . . Using . . . According to these requirements . . . 

1. Option 1: Vent to a 

flare.

a. Conduct visible emission observations.Method 22 (40 CFR part 60, appendix A).On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet 

the requirements of § 63.670. Prior 

to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER],2- 

hour observation period. Record 

the presence of a flame at the pilot 

light over the full period of the test, 

or the requirements of § 63.670. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37030 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS—Continued 

For each new or 

existing catalytic 

reforming unit . . . 

You must . . . Using . . . According to these requirements . . . 

b. Determine that the flare meets the 

requirements for net heating value 

of the gas being combusted and 

exit velocity.

40 CFR 63.11(b)(6) through (8) ......... On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet 

the requirements of § 63.670. Prior 

to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

the flare must meet the control device requirements in § 63.11(b) or 

the requirements of § 63.670. 

* * * * * * * 

■ 70. Table 19 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 19 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC

REFORMING UNITS

For each applicable process 

vent for a new or existing 

catalytic reforming unit . . . 

For the following emission limit . . . You have demonstrated initial compliance if . . . 

Option 1 ................................ Visible emissions from a flare must not exceed a total 

of 5 minutes during any 2 consecutive hours.

On and after [THE DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare 

meets the requirements of § 63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], visible emissions, measured 

using Method 22 over the 2-hour observation period 

of the performance test, do not exceed a total of 5 

minutes, or the flare meets the requirements of 

§ 63.670. 

* * * * * * * 

■ 71. Table 20 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR

CATALYTIC REFORMING UNITS

For each applicable process vent for a new or existing 

catalytic reforming unit . . . For this emission limit . . . 

You shall demonstrate continuous compliance during 

initial catalyst depressuring and catalyst purging operations by . . . 

1. Option 1 ........................................................................ Vent emissions from your 

process vent to a flare.

On and after [THE DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], meeting the 

requirements of § 63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], maintaining visible emissions 

from a flare below a total of 5 minutes during any 2 

consecutive hours, or meeting the requirements of 

§ 63.670. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37031 

TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR

CATALYTIC REFORMING UNITS—Continued 

For each applicable process vent for a new or existing 

catalytic reforming unit . . . For this emission limit . . . 

You shall demonstrate continuous compliance during 

initial catalyst depressuring and catalyst purging operations by . . . 

*******

■ 72. Table 21 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 21 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP 

EMISSIONS FROM CATALYTIC REFORMING UNITS

For each applicable 

process vent for a new 

or existing catalytic reforming unit . . . 

If you use . . . For this operating limit . . . 

You shall demonstrate continuous compliance 

during initial catalyst depressuring and purging 

operations by . . . 

1. Option 1 ..................... Flare .............................. The flare pilot light must be present at 

all times and the flare must be operating at all times that emissions may 

be vented to it.

On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], meeting the requirements of 

§ 63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], collecting flare monitoring data according to § 63.1572 and recording for each 1-hour period whether the monitor 

was continuously operating and the pilot light 

was continuously present during each 1-hour 

period, or meeting the requirements of 

§ 63.670. 

* * * * * * * 

■ 73. Table 22 to subpart UUU of part 

63 is amended by revising the entries for 

items 2 and 3 to read as follows: 

* * * * * 

TABLE 22 TO SUBPART UUU OF PART 63—INORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS

For . . . You shall meet this emission limit for each applicable catalytic reforming unit process 

vent during coke burn-off and catalyst rejuvenation . . . 

*******

2. Each existing cyclic or continuous catalytic reforming 

unit.

Reduce uncontrolled emissions of HCl by 97 percent by weight or to a concentration 

of 10 ppmv (dry basis), corrected to 3 percent oxygen. 

3. Each new semi-regenerative, cyclic, or continuous 

catalytic reforming unit.

Reduce uncontrolled emissions of HCl by 97 percent by weight or to a concentration 

of 10 ppmv (dry basis), corrected to 3 percent oxygen. 

■ 74. Table 24 to subpart UUU of part 

63 is amended by revising the entries for 

Items 2 through 4 and footnote 2 to read 

as follows: 

* * * * * 

TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM

CATALYTIC REFORMING UNITS

If you use this type of control device for your vent . . . You shall install and operate this type of continuous monitoring system . . . 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37032 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM

CATALYTIC REFORMING UNITS—Continued 

If you use this type of control device for your vent . . . You shall install and operate this type of continuous monitoring system . . . 

*******

2. Internal scrubbing system or no control device (e.g., 

hot regen system) to meet HCl outlet concentration 

limit.

Colormetric tube sampling system to measure the HCl concentration in the catalyst 

regenerator exhaust gas during coke burn-off and catalyst rejuvenation. The 

colormetric tube sampling system must meet the requirements in Table 41 of this 

subpart. 

3. Internal scrubbing system to meet HCl percent reduction standard.Continuous parameter monitoring system to measure and record the gas flow rate 

entering or exiting the internal scrubbing system during coke burn-off and catalyst 

rejuvenation; and continuous parameter monitoring system to measure and record 

the total water (or scrubbing liquid) flow rate entering the internal scrubbing system 

during coke burn-off and catalyst rejuvenation; and continuous parameter monitoring system to measure and record the pH or alkalinity of the water (or scrubbing 

liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation.2

4. Fixed-bed gas-solid adsorption system ......................... Continuous parameter monitoring system to measure and record the temperature of 

the gas entering or exiting the adsorption system during coke burn-off and catalyst 

rejuvenation; and colormetric tube sampling system to measure the gaseous HCl 

concentration in the adsorption system exhaust and at a point within the absorbent 

bed not to exceed 90 percent of the total length of the absorbent bed during coke 

burn-off and catalyst rejuvenation. The colormetric tube sampling system must 

meet the requirements in Table 41 of this subpart. 

* * * * * * * 

* * * * * 

2 If applicable, you can use the alternative in § 63.1573(c)(1) instead of a continuous parameter monitoring system for pH of the water (or 

scrubbing liquid) or the alternative in § 63.1573(c)(2) instead of a continuous parameter monitoring system for alkalinity of the water (or scrubbing 

liquid). 

■ 75. Table 25 to subpart UUU of part 

63 is amended by revising the entries for 

items 2.a and 4.a to read as follows: 

* * * * * 

TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS

For each new and existing 

catalytic reforming unit 

using . . . 

You shall . . . Using . . . According to these requirements . . . 

*******

2. Wet scrubber .................. a. Establish operating limit 

for pH level or alkalinity.

i. Data from continuous parameter monitoring systems.Measure and record the pH or alkalinity of the water 

(or scrubbing liquid) exiting scrubber every 15 minutes during the entire period of the performance test. 

Determine and record the minimum hourly average 

pH or alkalinity level from the recorded values. 

ii. Alternative pH procedure 

in § 63.1573 (b)(1).

Measure and record the pH of the water (or scrubbing 

liquid) exiting the scrubber during coke burn-off and 

catalyst rejuvenation using pH strips at least three 

times during each test run. Determine and record 

the average pH level for each test run. Determine 

and record the minimum test run average pH level. 

iii. Alternative alkalinity 

method in 

§ 63.1573(c)(2).

Measure and record the alkalinity of the water (or 

scrubbing liquid) exiting the scrubber during coke 

burn-off and catalyst rejuvenation using discrete titration at least three times during each test run. Determine and record the average alkalinity level for 

each test run. Determine and record the minimum 

test run average alkalinity level. 

* * * * * * * 

4. Internal scrubbing system meeting HCl percent 

reduction standard.

a. Establish operating limit 

for pH level or alkalinity.

i. Data from continuous parameter monitoring system.Measure and record the pH alkalinity of the water (or 

scrubbing liquid) exiting the internal scrubbing system every 15 minutes during the entire period of the 

performance test. Determine and record the minimum hourly average pH or alkalinity level from the 

recorded values. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37033 

TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS—Continued 

For each new and existing 

catalytic reforming unit 

using . . . 

You shall . . . Using . . . According to these requirements . . . 

ii. Alternative pH method in 

§ 63.1573(c)(1).

Measure and record pH of the water (or scrubbing liquid) exiting the internal scrubbing system during 

coke burn-off and catalyst rejuvenation using pH 

strips at least three times during each test run. Determine and record the average pH level for each 

test run. Determine and record the minimum test run 

average pH level. 

iii. Alternative alkalinity 

method in 

§ 63.1573(c)(2).

Measure and record the alkalinity of the water (or 

scrubbing liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation 

using discrete titration at least three times during 

each test run. Determine and record the average alkalinity level for each test run. Determine and record 

the minimum test run average alkalinity level. 

* * * * * * * 

* * * * * 

■ 76. Table 28 to subpart UUU of part 

63 is amended by revising the entry for 

item 5 and footnote 1 to read as follows: 

The revisions read as follows: 

* * * * * 

TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP 

EMISSIONS FROM CATALYTIC REFORMING UNITS

For each new and existing catalytic 

reforming unit using this type of 

control device or system . . . 

For this operating limit . . . You shall demonstrate continuous compliance during coke burn-off 

and catalyst rejuvenation by . . . 

*******

5. Moving-bed gas-solid adsorption 

system (e.g., ChlorsorbTM System.

a. The daily average temperature 

of the gas entering or exiting the 

adsorption system must not exceed the limit established during 

the performance test.

Collecting the hourly and daily average temperature monitoring data 

according to § 63.1572; and maintaining the daily average temperature below the operating limit established during the performance 

test. 

b. The weekly average chloride 

level on the sorbent entering the 

adsorption system must not exceed the design or manufacturer’s recommended limit (1.35 

weight percent for the 

ChlorsorbTM System).

Collecting samples of the sorbent exiting the adsorption system three 

times per week (on non-consecutive days); and analyzing the samples for total chloride; 3 and determining and recording the weekly 

average chloride concentration; and maintaining the chloride concentration below the design or manufacturer’s recommended limit 

(1.35 weight percent for the ChlorsorbTM System). 

c. The weekly average chloride 

level on the sorbent exiting the 

adsorption system must not exceed the design or manufacturer’s recommended limit (1.8 

weight percent for the 

ChlorsorbTM System).

Collecting samples of the sorbent exiting the adsorption system three 

times per week (on non-consecutive days); and analyzing the samples for total chloride concentration; and determining and recording 

the weekly average chloride concentration; and maintaining the 

chloride concentration below the design or manufacturer’s recommended limit (1.8 weight percent ChlorsorbTM System). 

1 If applicable, you can use either alternative in § 63.1573(c) instead of a continuous parameter monitoring system for pH or alkalinity if you 

used the alternative method in the initial performance test. 

* * * * * 

■ 77. Table 29 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(a)(1), you shall 

meet each emission limitation in the 

following table that applies to you. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37034 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 29 TO SUBPART UUU OF PART 63—HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS

For . . . You shall meet this emission limit for each process vent . . . 

1. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day 

and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 

in 40 CFR 60.102a(f)(1).

a. 250 ppmv (dry basis) of sulfur dioxide (SO2) at zero percent excess 

air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation control system or if you use 

a reduction control system followed by incineration. 

b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2

(dry basis) at zero percent excess air, or concentration determined 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction 

control system without incineration. 

2. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 60.102a(f)(1): Option 1 (Elect NSPS).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if 

you use an oxidation control system or if you use a reduction control 

system followed by incineration. 

b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2

(dry basis) at zero percent excess air, or concentration determined 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction 

control system without incineration. 

3. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 60.102a(f)(1): Option 2 (TRS limit).

300 ppmv of total reduced sulfur (TRS) compounds, expressed as an 

equivalent SO2 concentration (dry basis) at zero percent oxygen. 

■ 78. Table 30 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(a)(2), you shall 

meet each operating limit in the 

following table that applies to you. 

TABLE 30 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS

For . . . If use this type of control device You shall meet this operating limit . . . 

1. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day 

and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) 

or in 40 CFR 60.102a(f)(1).

Not applicable ............. Not applicable. 

2. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 CFR 60.102a(f)(1): Option 1 (Elect 

NSPS).

Not applicable ............. Not applicable. 

3. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 CFR 60.102a(f)(1): Option 2 (TRS limit), 

if using continuous emissions monitoring systems.

Not applicable ............. Not applicable. 

4. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 CFR 60.102a(f)(1): Option 2 (TRS limit), 

if using continuous parameter monitoring systems.

Thermal incinerator ..... Maintain the daily average combustion zone 

temperature above the limit established during the performance test; and maintain the 

daily average oxygen concentration in the 

vent stream (percent, dry basis) above the 

limit established during the performance 

test. 

■ 79. Table 31 to subpart UUU is revised 

to read as follows: 

As stated in § 63.1568(b)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR

RECOVERY UNITS

For . . . For this limit . . . You shall install and operate this continuous 

monitoring system . . . 

1. Each new or existing Claus sulfur recovery 

unit part of a sulfur recovery plant with design capacity greater than 20 long tons per 

day and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or 

reduction control system followed by incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of SO2 (dry basis) at zero percent excess air for each exhaust stack. This 

system must include an oxygen monitor for 

correcting the data for excess air. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37035 

TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR

RECOVERY UNITS—Continued 

For . . . For this limit . . . You shall install and operate this continuous 

monitoring system . . . 

b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero 

percent excess air if you use a reduction 

control system without incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of reduced sulfur and oxygen 

(O2) emissions. Calculate the reduced sulfur 

emissions as SO2 (dry basis) at zero percent excess air. Exception: You can use an 

instrument having an air or SO2 dilution and 

oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and 

recording the concentration (dry basis) at 

zero percent excess air of the resultant SO2

instead of the reduced sulfur monitor. The 

monitor must include an oxygen monitor for 

correcting the data for excess oxygen. 

c. If you use Equation 1 of 40 CFR 

60.102a(f)(1)(i) to set your emission limit.

Complete either item 1.a or item 1.b; and you 

must also install and operate a continuous 

emission monitoring system to measure and 

record the O2 concentration for the inlet air/

oxygen supplied to the system. 

2. Option 1: Elect NSPS. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in paragraph (a) (2) of 40 CFR 

60.104 or in 40 CFR 60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or 

reduction control system followed by incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of SO2 (dry basis), at zero 

percent excess air for each exhaust stack. 

This system must include an oxygen monitor for correcting the data for excess air. 

b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero 

percent excess air if you use a reduction 

control system without incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of reduced sulfur and O2

emissions for each exhaust stack. Calculate 

the reduced sulfur emissions as SO2 (dry 

basis), at zero percent excess air. Exception: You can use an instrument having an 

air or O2 dilution and oxidation system to 

convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess 

air of the resultant SO2 instead of the reduced sulfur monitor. The monitor must include an oxygen monitor for correcting the 

data for excess oxygen. 

c. If you use Equation 1 of 40 CFR 

60.102a(f)(1)(i) to set your emission limit.

Complete either item 2.a or item 2.b; and you 

must also install and operate a continuous 

emission monitoring system to measure and 

record the O2 concentration for the inlet air/

oxygen supplied to the system. 

3. Option 2: TRS limit. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or in 

40 CFR 60.102a(f)(1).

300 ppmv of total reduced sulfur (TRS) compounds, expressed as an equivalent SO2

concentration (dry basis) at zero percent oxygen.

i. Continuous emission monitoring system to 

measure and record the hourly average 

concentration of TRS for each exhaust 

stack; this monitor must include an oxygen 

monitor for correcting the data for excess 

oxygen; or 

ii. Continuous parameter monitoring systems 

to measure and record the combustion zone 

temperature of each thermal incinerator and 

the oxygen content (percent, dry basis) in 

the vent stream of the incinerator. 

■ 80. Table 32 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(b)(2) and (3), 

you shall meet each requirement in the 

following table that applies to you. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37036 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM

SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES

For . . . You must . . . Using . . . According to these 

requirements . . . 

1. Each new and existing sulfur recovery unit: Option 1 (Elect 

NSPS).

Measure SO2 concentration (for 

an oxidation or reduction system followed by incineration) or 

measure the concentration of 

reduced sulfur (or SO2 if you 

use an instrument to convert 

the reduced sulfur to SO2) for a 

reduction control system without incineration.

Data from continuous emission 

monitoring system.

Collect SO2 monitoring data every 

15 minutes for 24 consecutive 

operating hours. Reduce the 

data to 1-hour averages computed from four or more data 

points equally spaced over 

each 1-hour period. 

Measure O2 concentration for the 

inlet air/oxygen supplied to the 

system, if using Equation 1 of 

40 CFR 60.102a(f)1)(i) to set 

your emission limit.

Data from continuous emission 

monitoring system.

Collect O2 monitoring data every 

15 minutes for 24 consecutive 

operating hours. Reduce the 

data to 1-hour averages computed from four or more data 

points equally spaced over 

each 1-hour period; and average over the 24-hour period for 

input to Equation 1 of 40 CFR 

60.102a(f)(1)(i). 

2. Each new and existing sulfur recovery unit: Option 2 (TRS limit), 

using CEMS.

Measure the concentration of reduced sulfur (or SO2 if you use 

an instrument to convert the reduced sulfur to SO2).

Data from continuous emission 

monitoring system.

Collect TRS data every 15 minutes for 24 consecutive operating hours. Reduce the data to 

1-hour averages computed from 

four or more data points equally 

spaced over each 1-hour period. 

3. Each new and existing sulfur recovery unit: Option 2 (TRS limit), 

if using continuous parameter 

monitoring systems.

a. Select sampling port’s location 

and the number of traverse 

ports.

Method 1 or 1A in Appendix A–1 

to part 60 of this chapter.

Sampling sites must be located at 

the outlet of the control device 

and prior to any releases to the 

atmosphere. 

b. Determine velocity and volumetric flow rate.Method 2, 2A, 2C, 2D, 2F, or 2G 

in appendix A to part 60 of this 

chapter, as applicable.

c. Conduct gas molecular weight 

analysis; obtain the oxygen 

concentration needed to correct 

the emission rate for excess air.

Method 3, 3A, or 3B in appendix 

A to part 60 of this chapter, as 

applicable.

Take the samples simultaneously 

with reduced sulfur or moisture 

samples. 

d. Measure moisture content of 

the stack gas.

Method 4 in appendix A to part 60 

of this chapter.

Make your sampling time for each 

Method 4 sample equal to that 

for 4 Method 15 samples. 

e. Measure the concentration of 

TRS.

Method 15 or 15A in appendix A 

to part 60 of this chapter, as 

applicable.

If the cross-sectional area of the 

duct is less than 5 square meters (m2) or 54 square feet, you 

must use the centroid of the 

cross section as the sampling 

point. If the cross-sectional area 

is 5 m2 or more and the centroid is more than 1 meter (m) 

from the wall, your sampling 

point may be at a point no closer to the walls than 1 m or 39 

inches. Your sampling rate 

must be at least 3 liters per 

minute or 0.10 cubic feet per 

minute to ensure minimum residence time for the sample inside the sample lines. 

f. Calculate the SO2 equivalent for 

each run after correcting for 

moisture and oxygen.

The arithmetic average of the SO2

equivalent for each sample during the run.

g. Correct the reduced sulfur 

samples to zero percent excess 

air.

Equation 1 of § 63.1568.

h. Establish each operating limit in 

Table 30 of this subpart that 

applies to you.

Data from the continuous parameter monitoring system.


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37037 

TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES—Continued 

For . . . You must . . . Using . . . According to these 

requirements . . . 

i. Measure thermal incinerator: 

combustion zone temperature.

Data from the continuous parameter monitoring system.Collect temperature monitoring 

data every 15 minutes during 

the entire period of the performance test; and determine and 

record the minimum hourly average temperature from all the 

readings. 

j. Measure thermal incinerator: oxygen concentration (percent, 

dry basis) in the vent stream.

Data from the continuous parameter monitoring system.Collect oxygen concentration (percent, dry basis) data every 15 

minutes during the entire period 

of the performance test; and 

determine and record the minimum hourly average percent 

excess oxygen concentration. 

■ 81. Table 33 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(b)(5), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY

UNITS

For . . . For the following emission 

limit . . . You have demonstrated initial compliance if . . . 

1. Each new or existing Claus sulfur recovery unit part of a sulfur 

recovery plant with design capacity greater than 20 long tons per 

day and subject to the NSPS for 

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

a. 250 ppmv (dry basis) SO2 at 

zero percent excess air, or concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by incineration.

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and each 12-hour rolling average concentration of SO2 emissions measured by the continuous emission 

monitoring system is less than or equal to 250 ppmv (dry basis) at 

zero percent excess air, or the concentration determined using 

Equation 1 of 40 CFR 60.102a(f)(1)(i). As part of the Notification of 

Compliance Status, you must certify that your vent meets the SO2

limit. You are not required to do another performance test to demonstrate initial compliance. 

You have already conducted a performance evaluation to demonstrate initial compliance with the applicable performance specification. As part of your Notification of Compliance Status, you 

must certify that your continuous emission monitoring system 

meets the applicable requirements in § 63.1572. You are not required to do another performance evaluation to demonstrate initial 

compliance. 

b. 300 ppmv of reduced sulfur 

compounds calculated as ppmv 

SO2 (dry basis) at zero percent 

excess air, or concentration determined using Equation 1 of 40 

CFR 60.102a(f)(1)(i), if you use 

a reduction control system without incineration.

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and each 12-hour rolling average concentration of reduced sulfur compounds measured by your continuous emission monitoring system is less than or equal to 300 

ppmv, calculated as ppmv SO2 (dry basis) at zero percent excess 

air, or the concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i). As part of the Notification of Compliance Status, 

you must certify that your vent meets the SO2 limit. You are not required to do another performance test to demonstrate initial compliance. 

You have already conducted a performance evaluation to demonstrate initial compliance with the applicable performance specification. As part of your Notification of Compliance Status, you 

must certify that your continuous emission monitoring system 

meets the applicable requirements in § 63.1572. You are not required to do another performance evaluation to demonstrate initial 

compliance. 

2. Option 1: Elect NSPS. Each new 

or existing sulfur recovery unit 

(Claus or other type, regardless 

of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at 

zero percent excess air, or concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by incineration.

Each 12-hour rolling average concentration of SO2 emissions measured by the continuous emission monitoring system during the initial performance test is less than or equal to 250 ppmv (dry basis) 

at zero percent excess air, or the concentration determined using 

Equation 1 of 40 CFR 60.102a(f)(1)(i); and your performance evaluation shows the monitoring system meets the applicable requirements in § 63.1572. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37038 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY

UNITS—Continued 

For . . . For the following emission 

limit . . . You have demonstrated initial compliance if . . . 

b. 300 ppmv of reduced sulfur 

compounds calculated as ppmv 

SO2 (dry basis) at zero percent 

excess air, or concentration determined using Equation 1 of 40 

CFR 60.102a(f)(1)(i), if you use 

a reduction control system without incineration.

Each 12-hour rolling average concentration of reduced sulfur compounds measured by the continuous emission monitoring system 

during the initial performance test is less than or equal to 300 

ppmv, calculated as ppmv SO2 (dry basis) at zero percent excess 

air, or the concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i); and your performance evaluation shows the continuous emission monitoring system meets the applicable requirements in § 63.1572. 

3. Option 2: TRS limit. Each new or 

existing sulfur recovery unit 

(Claus or other type, regardless 

of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

300 ppmv of TRS compounds expressed as an equivalent SO2

concentration (dry basis) at zero 

percent oxygen.

If you use continuous parameter monitoring systems, the average 

concentration of TRS emissions measured using Method 15 during 

the initial performance test is less than or equal to 300 ppmv expressed as equivalent SO2 concentration (dry basis) at zero percent oxygen. If you use a continuous emission monitoring system, 

each 12-hour rolling average concentration of TRS emissions 

measured by the continuous emission monitoring system during 

the initial performance test is less than or equal to 300 ppmv expressed as an equivalent SO2 (dry basis) at zero percent oxygen; 

and your performance evaluation shows the continuous emission 

monitoring system meets the applicable requirements in § 63.1572. 

■ 82. Table 34 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR

RECOVERY UNITS

For . . . For this emission limit . . . You shall demonstrate continuous compliance by . . . 

1. Each new or existing Claus sulfur recovery unit part of a sulfur 

recovery plant with design capacity greater than 20 long tons per 

day and subject to the NSPS for 

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at 

zero percent excess air, or concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by incineration.

Collecting the hourly average SO2 monitoring data (dry basis, percent 

excess air) according to § 63.1572; determining and recording each 

12-hour rolling average concentration of SO2; maintaining each 12- 

hour rolling average concentration of SO2 at or below the applicable emission limitation; and reporting any 12-hour rolling average 

concentration of SO2 greater than the applicable emission limitation 

in the semiannual compliance report required by § 63.1575. 

b. 300 ppmv of reduced sulfur 

compounds calculated as ppmv 

SO2 (dry basis) at zero percent 

excess air, or concentration determined using Equation 1 of 40 

CFR 60.102a(f)(1)(i), if you use 

a reduction control system without incineration.

Collecting the hourly average reduced sulfur (and air or O2 dilution 

and oxidation) monitoring data according to § 63.1572; determining 

and recording each 12-hour rolling average concentration of reduced sulfur; maintaining each 12-hour rolling average concentration of reduced sulfur at or below the applicable emission limitation; 

and reporting any 12-hour rolling average concentration of reduced 

sulfur greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. 

2. Option 1: Elect NSPS. Each new 

or existing sulfur recovery unit 

(Claus or other type, regardless 

of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at 

zero percent excess air, or concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by incineration.

Collecting the hourly average SO2 data (dry basis, percent excess 

air) according to § 63.1572; determining and recording each 12- 

hour rolling average concentration of SO2; maintaining each 12- 

hour rolling average concentration of SO2 at or below the applicable emission limitation; and reporting any 12-hour rolling average 

concentration of SO2 greater than the applicable emission limitation 

in the semiannual compliance report required by § 63.1575. 

b. 300 ppmv of reduced sulfur 

compounds calculated as ppmv 

SO2 (dry basis) at zero percent 

excess air, or concentration determined using Equation 1 of 40 

CFR 60.102a(f)(1)(i), if you use 

a reduction control system without incineration.

Collecting the hourly average reduced sulfur (and air or O2 dilution 

and oxidation) monitoring data according to § 63.1572; determining 

and recording each 12-hour rolling average concentration of reduced sulfur; maintaining each 12-hour rolling average concentration of reduced sulfur at or below the applicable emission limitation; 

and reporting any 12-hour rolling average concentration of reduced 

sulfur greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. 

3. Option 2: TRS limit. Each new or 

existing sulfur recovery unit 

(Claus or other type, regardless 

of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

300 ppmv of TRS compounds, expressed as an SO2 concentration (dry basis) at zero percent 

oxygen or reduced sulfur compounds calculated as ppmv SO2

(dry basis) at zero percent excess air.

i. If you use continuous parameter monitoring systems, collecting the 

hourly average TRS monitoring data according to § 63.1572 and 

maintaining each 12-hour average concentration of TRS at or 

below the applicable emission limitation; or 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37039 

TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR

RECOVERY UNITS—Continued 

For . . . For this emission limit . . . You shall demonstrate continuous compliance by . . . 

ii. If you use a continuous emission monitoring system, collecting the 

hourly average TRS monitoring data according to § 63.1572, determining and recording each 12-hour rolling average concentration of 

TRS; maintaining each 12-hour rolling average concentration of 

TRS at or below the applicable emission limitation; and reporting 

any 12-hour rolling average TRS concentration greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. 

■ 83. Table 35 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS

FROM SULFUR RECOVERY UNITS

For . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

1. Each new or existing Claus sulfur recovery unit part of a sulfur 

recovery plant with design capacity greater than 20 long tons per 

day and subject to the NSPS for 

sulfur oxides in paragraph 40 

CFR 60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

Not applicable ................................ Meeting the requirements of Table 34 of this subpart. 

2. Option 1: Elect NSPS. Each new 

or existing sulfur recovery unit 

(Claus or other type, regardless 

of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

Not applicable ................................ Meeting the requirements of Table 34 of this subpart. 

3. Option 2: TRS limit. Each new or 

existing sulfur recovery unit 

(Claus or other type, regardless 

of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

a. Maintain the daily average combustion zone temperature above 

the level established during the 

performance test.

Collecting the hourly and daily average temperature monitoring data 

according to § 63.1572; and maintaining the daily average combustion zone temperature at or above the limit established during the 

performance test. 

b. The daily average oxygen concentration in the vent stream 

(percent, dry basis) must not fall 

below the level established during the performance test.

Collecting the hourly and daily average O2 monitoring data according 

to § 63.1572; and maintaining the average O2 concentration above 

the level established during the performance test. 

■ 84. Table 40 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1572(a)(1) and (b)(1), 

you shall meet each requirement in the 

following table that applies to you. 

TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS

This type of continuous opacity or emission 

monitoring system . . . Must meet these requirements . . . 

1. Continuous opacity monitoring system ........... Performance specification 1 (40 CFR part 60, Appendix B). 

2. PM CEMS; this monitor must include an O2

monitor for correcting the data for excess air.

The requirements in 40 CFR 60.105a(d). 

3. CO2, O2, and CO monitors for coke burn-off 

rate.

The requirements in 40 CFR 60.105a(b)(2). 

4. CO continuous emission monitoring system .. Performance specification 4 (40 CFR part 60, Appendix B); span value of 1,000 ppm; and procedure 1 (40 CFR part 60, Appendix F) except relative accuracy test audits are required annually instead of quarterly. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37040 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS—Continued 

This type of continuous opacity or emission 

monitoring system . . . Must meet these requirements . . . 

5. CO continuous emission monitoring system 

used to demonstrate emissions average 

under 50 ppm (dry basis).

Performance specification 4 (40 CFR part 60, Appendix B); and span value of 100 ppm. 

6. SO2 continuous emission monitoring system 

for sulfur recovery unit with oxidation control 

system or reduction control system; this monitor must include an O2 monitor for correcting 

the data for excess air.

Performance specification 2 (40 CFR part 60, Appendix B); span value of 500 ppm SO2, or if 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest 

O2 concentration; use Methods 6 or 6C (40 CFR part 60, Appendix A–4) for certifying the 

SO2 monitor and Methods 3A or 3B (40 CFR part 60, Appendix A–2) for certifying the O2

monitor; and procedure 1 (40 CFR part 60, Appendix F) except relative accuracy test audits 

are required annually instead of quarterly. 

7. Reduced sulfur and O2 continuous emission 

monitoring system for sulfur recovery unit with 

reduction control system not followed by incineration; this monitor must include an O2

monitor for correcting the data for excess air 

unless exempted.

Performance specification 5 (40 CFR part 60, Appendix B), except calibration drift specification is 2.5 percent of the span value instead of 5 percent; span value is 450 ppm reduced 

sulfur, or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at 

the highest O2 concentration; use Methods 15 or 15A (40 CFR part 60, Appendix A–5) for 

certifying the reduced sulfur monitor and Methods 3A or 3B (40 CFR part 60, Appendix A– 

2) for certifying the O2 monitor; if Method 3A or 3B yields O2 concentrations below 0.25 percent during the performance evaluation, the O2 concentration can be assumed to be zero 

and the O2 monitor is not required; and procedure 1 (40 CFR part 60, Appendix F), except 

relative accuracy test audits, are required annually instead of quarterly. 

8. Instrument with an air or O2 dilution and oxidation system to convert reduced sulfur to 

SO2 for continuously monitoring the concentration of SO2 instead of reduced sulfur 

monitor and O2 monitor.

Performance specification 5 (40 CFR part 60, Appendix B); span value of 375 ppm SO2 or if 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest 

O2 concentration; use Methods 15 or 15A for certifying the reduced sulfur monitor and 3A or 

3B for certifying the O2 monitor; and procedure 1 (40 CFR part 60, Appendix F), except relative accuracy test audits, are required annually instead of quarterly. 

9. TRS continuous emission monitoring system 

for sulfur recovery unit; this monitor must include an O2 monitor for correcting the data for 

excess air.

Performance specification 5 (40 CFR part 60, Appendix B). 

10. O2 monitor for oxygen concentration ............ If necessary due to interferences, locate the oxygen sensor prior to the introduction of any 

outside gas stream; performance specification 3 (40 CFR part 60, Appendix B; and procedure 1 (40 CFR part 60, Appendix F), except relative accuracy test audits, are required annually instead of quarterly. 

11. O2 monitor for oxygen concentration in inlet 

or supply.

Install, operate, and maintain each O2 monitor according to Performance Specification 3 of 

Appendix B to part 60; the span value for the O2 monitor must be selected between 20 and 

100 percent; conduct performance evaluations for O2 monitor according to Performance 

Specification 3 of Appendix B to part 60, and must use Method 3A or 3B of Appendix A–2 

to part 60 for conducting relative accuracy evaluations; comply with applicable quality assurance procedures of Appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 monitor and daily calibration drift determinations. 

■ 85. Table 41 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1572(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS PARAMETER MONITORING SYSTEMS

If you use . . . You shall . . . 

1. pH strips ...................................... Use pH strips with an accuracy of ±10 percent. 

2. pH meter ..................................... Locate the pH sensor in a position that provides a representative measurement of pH; ensure the sample 

is properly mixed and representative of the fluid to be measured. 

Use a pH sensor with an accuracy of at least ±0.2 pH units. 

Check the pH meter’s calibration on at least one point at least once daily; check the pH meter’s calibration 

on at least two points at least once quarterly; at least monthly, inspect all components for integrity and 

all electrical components for continuity; record the results of each calibration check and inspection. 

3. Colormetric tube sampling system.Use a colormetric tube sampling system with a printed numerical scale in ppmv, a standard measurement 

range of 1 to 10 ppmv (or 1 to 30 ppmv if applicable), and a standard deviation for measured values of 

no more than ±15 percent. System must include a gas detection pump and hot air probe if needed for 

the measurement range. 

4. BLD ............................................. Follow the requirements in 40 CFR 60.105a(c). 

5. Voltage, secondary current, or 

total power input sensors.

Use meters with an accuracy of at least ± 5 percent over the operating range. 

Each time that the unit is not operating, confirm that the meters read zero. Conduct a calibration check at 

least annually; conduct calibration checks following any period of more than 24 hours throughout which 

the meter exceeds the manufacturer’s specified maximum operating range; at least monthly, inspect all 

components of the continuous parameter monitoring system for integrity and all electrical connections for 

continuity; and record the results of each calibration check and inspection. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37041 

TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS PARAMETER MONITORING SYSTEMS—Continued 

If you use . . . You shall . . . 

6. Pressure/Pressure drop 1 sensors.Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure; 

minimizes or eliminates pulsating pressure, vibration, and internal and external corrosion. 

Use a gauge with an accuracy of at least ± 5 percent over the operating range or 0.5 inches of water column, whichever is greater. 

Check pressure tap for plugs at least once a week; using a manometer, check gauge calibration quarterly 

and transducer calibration monthly; conduct calibration checks following any period of more than 24 

hours throughout which the sensor exceeds the manufacturer’s specified maximum operating pressure 

range or install a new pressure sensor; at least monthly, inspect all components for integrity, all electrical connections for continuity, and all mechanical connections for leakage; record the results of each 

calibration check and inspection. 

7. Air flow rate, gas flow rate, or 

total water (or scrubbing liquid) 

flow rate sensors.

Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that 

provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and 

downstream disturbances. If you elect to comply with Option 3 (Ni lb/hr) or Option 4 (Ni lb/1,000 lb of 

coke burn-off) for the HAP metal emission limitations in § 63.1564, install the continuous parameter monitoring system for gas flow rate as close as practical to the continuous opacity monitoring system; and if 

you don’t use a continuous opacity monitoring system, install the continuous parameter monitoring system for gas flow rate as close as practical to the control device. 

Use a flow rate sensor with an accuracy of at least ±5 percent, or 0.5 gallons per minute for liquid flow, or 

10 cubic feet per minute for gas flow, whichever is greater. 

Conduct a flow sensor calibration check at least semiannually; conduct calibration checks following any period of more than 24 hours throughout which the sensor exceeds the manufacturer’s specified maximum 

operating range or install a new flow sensor; at least monthly, inspect all components for leakage; record 

the results of each calibration check and inspection. 

8. Temperature sensors .................. Locate the temperature sensor in the combustion zone, or in the ductwork immediately downstream of the 

combustion zone before any substantial heat exchange occurs or in the ductwork immediately downstream of the regenerator; locate the temperature sensor in a position that provides a representative 

temperature; shield the temperature sensor system from electromagnetic interference and chemical contaminants. 

Use a temperature sensor with an accuracy of at least ±1 percent of the temperature being measured, expressed in degrees Celsius (C) or 2.8 degrees C, whichever is greater. 

Conduct calibration checks at least annually; conduct calibration checks following any period of more than 

24 hours throughout which the sensor exceeds the manufacturer’s specified maximum operating temperature range, or install a new temperature sensor; at least monthly, inspect all components for integrity 

and all electrical connections for continuity, oxidation, and galvanic corrosion; record the results of each 

calibration check and inspection. 

9. Oxygen content sensors 2 ........... Locate the oxygen sensor so that it provides a representative measurement of the oxygen content of the 

exit gas stream; ensure the sample is properly mixed and representative of the gas to be measured. 

Use an oxygen sensor with an accuracy of at least ±1 percent of the range of the sensor. 

Conduct calibration checks at least quarterly; conduct calibration checks following any period of more than 

24 hours throughout which the sensor exceeds the manufacturer’s specified maximum operating range, 

or install a new oxygen sensor; at least monthly, inspect all components for integrity and all electrical 

connections for continuity; record the results of each calibration and inspection. 

1 Not applicable to non-venturi wet scrubbers of the jet-ejector design. 

2This does not replace the requirements for oxygen monitors that are required to use continuous emissions monitoring systems. These requirements apply to oxygen sensors that are continuous parameter monitors, such as those that monitor combustion zone oxygen concentration 

and regenerator exit oxygen concentration. 

■ 86. Table 43 to subpart UUU is revised 

to read as follows: 

As stated in § 63.1575(a), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 43 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR REPORTS

You must submit . . . The report must contain . . . You shall submit the report . . . 

1. A compliance report .................... If there are not deviations from any emission limitation or work practice standard that applies to you, a statement that there were no 

deviations from the standards during the reporting period and that 

no continuous opacity monitoring system or continuous emission 

monitoring system was inoperative, inactive, out-of-control, repaired, or adjusted; if you have a deviation from any emission limitation or work practice standard during the reporting period, the report must contain the information in § 63.1575(c) through (e).

Semiannually according to the requirements in § 63.1575(b). 

2. Performance test and CEMS 

performance evaluation data.

On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the information specified in § 63.1575(k)(1).

Within 60 days after the date of 

completing each test according 

to the requirements in 

§ 63.1575(k). 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37042 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

■ 87. Table 44 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1577, you shall meet 

each requirement in the following table 

that applies to you. 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU 

Citation Subject Applies to subpart UUU Explanation 

§ 63.1(a)(1)–(4) .................... General Applicability .......... Yes.

§ 63.1(a)(5) .......................... [Reserved] ......................... Not applicable 

§ 63.1(a)(6) .......................... Yes .................................... Except the correct mail drop (MD) number is C404– 

04. 

§ 63.1(a)(7)–(9) .................... [Reserved] ......................... Not applicable 

§ 63.1(a)(10)–(12) ................ Yes .................................... Except that subpart UUU specifies calendar or operating day. 

§ 63.1(b)(1) .......................... Initial Applicability Determination for this part.Yes 

§ 63.1(b)(2) .......................... [Reserved] ......................... Not applicable 

§ 63.1(b)(3) .......................... Yes 

§ 63.1(c)(1) ........................... Applicability of this part 

after a Relevant Standard has been set under 

this part.

Yes 

§ 63.1(c)(2) ........................... No ...................................... Area sources are not subject to subpart UUU. 

§ 63.1(c)(3)–(4) .................... [Reserved] ......................... Not applicable 

§ 63.1(c)(5) ........................... Yes 

§ 63.1(d) ............................... [Reserved] ......................... Not applicable 

§ 63.1(e) ............................... Applicability of Permit Program.Yes 

§ 63.2 ................................... Definitions .......................... Yes .................................... § 63.1579 of subpart UUU specifies that if the same 

term is defined in subparts A and UUU, it shall have 

the meaning given in subpart UUU. 

§ 63.3 ................................... Units and Abbreviations .... Yes 

§ 63.4(a)(1)–(2) .................... Prohibited Activities Yes ....................................

§ 63.4(a)(3)–(5) .................... [Reserved] ......................... Not applicable 

§ 63.4(b)–(c) ......................... Circumvention and Fragmentation.Yes 

§ 63.5(a) ............................... Construction and Reconstruction Yes 

§ 63.5(b)(1) .......................... Yes 

§ 63.5(b)(2) .......................... [Reserved] ......................... Not applicable 

§ 63.5(b)(3)–(4) .................... Yes .................................... In § 63.5(b)(4), replace the reference to § 63.9(b) with 

§ 63.9(b)(4) and (5). 

§ 63.5(b)(5) .......................... [Reserved] ......................... Not applicable 

§ 63.5(b)(6) .......................... Yes 

§ 63.5(c) ............................... [Reserved] ......................... Not applicable 

§ 63.5(d)(1)(i) ....................... Application for Approval of 

Construction or Reconstruction—General Application Requirements.

Yes .................................... Except subpart UUU specifies the application is submitted as soon as practicable before startup but not 

later than 90 days after the promulgation date if 

construction or reconstruction had commenced and 

initial startup had not occurred before promulgation. 

§ 63.5(d)(1)(ii) ...................... Yes .................................... Except that emission estimates specified in 

§ 63.5(d)(1)(ii)(H) are not required, and 

§ 63.5(d)(1)(ii)(G) and (I) are Reserved and do not 

apply. 

§ 63.5(d)(1)(iii) ...................... No ...................................... Subpart UUU specifies submission of notification of 

compliance status. 

§ 63.5(d)(2) .......................... Yes 

§ 63.5(d)(3) .......................... Yes 

§ 63.5(d)(4) .......................... Yes 

§ 63.5(e) ............................... Approval of Construction or 

Reconstruction.

Yes 

§ 63.5(f)(1) ........................... Approval of Construction or 

Reconstruction Based on 

State Review.

Yes 

§ 63.5(f)(2) ........................... Yes .................................... Except that the cross-reference to § 63.9(b)(2) does 

not apply. 

§ 63.6(a) ............................... Compliance with Standards 

and Maintenance—Applicability.

Yes 

§ 63.6(b)(1)–(4) .................... Compliance Dates for New 

and Reconstructed 

Sources.

Yes 

§ 63.6(b)(5) .......................... Yes .................................... Except that subpart UUU specifies different compliance dates for sources. 

§ 63.6(b)(6) .......................... [Reserved] ......................... Not applicable 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37043 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart UUU Explanation 

§ 63.6(b)(7) .......................... Compliance Dates for New 

and Reconstructed Area 

Sources That Become 

Major.

Yes 

§ 63.6(c)(1)–(2) .................... Compliance Dates for Existing Sources.Yes .................................... Except that subpart UUU specifies different compliance dates for sources subject to Tier II gasoline 

sulfur control requirements. 

§ 63.6(c)(3)–(4) .................... [Reserved] ......................... Not applicable 

§ 63.6(c)(5) ........................... Compliance Dates for Existing Area Sources That 

Become Major.

Yes 

§ 63.6(d) ............................... [Reserved] ......................... Not applicable 

§ 63.6(e)(1)(i) ....................... General Duty to Minimize 

Emissions.

No ...................................... See § 63.1570(c) for general duty requirement. 

§ 63.6(e)(1)(ii) ...................... Requirement to Correct 

Malfunctions as Soon as 

Possible.

No 

§ 63.6(e)(1)(iii) ...................... Compliance with Standards 

and Maintenance Requirements.

Yes 

§ 63.6(e)(2) .......................... [Reserved] ......................... Not applicable 

§ 63.6(e)(3)(i) ....................... Startup, Shutdown, and 

Malfunction Plan Requirements.

No 

§ 63.6(e)(3)(ii) ...................... [Reserved] ......................... Not applicable 

§ 63.6(e)(3)(iii)–(ix) ............... No 

§ 63.6(f)(1) ........................... SSM Exemption ................. No 

§ 63.6(f)(2)(i)–(iii)(C) ............ Compliance with Standards 

and Maintenance Requirements.

Yes 

§ 63.6(f)(2)(iii)(D) .................. Yes 

§ 63.6(f)(2)(iv)–(v) ................ Yes 

§ 63.6(f)(3) ........................... Yes .................................... Except the cross-references to § 63.6(f)(1) and 

§ 63.6(e)(1)(i) are changed to § 63.1570(c). 

§ 63.6(g) ............................... Alternative Standard .......... Yes 

§ 63.6(h)(1) .......................... SSM Exemption for Opacity/VE Standards.No 

§ 63.6(h)(2)(i) ....................... Determining Compliance 

with Opacity/VE Standards.

No ...................................... Subpart UUU specifies methods. 

§ 63.6(h)(2)(ii) ...................... [Reserved] ......................... Not applicable 

§ 63.6(h)(2)(iii) ...................... Yes 

§ 63.6(h)(3) .......................... [Reserved] ......................... Not applicable 

§ 63.6(h)(4) .......................... Notification of Opacity/VE 

Observation Date.

Yes .................................... Applies to Method 22 tests. 

§ 63.6(h)(5) .......................... Conducting Opacity/VE 

Observations.

No 

§ 63.6(h)(6) .......................... Records of Conditions During Opacity/VE Observations.Yes .................................... Applies to Method 22 observations. 

§ 63.6(h)(7)(i) ....................... Report COM Monitoring 

Data from Performance 

Test.

Yes 

§ 63.6(h)(7)(ii) ...................... Using COM Instead of 

Method 9.

No 

§ 63.6(h)(7)(iii) ...................... Averaging Time for COM 

during Performance Test.

Yes 

§ 63.6(h)(7)(iv) ..................... COM Requirements ........... Yes 

§ 63.6(h)(7)(v) ...................... COMS Results and Visual 

Observations.

Yes 

§ 63.6(h)(8) .......................... Determining Compliance 

with Opacity/VE Standards.

Yes 

§ 63.6(h)(9) .......................... Adjusted Opacity Standard Yes 

§ 63.6(i)(1)–(14) ................... Extension of Compliance .. Yes .................................... Extension of compliance under § 63.6(i)(4) not applicable to a facility that installs catalytic cracking feed 

hydrotreating and receives an extended compliance 

date under § 63.1563(c). 

§ 63.6(i)(15) .......................... [Reserved] ......................... Not applicable 

§ 63.6(i)(16) .......................... Yes 


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37044 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart UUU Explanation 

§ 63.6(j) ................................ Presidential Compliance 

Exemption.

Yes 

§ 63.7(a)(1) .......................... Performance Test Requirements Applicability.Yes .................................... Except that subpart UUU specifies the applicable test 

and demonstration procedures. 

§ 63.7(a)(2) .......................... Performance Test Dates ... Yes .................................... Except test results must be submitted in the Notification of Compliance Status report due 150 days after 

the compliance date. 

§ 63.7(a)(3) .......................... Section 114 Authority ........ Yes 

§ 63.7(a)(4) .......................... Force Majeure ................... Yes 

§ 63.7(b) ............................... Notifications ....................... Yes .................................... Except that subpart UUU specifies notification at least 

30 days prior to the scheduled test date rather than 

60 days. 

§ 63.7(c) ............................... Quality Assurance Program/Site-Specific Test 

Plan.

Yes 

§ 63.7(d) ............................... Performance Test Facilities Yes 

§ 63.7(e)(1) .......................... Performance Testing ......... No ...................................... See § 63.1571(b)(1). 

§ 63.7(e)(2)–(4) .................... Conduct of Tests ............... Yes 

§ 63.7(f) ................................ Alternative Test Method .... Yes 

§ 63.7(g) ............................... Data Analysis, Recordkeeping, Reporting.Yes .................................... Except performance test reports must be submitted 

with notification of compliance status due 150 days 

after the compliance date, and § 63.7(g)(2) is Reserved and does not apply. 

§ 63.7(h) ............................... Waiver of Tests ................. Yes 

§ 63.8(a)(1) .......................... Monitoring Requirements— 

Applicability.

Yes 

§ 63.8(a)(2) .......................... Performance Specifications Yes 

§ 63.8(a)(3) .......................... [Reserved] ......................... Not applicable 

§ 63.8(a)(4) .......................... Monitoring with Flares ....... Yes .................................... Except that for a flare complying with § 63.670, the 

cross-reference to § 63.11 in this paragraph does 

not include § 63.11(b). 

§ 63.8(b)(1) .......................... Conduct of Monitoring ....... Yes 

§ 63.8(b)(2)–(3) .................... Multiple Effluents and Multiple Monitoring Systems.Yes .................................... Subpart UUU specifies the required monitoring locations. 

§ 63.8(c)(1) ........................... Monitoring System Operation and Maintenance.Yes 

§ 63.8(c)(1)(i) ....................... General Duty to Minimize 

Emissions and CMS Operation.

No ...................................... See § 63.1570(c). 

§ 63.8(c)(1)(ii) ....................... Keep Necessary Parts for 

CMS.

Yes 

§ 63.8(c)(1)(iii) ...................... Requirement to Develop 

SSM Plan for CMS.

No 

§ 63.8(c)(2)–(3) .................... Monitoring System Installation.Yes .................................... Except that subpart UUU specifies that for continuous 

parameter monitoring systems, operational status 

verification includes completion of manufacturer written specifications or installation, operation, and calibration of the system or other written procedures 

that provide adequate assurance that the equipment 

will monitor accurately. 

§ 63.8(c)(4) ........................... Continuous Monitoring 

System Requirements.

Yes 

§ 63.8(c)(5) ........................... COMS Minimum Procedures.Yes 

§ 63.8(c)(6) ........................... CMS Requirements ........... Yes 

§ 63.8(c)(7)–(8) .................... CMS Requirements ........... Yes 

§ 63.8(d)(1)–(2) .................... Quality Control Program 

for CMS.

Yes 

§ 63.8(d)(3) .......................... Written Procedures for 

CMS.

No 

§ 63.8(e) ............................... CMS Performance Evaluation.Yes .................................... Except that results are to be submitted as part of the 

Notification Compliance Status due 150 days after 

the compliance date. 

§ 63.8(f)(1)–(5) ..................... Alternative Monitoring 

Methods.

Yes .................................... Except that subpart UUU specifies procedures for requesting alternative monitoring systems and alternative parameters. 

§ 63.8(f)(6) ........................... Alternative to Relative Accuracy Test.Yes .................................... Applicable to continuous emission monitoring systems 

if performance specification requires a relative accuracy test audit. 

§ 63.8(g)(1)–(4) .................... Reduction of Monitoring 

Data.

Yes .................................... Applies to continuous opacity monitoring system or 

continuous emission monitoring system. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37045 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart UUU Explanation 

§ 63.8(g)(5) .......................... Data Reduction .................. No ...................................... Subpart UUU specifies requirements. 

§ 63.9(a) ............................... Notification Requirements—Applicability.Yes .................................... Duplicate Notification of Compliance Status report to 

the Regional Administrator may be required. 

§ 63.9(b)(1)–(2) .................... Initial Notifications ............. Yes .................................... Except that notification of construction or reconstruction is to be submitted as soon as practicable before 

startup but no later than 30 days after the effective 

date if construction or reconstruction had commenced but startup had not occurred before the effective date. 

§ 63.9(b)(3) .......................... [Reserved] ......................... Not applicable 

§ 63.9(b)(4)–(5) .................... Initial Notification Information.Yes .................................... Except § 63.9(b)(4)(ii)–(iv), which are Reserved and do 

not apply. 

§ 63.9(c) ............................... Request for Extension of 

Compliance.

Yes 

§ 63.9(d) ............................... New Source Notification for 

Special Compliance Requirements.

Yes 

§ 63.9(e) ............................... Notification of Performance 

Test.

Yes .................................... Except that notification is required at least 30 days before test. 

§ 63.9(f) ................................ Notification of VE/Opacity 

Test.

Yes 

§ 63.9(g) ............................... Additional Notification Requirements for Sources 

with Continuous Monitoring Systems.

Yes 

§ 63.9(h) ............................... Notification of Compliance 

Status.

Yes .................................... Except that subpart UUU specifies the notification is 

due no later than 150 days after compliance date, 

and except that the reference to § 63.5(d)(1)(ii)(H) in 

§ 63.9(h)(5) does not apply. 

§ 63.9(i) ................................ Adjustment of Deadlines ... Yes 

§ 63.9(j) ................................ Change in Previous Information.Yes 

63.10(a) ............................... Recordkeeping and Reporting Applicability.Yes 

§ 63.10(b)(1) ........................ General Recordkeeping 

Requirements.

Yes 

§ 63.10(b)(2)(i) ..................... Recordkeeping of Occurrence and Duration of 

Startups and Shutdowns.

No 

§ 63.10(b)(2)(ii) .................... Recordkeeping of Malfunctions.No ...................................... See § 63.1576(a)(2) for recordkeeping of (1) date, time 

and duration; (2) listing of affected source or equipment, and an estimate of the volume of each regulated pollutant emitted over the standard; and (3) 

actions taken to minimize emissions and correct the 

failure. 

§ 63.10(b)(2)(iii) .................... Maintenance Records ....... Yes 

§ 63.10(b)(2)(iv)–(v) ............. Actions Taken to Minimize 

Emissions During SSM.

No 

§ 63.10(b)(2)(vi) ................... Recordkeeping for CMS 

Malfunctions.

Yes 

§ 63.10(b)(2)(vii)–(xiv) .......... Other CMS Requirements Yes 

§ 63.10(b)(3) ........................ Recordkeeping for Applicability Determinations..Yes 

§ 63.10(c)(1)–(6) .................. Additional Records for 

Continuous Monitoring 

Systems.

Yes .................................... Except § 63.10(c)(2)–(4), which are Reserved and do 

not apply. 

§ 63.10(c)(7)–(8) .................. Additional Recordkeeping 

Requirements for CMS— 

Identifying Exceedances 

and Excess Emissions.

Yes 

§ 63.10(c)(9) ......................... [Reserved] ......................... Not applicable 

§ 63.10(c)(10) ....................... Recording Nature and 

Cause of Malfunctions.

No ...................................... See § 63.1576(a)(2) for malfunctions recordkeeping requirements. 

§ 63.10(c)(11) ....................... Recording Corrective Actions.No ...................................... See § 63.1576(a)(2) for malfunctions recordkeeping requirements. 

§ 63.10(c)(12)–(14) .............. Additional CMS Recordkeeping Requirements.Yes 

§ 63.10(c)(15) ....................... Use of SSM Plan ............... No 

§ 63.10(d)(1) ........................ General Reporting Requirements.Yes 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
37046 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart UUU Explanation 

§ 63.10(d)(2) ........................ Performance Test Results No ...................................... Subpart UUU requires performance test results to be 

reported as part of the Notification of Compliance 

Status due 150 days after the compliance date. 

§ 63.10(d)(3) ........................ Opacity or VE Observations.Yes 

§ 63.10(d)(4) ........................ Progress Reports .............. Yes 

§ 63.10(d)(5) ........................ SSM Reports ..................... No ...................................... See § 63.1575(d) for CPMS malfunction reporting and 

§ 63.1575(e) for COMS and CEMS malfunction reporting. 

§ 63.10(e)(1)–(2) .................. Additional CMS Reports .... Yes .................................... Except that reports of performance evaluations must 

be submitted in Notification of Compliance Status. 

§ 63.10(e)(3) ........................ Excess Emissions/CMS 

Performance Reports.

No ...................................... Subpart UUU specifies the applicable requirements. 

§ 63.10(e)(4) ........................ COMS Data Reports ......... Yes 

§ 63.10(f) .............................. Recordkeeping/Reporting 

Waiver.

Yes 

§ 63.11(a) ............................. Control Device and Work 

Practice Requirements— 

Applicability.

Yes 

§ 63.11(b) ............................. Flares ................................. Yes .................................... Except that flares complying with § 63.670 are not 

subject to the requirements of § 63.11(b). 

§ 63.11(c)-(e) ....................... Alternative Work Practice 

for Monitoring Equipment 

for Leaks.

Yes 

§ 63.12 ................................. State Authority and Delegations.Yes 

§ 63.13 ................................. Addresses .......................... Yes 

§ 63.14 ................................. Incorporation by Reference Yes 

§ 63.15 ................................. Availability of Information 

and Confidentiality.

Yes 

§ 63.16 ................................. Performance Track Provisions.Yes 

■ 88. Appendix A to subpart UUU of 

part 63 is amended by: 

■ a. Revising the first sentence of 

section 2.1; and 

■ b. Revising section 7.1.3. 

The revisions read as follows: 

Appendix A to Subpart UUU of Part 

63—Determination of Metal 

Concentration on Catalyst Particles 

(Instrumental Analyzer Procedure) 

* * * * * 

2.1 A representative sample of catalyst 

particles is collected, prepared, and analyzed 

for analyte concentration using either energy 

or wavelength dispersive X-ray fluorescent 

(XRF) spectrometry instrumental analyzers. 

* * * 

* * * * * 

7.1.3 Low-Range Calibration Standard. 

Concentration equivalent to 1 to 20 percent 

of the span. The concentration of the lowrange calibration standard should be selected 

so that it is less than either one-fourth of the 

applicable concentration limit or of the 

lowest concentration anticipated in the 

catalyst samples. 

* * * * * 

Appendix A to Part 63—[AMENDED] 

■ 89. Appendix A to part 63 is amended 

by adding Method 325A and Method 

325B to read as follows: 

Method 325A—Volatile Organic Compounds 

From Fugitive and Area Sources 

Sampler Deployment and VOC Sample 

Collection 

1.0 Scope and Application 

1.1 This method describes collection of 

volatile organic compounds (VOCs) at a 

facility property boundary or from fugitive 

and area emission sources using passive 

(diffusive) tube samplers (PS). The 

concentration of airborne VOCs at or near 

these potential fugitive- or area-emission 

sources may be determined using this 

method in combination with Method 325B. 

Companion Method 325B (Sampler 

Preparation and Analysis) describes 

preparation of sampling tubes, shipment and 

storage of exposed sampling tubes, and 

analysis of sampling tubes collected using 

either this passive sampling procedure or 

alternative active (pumped) sampling 

methods. 

1.2 This method may be used to 

determine the average concentration of the 

select VOCs and corresponding uptake rates 

listed in Method 325B, Table 12.1. 

Additional compounds or alternative 

sorbents must be evaluated as described in 

Addendum A of Method 325B unless the 

compound or sorbent has already been 

validated and reported in one of the 

following national/international standard 

methods: ISO 16017–2:2003 (incorporated by 

reference—see § 63.14), ASTM D6196– 

03(2009) (incorporated by reference—see 

§ 63.14), or BS EN 14662–4:2005 

(incorporated by reference—see § 63.14), or 

in the peer-reviewed open literature. 

1.3 Methods 325A and 325B are valid for 

the measurement of benzene. Supporting 

literature (References 1–8) indicates that 

benzene can be measured by flame ionization 

detection or mass spectrometry over a 

concentration range of approximately 0.5 

micrograms per cubic meter (mg/m3) to at 

least 500 mg/m3 when industry standard (3.5 

inch long x 0.25 inch outside diameter (o.d.) 

x 5 mm inner diameter (i.d.)) stainless steel 

sorbent tubes packed with Carbograph 1 

TDTM, Carbopack BTM, or Carbopack X® or 

equivalent are used and when samples are 

accumulated over a period of 14 days. 

1.4 This method may be applied to 

screening average airborne VOC 

concentrations at facility property boundaries 

over an extended period of time using 

multiple sampling episodes (e.g., 26 x 14-day 

sampling episodes). The duration of each 

sampling period must be 14 days. 

1.5 This method requires the collection of 

local meteorological data (wind speed and 

direction, temperature, and barometric 

pressure). Although local meteorology is a 

component of this method, non-regulatory 

applications of this method may use regional 

meteorological data. Such applications risk 

that the results may not identify the precise 

source of the emissions. 


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2.0 Summary of the Method 

2.1 Principle of the Method. The diffusive 

passive sampler collects VOC from air for a 

measured time period at a rate that is 

proportional to the concentration of vapor in 

the air at that location. 

2.1.1 This method describes the 

deployment of prepared passive samplers, 

including determination of the number of 

passive samplers needed for each survey and 

placement of samplers along the fenceline or 

facility boundary depending on the size and 

shape of the site or linear length of the 

boundary. 

2.1.2 The rate of sampling is specific to 

each compound and depends on the 

diffusion constants of that VOC and the 

sampler dimensions/characteristics as 

determined by prior calibration in a standard 

atmosphere (Reference 1). 

2.1.3 The gaseous VOC target compounds 

migrate through a constant diffusion barrier 

(e.g., an air gap of fixed dimensions) at the 

sampling end of the diffusion sampling tube 

and adsorb onto the sorbent. 

2.1.4 Heat and a flow of inert carrier gas 

are then used to extract (desorb) the retained 

VOCs back from the sampling end of the tube 

and transport/transfer them to a gas 

chromatograph (GC) equipped with a 

chromatographic column to separate the 

VOCs and a detector to determine the 

quantity of target VOCs. 

2.1.5 Gaseous or liquid calibration 

standards loaded onto the sampling ends of 

clean sorbent tubes must be used to calibrate 

the analytical equipment. 

2.1.6 This method requires the use of 

field blanks to ensure sample integrity 

associated with shipment, collection, and 

storage of the passive samples. It also 

requires the use of field duplicates to validate 

the sampling process. 

2.1.7 At the end of each sampling period, 

the passive samples are collected, sealed, and 

shipped to a laboratory for analysis of target 

VOCs by thermal desorption gas 

chromatography, as described in Method 

325B. 

2.2 Application of Diffusive Sampling. 

2.2.1 This method requires deployment of 

passive sampling tubes on the facility 

fenceline or property boundaries and 

collection of local meteorological data. It may 

be used to determine average concentration 

of VOC at a facility fenceline or property 

boundaries using time integrated passive 

sampling (Reference 2). 

2.2.2 Collecting samples and 

meteorological data at progressively higher 

frequencies may be employed to resolve 

shorter term concentration fluctuations and 

wind conditions that could introduce 

interfering emissions from other sources. 

2.2.3 This passive sampling method 

provides a low cost approach to screening of 

fugitive or area emissions compared to active 

sampling methods that are based on pumped 

sorbent tubes or time weighted average 

canister sampling. 

2.2.3.1 Additional passive sampling tubes 

may be deployed at different distances from 

the facility property boundary or from the 

geometric center of the fugitive emission 

source. 

2.2.3.2 Additional meteorological 

measurements may also be collected as 

needed to perform preliminary gradientbased assessment of the extent of the 

pollution plume at ground level and the 

effect of ‘‘background’’ sources contributing 

to airborne VOC concentrations at the 

location. 

2.2.4 Time-resolved concentration 

measurements coupled with time-resolved 

meteorological monitoring may be used to 

generate data needed for source 

apportionment procedures and mass flux 

calculations. 

3.0 Definitions 

(See also Section 3.0 of Method 325B.) 

3.1 Fenceline means the property 

boundary of a facility. 

3.2 Passive sampler (PS) means a specific 

type of sorbent tube (defined in this method) 

that has a fixed dimension air (diffusion) gap 

at the sampling end and is sealed at the other 

end. 

3.3 Passive sampling refers to the activity 

of quantitatively collecting VOC on sorbent 

tubes using the process of diffusion. 

3.4 PSi is the annual average for all PS 

concentration results from location i. 

3.5 PSi3 is the set of annual average 

concentration results for PSi and two sorbent 

tubes nearest to the PS location i. 

3.6 PSip is the concentration from the 

sorbent tube at location i for the test period 

or episode p. 

3.7 Retention volume is the maximum 

mass of VOC that can be collected before the 

capacity of the sorbent is exceeded and back 

diffusion of the VOC from the tube occurs. 

3.8 Sampling episode is the length of 

time each passive sampler is exposed during 

field monitoring. The sampling episode for 

this method is 14 days. 

3.9 Sorbent tube (Also referred to as tube, 

PS tube, sorbent tube, and sampling tube) is 

a stainless steel or inert coated stainless steel 

tube. Standard PS tube dimensions for this 

method are 3.5-inch (89 mm) long x 0.25- 

inch (6.4 mm) o.d. stainless steel tubes with 

an i.d. of 5 mm, a cross-sectional area of 19.6 

mm2 and an air gap of 15 mm. The central 

portion of the tube is packed with solid 

adsorbent material contained between 2 x 

100-mesh stainless steel gauzes and 

terminated with a diffusion cap at the 

sampling end of the tube. These axial passive 

samplers are installed under a protective 

hood during field deployment. 

Note: Glass and glass- (or fused silica-) 

lined stainless steel sorbent tubes (typically 

4 mm i.d.) are also available in various 

lengths to suit different makes of thermal 

desorption equipment, but these are rarely 

used for passive sampling because it is more 

difficult to adequately define the diffusive air 

gap in glass or glass-line tubing. Such tubes 

are not recommended for this method. 

4.0 Sampling Interferences 

4.1 General Interferences. Passive tube 

samplers should be sited at a distance 

beyond the influence of possible obstructions 

such as trees, walls, or buildings at the 

monitoring site. General guidance for siting 

can be found in EPA–454/B–13–003, Quality 

Assurance Handbook for Air Pollution 

Measurement Systems, Volume II: Ambient 

Air Quality Monitoring Program, May 2013 

(Reference 3) (incorporated by reference—see 

§ 63.14). Complex topography and physical 

site obstructions, such as bodies of water, 

hills, buildings, and other structures that may 

prevent access to a planned PS location must 

be taken into consideration. You must 

document and report siting interference with 

the results of this method. 

4.2 Background Interference. Nearby or 

upwind sources of target emissions outside 

the facility being tested can contribute to 

background concentrations. Moreover, 

because passive samplers measure 

continuously, changes in wind direction can 

cause variation in the level of background 

concentrations from interfering sources 

during the monitoring period. This is why 

local meteorological information, particularly 

wind direction and speed, is required to be 

collected throughout the monitoring period. 

Interfering sources can include neighboring 

industrial facilities, transportation facilities, 

fueling operations, combustion sources, 

short-term transient sources, residential 

sources, and nearby highways or roads. As 

PS data are evaluated, the location of 

potential interferences with respect to PS 

locations and local wind conditions should 

be considered, especially when high PS 

concentration values are observed. 

4.3 Tube Handling. You must protect the 

PS tubes from gross external contamination 

during field sampling. Analytical thermal 

desorption equipment used to analyze PS 

tubes must desorb organic compounds from 

the interior of PS tubes and excludes 

contamination from external sampler 

surfaces in the analytical/sample flow path. 

If the analytical equipment does not comply 

with this requirement, you must wear clean, 

white, cotton or powder-free nitrile gloves to 

handle sampling tubes to prevent 

contamination of the external sampler 

surfaces. Sampling tubes must be capped 

with two-piece, brass, 0.25 inch, long-term 

storage caps fitted with combined 

polytetrafluoroethylene ferrules (see Section 

6.1 and Method 325B) to prevent ingress of 

airborne contaminants outside the sampling 

period. When not being used for field 

monitoring, the capped tubes must be stored 

in a clean, air-tight, shipping container to 

prevent the collection of VOCs (see Section 

6.4.2 of Method 325B). 

4.4 Local Weather Conditions and 

Airborne Particulates. Although air speeds 

are a constraint for many forms of passive 

samplers, axial tube PS devices have such a 

slow inherent uptake rate that they are 

largely immune to these effects (References 

4,5). Passive samplers must nevertheless be 

deployed under non-emitting weatherproof 

hoods to moderate the effect of local weather 

conditions such as solar heating and rain. 

The cover must not impede the ingress of 

ambient air. Sampling tubes should also be 

orientated vertically and pointing 

downwards, to minimize accumulation of 

particulates. 

4.5 Temperature. The normal working 

range for field sampling for sorbent packing 

is 0–40 °C (References 6,7). Note that most 

published passive uptake rate data for 

sorbent tubes is quoted at 20 °C. Note also 

that, as a rough guide, an increase in 

temperature of 10 °C will reduce the retention 


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volume (i.e., collection capacity) for a given 

analyte on a given sorbent packing by a factor 

of 2, but the uptake rate will not change 

significantly (Reference 4). 

5.0 Safety 

This method does not purport to include 

all safety issues or procedures needed when 

deploying or collecting passive sampling 

tubes. Precautions typical of field air 

sampling projects are required. Tripping, 

falling, electrical, and weather safety 

considerations must all be included in plans 

to deploy and collect passive sampling tubes. 

6.0 Sampling Equipment and Supplies, and 

Pre-Deployment Planning 

This section describes the equipment and 

supplies needed to deploy passive sampling 

monitoring equipment at a facility fenceline 

or property boundary. Details of the passive 

sampling tubes themselves and equipment 

required for subsequent analysis are 

described in Method 325B. 

6.1 Passive Sampling Tubes. The 

industry standard PS tubes used in this 

method must meet the specific configuration 

and preparation described in Section 3.0 of 

this method and Section 6.1 of Method 325B. 

Note: The use of PS tubes packed with 

various sorbent materials for monitoring a 

wide variety of organic compounds in 

ambient air has been documented in the 

literature (References 4–10). Other sorbents 

that may be used in standard passive 

sampling tubes for monitoring additional 

target compound(s) once their uptake rate 

and performance has been demonstrated 

following procedures in Addendum A to 

Method 325B. Guidance on sorbent selection 

can also be obtained from relevant national 

and international standard methods such as 

ASTM D6196–03 (2009) (Reference 14) 

(incorporated by reference—see § 63.14) and 

ISO 16017–2:2003 (Reference 13) 

(incorporated by reference—see § 63.14). 

6.2 Passive or Diffusive Sampling Cap. 

One diffusive sampling cap is required per 

PS tube. The cap fits onto the sampling end 

of the tube during air monitoring. The other 

end of the tube remains sealed with the longterm storage cap. Each diffusive sampling cap 

is fitted with a stainless steel gauze, which 

defines the outer limit of the diffusion air 

gap. 

6.3 Sorbent Tube Protection Cover. A 

simple weatherproof hood, suitable for 

protecting passive sampling tubes from the 

worst of the weather (see Section 4.4) 

consists of an inverted cone/funnel 

constructed of an inert, non-outgassing 

material that fits over the diffusive tube, with 

the open (sampling) end of the tube 

projecting just below the cone opening. An 

example is shown in Figure 6.1 (Adapted 

from Reference 13). 

6.4 Thermal Desorption Apparatus. If the 

analytical thermal desorber that will 

subsequently be used to analyze the passive 

sampling tubes does not meet the 

requirement to exclude outer surface 

contaminants from the sample flow path (see 

Section 6.6 of Method 325B), then clean, 

white, cotton or powder-free nitrile gloves 

must be used for handling the passive 

sampling tubes during field deployment. 

6.5 Sorbent Selection. Sorbent tube 

configurations, sorbents or other VOC not 

listed in this method must be evaluated 

according to Method 325B, Addendum A or 

ISO 16017–2:2003 (Reference 13) 

(incorporated by reference—see § 63.14). The 

supporting evaluation and verification data 

described in Method 325B, Addendum A for 

configurations or compounds different from 

the ones described in this method must meet 

the performance requirements of Method 

325A/B and must be submitted with the test 

plan for your measurement program. 

7.0 Reagents and Standards 

No reagents or standards are needed for the 

field deployment and collection of passive 

sampling tubes. Specifications for sorbents, 

gas and liquid phase standards, preloaded 

standard tubes, and carrier gases are covered 

in Section 7 of Method 325B. 

8.0 Sample Deployment, Recovery, and 

Storage 

Pre-deployment and planning steps are 

required before field deployment of passive 

sampling tubes. These activities include but 

are not limited to conducting a site visit, 

determining suitable and required 

monitoring locations, and determining the 

monitoring frequency to be used. 

8.1 Conducting the Site Visit. 

8.1.1 Determine the size and shape of the 

facility footprint in order to determine the 

required number of monitoring locations. 

8.1.2 Identify obstacles or obstructions 

(buildings, roads, fences), hills and other 

terrain issues (e.g., bodies of water or swamp 

land) that could interfere with air parcel flow 

to the sampler or that prevent reasonable 

access to the location. You may use the 

general guidance in Section 4.1 of this 

method during the site visit to identify 

sampling locations. You must evaluate the 

placement of each passive sampler to 

determine if the conditions in this section are 

met. 

8.1.3 Identify to the extent possible and 

record potential off-site source interferences 


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(e.g., neighboring industrial facilities, 

transportation facilities, fueling operations, 

combustion sources, short-term transient 

sources, residential sources, nearby 

highways). 

8.1.4 Identify the closest available 

meteorological station. Identify potential 

locations for one or more on-site or near-site 

meteorological station(s) following the 

guidance in EPA–454/B–08–002, Quality 

Assurance Handbook for Air Pollution 

Measurement Systems, Volume IV: 

Meteorological Measurements, Version 2.0 

(Final), March 2008 (Reference 11) 

(incorporated by reference—see § 63.14). 

8.2 Determining Sampling Locations 

(References 2, 3). 

8.2.1 The number and placement of the 

passive samplers depends on the size, the 

shape of the facility footprint or the linear 

distance around the facility, and the 

proximity of emission sources near the 

property boundaries. Aerial photographs or 

site maps may be used to determine the size 

(acreage) and shape of the facility or the 

length of the boundary. You will place 

passive samplers on the facility property 

boundary at different angles circling the 

geometric center of the facility based on the 

size of the area (or subarea) or at different 

distances based on the size and boundary 

length of the facility. 

Note: In some instances, permanent air 

monitoring stations may already be located in 

close proximity to the facility. These stations 

may be operated and maintained by the site, 

or local or state regulatory agencies. If access 

to the station is possible, a PS may be 

deployed adjacent to other air monitoring 

instrumentation. A comparison of the 

pollutant concentrations measured with the 

PS to concentrations measured by site 

instrumentation may be used as an optional 

data quality indicator to assess the accuracy 

of PS. 

8.2.2 Option 1 for Determining Sampling 

Locations. 

8.2.2.1 For facilities with a regular 

(circular, triangular, rectangular, or square) 

shape, determine the geographic center of the 

facility. 

8.2.2.1.1 For regularly shaped facilities 

with an area of less than or equal to 750 

acres, measure angles around the center point 

of 30 degrees for a total of twelve 30 degree 

measurements. 

8.2.2.1.2 For regularly shaped facilities 

covering an area greater than 750 acres but 

less than or equal to 1,500 acres, measure 

from the center point angles of 20 degrees for 

a total of eighteen 20 degree measurements. 

Figure 8.1 shows the monitor placement 

around the property boundary of a facility 

with an area between 750 and 1,500 acres. 

Monitor placements are represented with 

black dots along the property boundary. 

8.2.2.1.3 For facilities covering an area 

greater than 1,500 acres, measure angles of 15 

degrees from the center point for a total of 

twenty-four 15 degree measurements. 

8.2.2.1.4 Place samplers securely on a 

pole or supporting structure at 1.5 to 3 meters 

above ground level at each point just beyond 

the intersection where the measured angle 

intersects the property boundary. 

8.2.2.1.5 Extra samplers must be placed 

near known sources of VOCs at the test 

facility. In the case that a potential emission 

source is within 50 meters of the property 

boundary and the source location is between 

two monitors, measure the distance (x) 

between the two monitors and place another 

monitor halfway between (x/2) the two 

monitors. For example, in Figure 8.1 the 

facility added three additional monitors (i.e., 

light shaded sampler locations) to provide 

sufficient coverage of all area sources. 

8.2.2.2 For irregularly shaped facilities, 

divide the area into a set of connecting 

subarea circles, triangles or rectangles to 

determine sampling locations. The subareas 

must be defined such that a circle can 

reasonably encompass the subarea. Then 


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determine the geometric center point of each 

of the subareas. 

8.2.2.2.1 If a subarea is less than or equal 

to 750 acres (e.g., Figure 8.2), measure angles 

of 30 degrees from the center point for a total 

of twelve 30 degree measurements. 

8.2.2.2.2 If a subarea is greater than 750 

acres but less than or equal to 1,500 acres 

(e.g., Figure 8.3), measure angles of 20 

degrees from the center point for a total of 

eighteen 20 degree measurements. 

8.2.2.2.3 If a subarea is greater than 1,500 

acres, measure angles of 15 degrees from the 

center for a total of twenty-four 15 degree 

measurements. 

8.2.2.3 Locate each sampling point just 

beyond the intersection of the measured 

angle and the outer property boundary. 

8.2.2.4 Sampling sites are not needed at 

the intersection of an inner boundary with an 

adjacent subarea. The sampling location must 

be sited where the measured angle intersects 

more than one point along the subarea’s outer 

boundary. 


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8.2.3 Option 2 for Determining Sampling 

Locations. 

8.2.3.1 For facilities with a boundary 

length of less than 24,000 feet, a minimum 

of twelve sampling locations evenly spaced 

± 10 percent of the location interval is 

required. 

8.2.3.2 For facilities with a boundary 

length greater than 24,000 feet, sampling 

locations are spaced 2,000 ±250 feet apart. 

8.2.3.4 Place samplers securely on a pole 

or supporting structure at 1.5 to 3 meters 

above ground level. 

8.2.3.5 Extra samplers must be placed 

near known sources of VOCs at the test 

facility. In the case that a potential emission 

source is within 50 meters of the property 

boundary and the source location is between 

two monitors, measure the distance (x) 

between the two monitors and place another 

monitor halfway between (x/2) the two 

monitors. For example, in Figure 8.4, the 

facility added three additional monitors (i.e., 

light shaded sampler locations) to provide 

sufficient coverage of all area sources. 


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8.3 Siting a Meteorological Station. A 

dedicated meteorological station is required 

at or near the facility you are monitoring. A 

number of commercially available 

meteorological stations can be used. 

Information on meteorological instruments 

can be found in EPA–454/R–99–005, 

Meteorological Monitoring Guidance for 

Regulatory Modeling Applications, February 

2000 (Reference 11) (incorporated by 

reference—see § 63.14). Some important 

considerations for siting of meteorological 

stations are detailed below. 

8.3.1 Place meteorological stations in 

locations that represent conditions affecting 

the transport and dispersion of pollutants in 

the area of interest. Complex terrain may 

require the use of more than one 

meteorological station. 

8.3.2 Deploy wind instruments over level, 

open terrain at a height of 10 meters. If 

possible, locate wind instruments at a 

distance away from nearby structures that is 

equal to at least 10 times the height of the 

structure. 

8.3.3 Protect meteorological instruments 

from thermal radiation and adequately 

ventilate them using aspirated shields. The 

temperature sensor must be located at a 

distance away from any nearby structures 

that is equal to at least four times the height 

of the structure. Temperature sensors must be 

located at least 30 meters from large paved 

areas. 

8.3.4 Collect and record meteorological 

data, including wind speed, wind direction, 

and temperature and average data on an 

hourly basis. Collect daily unit vector wind 

direction data plus average temperature and 

barometric pressure measurements of the 

sampled air to enable calculation of 

concentrations at standard conditions. 

8.3.5 Identify and record the location of 

the meteorological station by its GPS 

coordinate. 

8.4 Monitoring Frequency. 

8.4.1 Sample collection may be 

performed for periods from 48 hours up to 14 

days. 

8.4.2 A site screening protocol that meets 

method requirements may be performed by 

collecting samples for a year where each PS 

accumulates VOC for a 14-day sampling 

period. Study results are accumulated for the 

sampling periods (typically 26) over the 

course of one calendar year. The sampling 

tubes must be changed at approximately the 

same time of day at each of the monitoring 

sites. 

8.5 Passive Sampler Deployment. 

8.5.1 Clean (conditioned) sorbent tubes 

must be prepared and packaged by the 

laboratory as described in Method 325B and 

must be deployed for sampling within 30 

days of conditioning. 

8.5.2 Allow the tubes to equilibrate with 

ambient temperature (approximately 30 

minutes to 1 hour) at the monitoring location 

before removing them from their storage/

shipping container for sample collection. 

8.5.3 If there is any risk that the 

analytical equipment will not meet the 

requirement to exclude contamination on 

outer tube surfaces from the sample flow 

path (see Section 6.6 of Method 325B), 

sample handlers must wear clean, white, 

cotton or powder-free nitrile gloves during 

PS deployment and collection and 

throughout any other tube handling 

operations. 

8.5.4 Inspect the sampling tubes 

immediately prior to deployment. Ensure 

that they are intact, securely capped, and in 

good condition. Any suspect tubes (e.g., 

tubes that appear to have leaked sorbent) 

should be removed from the sampling set. 

8.5.5 Secure passive samplers at a height 

of 1.5 to 2 meters above ground using a pole 

or other secure structure at each sampling 

location. Orient the PS vertically and with 

the sampling end pointing downward to 

avoid ingress of particulates. 

Note: Duplicate sampling assemblies must 

be deployed at at least one monitoring 

location during each field monitoring 

exercise. 

8.5.6 Protect the PS from rain and 

excessive wind velocity by placing them 

under the type of protective hood described 

in Section 6.1.3 or equivalent. 

8.5.7 Remove the storage cap on the 

sampling end of the tube and replace it with 

a diffusive sampling cap at the start of the 

sampling period. Make sure the diffusion cap 

is properly seated and store the removed 

storage caps in the empty tube shipping 

container. 

8.5.8 Record the start time and location 

details for each sampler on the field sample 

data sheet (see example in Section 17.0.) 

8.5.9 Expose the sampling tubes for the 

14-day sampling period. 

8.5.10 Field blank tubes (see Section 9.3 

of Method 325B) are stored outside the 

shipping container at representative 

sampling locations around the site, but with 

both long-term storage caps kept in place 

throughout the monitoring exercise. One 

field blank tube is required for every 10 

sampled tubes on a monitoring exercise. No 


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less than two field blanks should be 

collected, regardless of the size of the 

monitoring study. Record the tube number(s) 

for the field blank(s) on the field sample data 

sheet. 

8.6 Sorbent Tube Recovery and 

Meteorological Data Collection. Recover 

deployed sampling tubes and field blanks as 

follows: 

8.6.1 After the sampling period is 

complete, immediately replace the diffusion 

end cap on each sampled tube with a longterm storage end cap. Tighten the seal 

securely by hand and then tighten an 

additional quarter turn with an appropriate 

tool. Record the stop date and time and any 

additional relevant information on the 

sample data sheet. 

8.6.2 Place the sampled tubes, together 

with the field blanks, in the storage/shipping 

container. Label the storage container, but do 

not use paints, markers, or adhesive labels to 

identify the tubes. TD-compatible electronic 

(radio frequency identification (RFID)) tube 

labels are available commercially and are 

compatible with some brands of thermal 

desorber. If used, these may be programmed 

with relevant tube and sample information, 

which can be read and automatically 

transcribed into the sequence report by the 

TD system. 

Note: Sampled tubes must not be placed in 

the same shipping container as clean 

conditioned sampling tubes. 

8.6.3 Sampled tubes may be shipped at 

ambient temperature to a laboratory for 

sample analysis. 

8.6.4 Specify whether the tubes are field 

blanks or were used for sampling and 

document relevant information for each tube 

using a Chain of Custody form (see example 

in Section 17.0) that accompanies the 

samples from preparation of the tubes 

through receipt for analysis, including the 

following information: Unique tube 

identification numbers for each sampled 

tube; the date, time, and location code for 

each PS placement; the date, time, and 

location code for each PS recovery; the GPS 

reference for each sampling location; the 

unique identification number of the 

duplicate sample (if applicable); and 

problems or anomalies encountered. 

8.6.5 If the sorbent tubes are supplied 

with electronic (e.g., RFID) tags, it is also 

possible to allocate a sample identifier to 

each PS tube. In this case, the recommended 

format for the identification number of each 

sampled tube is AA–BB–CC–DD–VOC, 

where: 

AA = Sequence number of placement on 

route (01, 02, 03 . . .) 

BB = Sampling location code (01, 02, 03 . . .) 

CC = 14-day sample period number (01 to 26) 

DD = Sample code (SA = sample, DU = 

duplicate, FB = field blank) 

VOC = 3-letter code for target compound(s) 

(e.g., BNZ for benzene or BTX for 

benzene, toluene, and xylenes) 

Note: Sampling start and end times/dates 

can also be logged using RFID tube tags. 

8.6.6 Collect daily unit vector wind 

direction data plus average temperature and 

barometric pressure measurements to enable 

calculation of concentrations at standard 

conditions. You must supply this 

information to the laboratory with the 

samples. 

9.0 Quality Control 

9.1 Most quality control checks are 

carried out by the laboratory and associated 

requirements are in Section 9.0 of Method 

325B, including requirements for laboratory 

blanks, field blanks, and duplicate samples. 

9.2 Evaluate for potential outliers the 

laboratory results for neighboring sampling 

tubes collected over the same time period. A 

potential outlier is a result for which one or 

more PS tube does not agree with the trend 

in results shown by neighboring PS tubes— 

particularly when data from those locations 

have been more consistent during previous 

sampling periods. Accidental contamination 

by the sample handler must be documented 

before any result can be eliminated as an 

outlier. Rare but possible examples of 

contamination include loose or missing 

storage caps or contaminated storage/

shipping containers. Review data from the 

same and neighboring monitoring locations 

for the subsequent sampling periods. If the 

anomalous result is not repeated for that 

monitoring location, the episode can be 

ascribed to transient contamination and the 

data in question must be flagged for potential 

elimination from the dataset. 

9.3 Duplicates and Field Blanks. 

9.3.1 Collect at least one co-located/

duplicate sample for every 10 field samples 

to determine precision of the measurements. 

9.3.2 Collect at least two field blanks 

sorbent samples per sampling period to 

ensure sample integrity associated with 

shipment, collection, and storage. You must 

use the entire sampling apparatus for field 

blanks including unopened sorbent tubes 

mounted in protective sampling hoods. The 

tube closures must not be removed. Field 

blanks must be placed in two different 

quadrants (e.g., 90 ° and 270 °) and remain at 

the sampling location for the sampling 

period. 

10.0 Calibration and Standardization 

Follow the calibration and standardization 

procedures for meteorological measurements 

in EPA–454/B–08–002, Quality Assurance 

Handbook for Air Pollution Measurement 

Systems, Volume IV: Meteorological 

Measurements, Version 2.0 (Final), March 

2008 (Reference 11) (incorporated by 

reference—see § 63.14). Refer to Method 

325B for calibration and standardization 

procedures for analysis of the passive 

sampling tubes. 

11.0 Analytical Procedures 

Refer to Method 325B, which provides 

details for the preparation and analysis of 

sampled passive monitoring tubes 

(preparation of sampling tubes, shipment and 

storage of exposed sampling tubes, and 

analysis of sampling tubes). 

12.0 Data Analysis, Calculations and 

Documentation 

12.1 Calculate Annual Average Fenceline 

Concentration. After a year’s worth of 

sampling at the facility fenceline (for 

example, 26 14-day samples), the average 

(PSi) can be calculated for any specified 

period at each PS location using Equation 

12.1. 

Where: 

PSi = Annual average for location i. 

PSip = Sampling period specific 

concentration from Method 325B. 

i = Location of passive sampler (0 to 360 °). 

p = The sampling period. 

N = The number of sampling periods in the 

year (e.g., for 14-day sampling periods, 

from 1 to 26). 

Note: PSip is a function of sampling 

location-specific factors such as the 

contribution from facility sources, unusual 

localized meteorological conditions, 

contribution from nearby interfering sources, 

the background caused by integrated far-field 

sources and measurement error due to 

deployment, handling, siting, or analytical 

errors. 

12.2 Identify Sampling Locations of 

Interest. If data from neighboring sampling 

locations are significantly different, then you 

may add extra sampling points to isolate 

background contributions or identify facilityspecific ‘‘hot spots.’’ 

12.3 Evaluate Trends. You may evaluate 

trends and patterns in the PS data over 

multiple sampling episodes to determine if 

elevated concentrations of target compounds 

are due to operations on the facility or if 

contributions from background sources are 

significant. 

12.3.1 Obtain meteorological data 

including wind speed and wind direction or 

unit vector wind data from the on-site 

meteorological station. Use this 

meteorological data to determine the 

prevailing wind direction and speed during 

the periods of elevated concentrations. 

12.3.2 As an option you may perform 

preliminary back trajectory calculations 

(http://ready.arl.noaa.gov/HYSPLIT.php) to 

aid in identifying the source of the 

background contribution to elevated target 

compound concentrations. 

12.3.3 Information on published or 

documented events on- and off-site may also 

be included in the associated sampling 

episode report to explain elevated 

concentrations if relevant. For example, you 


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would describe if there was a chemical spill 

on site, or an accident on an adjacent road. 

12.3.4 Additional monitoring for shorter 

periods may be necessary to allow better 

discrimination/resolution of contributing 

emission sources if the measured trends and 

associated meteorology do not provide a clear 

assessment of facility contribution to the 

measured fenceline concentration. 

13.0 Method Performance 

Method performance requirements are 

described in Method 325B. 

14.0 Pollution Prevention 

[Reserved] 

15.0 Waste Management 

[Reserved] 

16.0 References 

1. Ambient air quality—Standard method for 

measurement of benzene 

concentrations—Part 4: Diffusive 

sampling followed by thermal desorption 

and gas chromatography, BS EN 14662– 

4:2005. 

2. Thoma, E.D., Miller, C.M., Chung, K.C., 

Parsons, N.L. and Shine, B.C. Facility 

Fence Line Monitoring using Passive 

Samplers, J. Air & Waste Mange. Assoc. 

2011, 61:834–842. 

3. Quality Assurance Handbook for Air 

Pollution Measurement Systems, Volume 

II: Ambient Air Quality Monitoring 

Program, EPA–454/B–13–003, May 2013. 

Available at http://www.epa.gov/

ttnamti1/files/ambient/pm25/qa/QAHandbook-Vol-II.pdf. 

4. Brown, R.H., Charlton, J. and Saunders, 

K.J.: The development of an improved 

diffusive sampler. Am. Ind. Hyg. Assoc. 

J. 1981, 42(12): 865–869. 

5. Brown, R. H. Environmental use of 

diffusive samplers: evaluation of reliable 

diffusive uptake rates for benzene, 

toluene and xylene. J. Environ. Monit. 

1999, 1 (1), 115–116. 

6. Ballach, J.; Greuter, B.; Schultz, E.; 

Jaeschke, W. Variations of uptake rates in 

benzene diffusive sampling as a function 

of ambient conditions. Sci. Total 

Environ. 1999, 244, 203–217. 

7. Brown, R. H. Monitoring the ambient 

environment with diffusive samplers: 

theory and practical considerations. J 

Environ. Monit. 2000, 2(1), 1–9. 

8. Buzica, D.; Gerboles, M.; Plaisance, H. The 

equivalence of diffusive samplers to 

reference methods for monitoring O3, 

benzene and NO2 in ambient air. J. 

Environ. Monit. 2008, 10 (9), 1052–1059. 

9. Woolfenden, E. Sorbent-based sampling 

methods for volatile and semi-volatile 

organic compounds in air. Part 2. 

Sorbent selection and other aspects of 

optimizing air monitoring methods. J. 

Chromatogr. A 2010, 1217, (16), 2685– 

94. 

10. Pfeffer, H. U.; Breuer, L. BTX 

measurements with diffusive samplers in 

the vicinity of a cokery: Comparison 

between ORSA-type samplers and 

pumped sampling. J. Environ. Monit. 

2000, 2 (5), 483–486. 

11. US EPA. 2000. Meteorological Monitoring 

Guidance for Regulatory Modeling 

Applications. EPA–454/R–99–005. Office 

of Air Quality Planning and Standards, 

Research Triangle Park, NC. February 

2000. Available at http://www.epa.gov/

scram001/guidance/met/mmgrma.pdf. 

12. Quality Assurance Handbook for Air 

Pollution Measurement Systems. Volume 

IV: Meteorological Measurements 

Version 2.0 Final, EPA–454/B–08–002 

March 2008. Available at http://

www.epa.gov/ttnamti1/files/ambient/

met/Volume%20IV_Meteorological_

Measurements.pdf. 

13. ISO 16017–2:2003, Indoor, ambient and 

workplace air—Sampling and analysis of 

volatile organic compounds by sorbent 

tube/thermal desorption/capillary gas 

chromatography. Part 2: Diffusive 

sampling. 

14. ASTM D6196–03(2009): Standard 

practice for selection of sorbents, 

sampling, and thermal desorption 

analysis procedures for volatile organic 

compounds in air. 

17.0 Tables, Diagrams, Flowcharts and 

Validation Data 


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Method 325B—Volatile Organic Compounds 

From Fugitive and Area Sources 

Sampler Preparation and Analysis 

1.0 Scope and Application 

1.1 This method describes thermal 

desorption/gas chromatography (TD/GC) 

analysis of volatile organic compounds 

(VOCs) from fugitive and area emission 

sources collected onto sorbent tubes using 

passive sampling. It could also be applied to 

the TD/GC analysis of VOCs collected using 

active (pumped) sampling onto sorbent tubes. 

The concentration of airborne VOCs at or 

near potential fugitive- or area-emission 

sources may be determined using this 

method in combination with Method 325A. 

Companion Method 325A (Sampler 

Deployment and VOC Sample Collection) 

describes procedures for deploying the 

sorbent tubes and passively collecting VOCs. 

1.2 The preferred GC detector for this 

method is a mass spectrometer (MS), but 

flame ionization detectors (FID) may also be 

used. Other conventional GC detectors such 

as electron capture (ECD), photoionization 

(PID), or flame photometric (FPD) may also 

be used if they are selective and sensitive to 

the target compound(s) and if they meet the 

method performance criteria provided in this 

method. 

1.3 There are 97 VOCs listed as 

hazardous air pollutants in Title III of the 

Clean Air Act Amendments of 1990. Many of 

these VOC are candidate compounds for this 

method. Compounds with known uptake 

rates for Carbopack X or equivalent are listed 

in Table 12.1. This method provides 

performance criteria to demonstrate 

acceptable performance of the method (or 

modifications of the method) for monitoring 

a given compound or set of the compounds 

listed in Table 12.1. If standard passive 

sampling tubes are packed with other 

sorbents or used for other analytes than those 

listed in Table 12.1, then method 

performance and relevant uptake rates 

should be verified according to Appendix A 

to this method unless the compound or 

sorbent has already been validated and 

reported in one of the following national/

international standard methods: ISO 16017– 

2:2003(incorporated by reference—see 

§ 63.14), ASTM D6196–03(2009) 

(incorporated by reference—see § 63.14), or 

BS EN 14662–4:2005 (incorporated by 

reference—see § 63.14), or in the peerreviewed open literature. 

1.4 The analytical approach using TD/

GC/MS is based on previously published 

EPA guidance in Compendium Method TO– 

17 (http://www.epa.gov/ttnamti1/

airtox.html#compendium) (Reference 1), 

which describes active (pumped) sampling of 

VOCs from ambient air onto tubes packed 

with thermally stable adsorbents. 

1.5 Inorganic gases not suitable for 

analysis by this method include oxides of 

carbon, nitrogen and sulfur, ozone (O3), and 

other diatomic permanent gases. Other 

pollutants not suitable for this analysis 

method include particulate pollutants, (i.e., 

fumes, aerosols, and dusts), compounds too 

labile (reactive) for conventional GC analysis, 

and VOCs that are more volatile than 

propane. 

2.0 Summary of Method 

2.1 This method provides procedures for 

the preparation, conditioning, blanking, and 

shipping of sorbent tubes prior to sample 

collection. 

2.2 Laboratory and field personnel must 

have experience of sampling trace-level 

VOCs using sorbent tubes (References 2, 5) 

and must have experience operating thermal 

desorption/GC/multi-detector 

instrumentation. 

2.3 Key steps of this method as 

implemented for each sample tube include: 

Stringent leak testing under stop flow, 

recording ambient temperature conditions, 

adding internal standards, purging the tube, 

thermally desorping the sampling tube, 

refocusing on a focusing trap, desorping and 

transferring/injecting the VOCs from the 

secondary trap into the capillary GC column 

for separation and analysis. 

2.4 Water management steps incorporated 

into this method include: (a) selection of 

hydrophobic sorbents in the sampling tube; 

(b) optional dry purging of sample tubes prior 

to analysis; and (c) additional selective 

elimination of water during primary (tube) 

desorption (if required) by selecting trapping 

sorbents and temperatures such that target 

compounds are quantitatively retained while 

water is purged to vent. 

3.0 Definitions 

(See also Section 3.0 of Method 325A). 

3.1 Blanking is the desorption and 

confirmatory analysis of conditioned sorbent 

tubes before they are sent for field sampling. 

3.2 Breakthrough volume and associated 

relation to passive sampling. Breakthrough 

volumes, as applied to active sorbent tube 

sampling, equate to the volume of air 

containing a constant concentration of 

analyte that may be passed through a sorbent 

tube at a given temperature before a 

detectable level (5 percent) of the input 

analyte concentration elutes from the tube. 

Although breakthrough volumes are directly 

related to active rather than passive 

sampling, they provide a measure of the 

strength of the sorbent-sorbate interaction 

and therefore also relate to the efficiency of 

the passive sampling process. The best direct 

measure of passive sampling efficiency is the 

stability of the uptake rate. Quantitative 

passive sampling is compromised when back 

diffusion becomes significant—i.e., when the 

concentration of a target analyte immediately 

above the sorbent sampling surface no longer 

approximates to zero. This causes a reduction 

in the uptake rate over time. If the uptake rate 

for a given analyte on a given sorbent tube 

remains relatively constant—i.e., if the 

uptake rate determined for 48 hours is 

similar to that determined for 7 or 14 days— 

the user can be confident that passive 

sampling is occurring at a constant rate. As 

a general rule of thumb, such ideal passive 

sampling conditions typically exist for 

analyte:sorbent combinations where the 

breakthrough volume exceeds 100 L 

(Reference 4). 

3.3 Calibration verification sample. 

Single level calibration samples run 

periodically to confirm that the analytical 

system continues to generate sample results 

within acceptable agreement to the current 

calibration curve. 

3.4 Focusing trap is a cooled, secondary 

sorbent trap integrated into the analytical 

thermal desorber. It typically has a smaller 

i.d. and lower thermal mass than the original 

sample tube allowing it to effectively refocus 

desorbed analytes and then heat rapidly to 

ensure efficient transfer/injection into the 

capillary GC analytical column. 

3.5 High Resolution Capillary Column 

Chromatography uses fused silica capillary 

columns with an inner diameter of 320 mm 

or less and with a stationary phase film 

thickness of 5 mm or less. 

3.6 h is time in hours. 

3.7 i.d. is inner diameter. 

3.8 min is time in minutes. 

3.9 MS–SCAN is the mode of operation of 

a GC quadrupole mass spectrometer detector 

that measures all ions over a given mass 

range over a given period of time. 

3.10 MS–SIM is the mode of operation of 

a GC quadrupole mass spectrometer detector 

that measures only a single ion or a selected 

number of discrete ions for each analyte. 

3.11 o.d. is outer diameter. 

3.12 ppbv is parts per billion by volume. 

3.13 Retention volume is the volume of 

gas required to move an analyte vapor plug 

through the sorbent tube at a given 

temperature during active (pumped) 

sampling. Note that retention volume 

provides another measure of the strength of 

sorbent:sorbate (analyte) affinity and is 

closely related to breakthrough volume—See 

discussion in Section 3.2 above. 

3.14 Thermal desorption is the use of 

heat and a flow of inert (carrier) gas to extract 

volatiles from a solid matrix. No solvent is 

required. 

3.15 Total ion chromatogram is the 

chromatogram produced from a mass 

spectrometer detector collecting full spectral 

information. 

3.16 Two-stage thermal desorption is the 

process of thermally desorbing analytes from 

a sorbent tube, reconcentrating them on a 

focusing trap (see Section 3.4), which is then 

itself rapidly heated to ‘‘inject’’ the 

concentrated compounds into the GC 

analyzer. 

3.17 VOC means volatile organic 

compound. 

4.0 Analytical Interferences 

4.1 Interference from Sorbent Artifacts. 

Artifacts may include target analytes as well 

as other VOC that co-elute 

chromatographically with the compounds of 

interest or otherwise interfere with the 

identification or quantitation of target 

analytes. 

4.1.1 Sorbent decomposition artifacts are 

VOCs that form when sorbents degenerate, 

e.g., when exposed to reactive species during 

sampling. For example, benzaldehyde, 

phenol, and acetophenone artifacts are 

reported to be formed via oxidation of the 

polymer Tenax® when sampling high 

concentration (100–500 ppb) ozone 

atmospheres (Reference 5). 

4.1.2 Preparation and storage artifacts are 

VOCs that were not completely cleaned from 

the sorbent tube during conditioning or that 

are an inherent feature of that sorbent at a 

given temperature. 

4.2 Humidity. Moisture captured during 

sampling can interfere with VOC analysis. 


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Passive sampling using tubes packed with 

hydrophobic sorbents, like those described in 

this method, minimizes water retention. 

However, if water interference is found to be 

an issue under extreme conditions, one or 

more of the water management steps 

described in Section 2.4 can be applied. 

4.3 Contamination from Sample 

Handling. The type of analytical thermal 

desorption equipment selected should 

exclude the possibility of outer tube surface 

contamination entering the sample flow path 

(see Section 6.6). If the available system does 

not meet this requirement, sampling tubes 

and caps must be handled only while 

wearing clean, white cotton or powder free 

nitrile gloves to prevent contamination with 

body oils, hand lotions, perfumes, etc. 

5.0 Safety 

5.1 This method does not address all of 

the safety concerns associated with its use. It 

is the responsibility of the user of this 

standard to establish appropriate field and 

laboratory safety and health practices prior to 

use. 

5.2 Laboratory analysts must exercise 

extreme care in working with high-pressure 

gas cylinders. 

5.3 Due to the high temperatures 

involved, operators must use caution when 

conditioning and analyzing tubes. 

6.0 Equipment and Supplies 

6.1 Tube Dimensions and Materials. The 

sampling tubes for this method are 3.5-inches 

(89 mm) long, 1⁄4 inch (6.4 mm) o.d., and 5 

mm i.d. passive sampling tubes (see Figure 

6.1). The tubes are made of inert-coated 

stainless steel with the central section (up to 

60 mm) packed with sorbent, typically 

supported between two 100 mesh stainless 

steel gauze. The tubes have a cross sectional 

area of 19.6 square mm (5 mm i.d.). When 

used for passive sampling, these tubes have 

an internal diffusion (air) gap (DG) of 1.5 cm 

between the sorbent retaining gauze at the 

sampling end of the tube, and the gauze in 

the diffusion cap. 

6.2 Tube Conditioning Apparatus. 

6.2.1 Freshly packed or newly purchased 

tubes must be conditioned as described in 

Section 9 using an appropriate dedicated 

tube conditioning unit or the thermal 

desorber. Note that the analytical TD system 

should only be used for tube conditioning 

only if it supports a dedicated tube 

conditioning mode in which effluent from 

contaminated tubes is directed to vent 

without passing through key parts of the 

sample flow path such as the focusing trap. 

6.2.2 Dedicated tube conditioning units 

must be leak-tight to prevent air ingress, 

allow precise and reproducible temperature 

selection (±5 °C), offer a temperature range at 

least as great as that of the thermal desorber, 

and support inert gas flows in the range up 

to 100 mL/min. 

Note: For safety and to avoid laboratory 

contamination, effluent gases from freshly 

packed or highly contaminated tubes should 

be passed through a charcoal filter during the 

conditioning process to prevent desorbed 

VOCs from polluting the laboratory 

atmosphere. 

6.3 Tube Labeling. 

6.3.1 Label the sample tubes with a 

unique permanent identification number and 

an indication of the sampling end of the tube. 

Labeling options include etching and TDcompatible electronic (radio frequency 

identification (RFID)) tube labels. 

6.3.2 To avoid contamination, do not 

make ink markings of any kind on clean 

sorbent tubes or apply adhesive labels. 

Note: TD-compatible electronic (RFID) tube 

labels are available commercially and are 

compatible with some brands of thermal 

desorber. If used, these may be programmed 

with relevant tube and sample information, 

which can be read and automatically 

transcribed into the sequence report by the 

TD system (see Section 8.6 of Method 325A). 

6.4 Blank and Sampled Tube Storage 

Apparatus. 

6.4.1 Long-term storage caps. Seal clean, 

blank and sampled sorbent tubes using inert, 

long-term tube storage caps comprising nongreased, 2-piece, 0.25-inch, metal 

SwageLok®-type screw caps fitted with 

combined polytetrafluoroethylene ferrules. 

6.4.2 Storage and transportation 

containers. Use clean glass jars, metal cans or 

rigid, non-emitting polymer boxes. 

Note: You may add a small packet of new 

activated charcoal or charcoal/silica gel to 

the shipping container for storage and 

transportation of batches of conditioned 

sorbent tubes prior to use. Coolers without 

ice packs make suitable shipping boxes for 

containers of tubes because the coolers help 

to insulate the samples from extreme 

temperatures (e.g., if left in a parked vehicle). 

6.5 Unheated GC Injection Unit for 

Loading Standards onto Blank Tubes. A 

suitable device has a simple push fit or 

finger-tightening connector for attaching the 

sampling end of blank sorbent tubes without 

damaging the tube. It also has a means of 

controlling carrier gas flow through the 

injector and attached sorbent tube at 50–100 

ml/min and includes a low emission septum 

cap that allows the introduction of gas or 

liquid standards via appropriate syringes. 

Reproducible and quantitative transfer of 

higher boiling compounds in liquid 

standards is facilitated if the injection unit 

allows the tip of the syringe to just touch the 

sorbent retaining gauze inside the tube. 

6.6 Thermal Desorption Apparatus. The 

manual or automated thermal desorption 

system must heat sorbent tubes while a 

controlled flow of inert (carrier) gas passes 

through the tube and out of the sampling 

end. The apparatus must also incorporate a 

focusing trap to quantitatively refocus 

compounds desorbed from the tube. 

Secondary desorption of the focusing trap 

should be fast/efficient enough to transfer the 

compounds into the high resolution capillary 

GC column without band broadening and 

without any need for further pre- or oncolumn focusing. Typical TD focusing traps 

comprise small sorbent traps (Reference 16) 

that are electrically-cooled using multistage 

Peltier cells (References 17, 18). The 

direction of gas flow during trap desorption 

should be the reverse of that used for 

focusing to extend the compatible analyte 

volatility range. Closed cycle coolers offer 

another cryogen-free trap cooling option. 

Other TD system requirements and 

operational stages are described in Section 11 

and in Figures 17–2 through 17–4. 

6.7 Thermal Desorber—GC Interface. 

6.7.1 The interface between the thermal 

desorber and the GC must be heated 

uniformly and the connection between the 

transfer line insert and the capillary GC 

analytical column itself must be leak tight. 

6.7.2 A portion of capillary column can 

alternatively be threaded through the heated 

transfer line/TD interface and connected 

directly to the thermal desorber. 

Note: Use of a metal syringe-type needle or 

unheated length of fused silica pushed 


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through the septum of a conventional GC 

injector is not permitted as a means of 

interfacing the thermal desorber to the 

chromatograph. Such connections result in 

cold spots, cause band broadening and are 

prone to leaks. 

6.8 GC/MS Analytical Components. 

6.8.1 The GC system must be capable of 

temperature programming and operation of a 

high resolution capillary column. Depending 

on the choice of column (e.g., film thickness) 

and the volatility of the target compounds, it 

may be necessary to cool the GC oven to 

subambient temperatures (e.g., ¥50 °C) at the 

start of the run to allow resolution of very 

volatile organic compounds. 

6.8.2 All carrier gas lines supplying the 

GC must be constructed from clean stainless 

steel or copper tubing. Nonpolytetrafluoroethylene thread sealants. Flow 

controllers, cylinder regulators, or other 

pneumatic components fitted with rubber 

components are not suitable. 

6.9 Chromatographic Columns. Highresolution, fused silica or equivalent 

capillary columns that provide adequate 

separation of sample components to permit 

identification and quantitation of target 

compounds must be used. 

Note: 100-percent methyl silicone or 5- 

percent phenyl, 95-percent methyl silicone 

fused silica capillary columns of 0.25- to 

0.32-mm i.d. of varying lengths and with 

varying thicknesses of stationary phase have 

been used successfully for non-polar and 

moderately polar compounds. However, 

given the diversity of potential target lists, 

GC column choice is left to the operator, 

subject to the performance criteria of this 

method. 

6.10 Mass Spectrometer. Linear 

quadrupole, magnetic sector, ion trap or 

time-of-flight mass spectrometers may be 

used provided they meet specified 

performance criteria. The mass detector must 

be capable of collecting data from 35 to 300 

atomic mass units (amu) every 1 second or 

less, utilizing 70 volts (nominal) electron 

energy in the electron ionization mode, and 

producing a mass spectrum that meets all the 

instrument performance acceptance criteria 

in Section 9 when 50 hg or less of pbromofluorobenzene is analyzed. 

7.0 Reagents and Standards 

7.1 Sorbent Selection. 

7.1.1 Use commercially packed tubes 

meeting the requirements of this method or 

prepare tubes in the laboratory using sieved 

sorbents of particle size in the range 20 to 80 

mesh that meet the retention and quality 

control requirements of this method. 

7.1.2 This passive air monitoring method 

can be used without the evaluation specified 

in Addendum A if the type of tubes 

described in Section 6.1 are packed with 4– 

6 cm (typically 400–650 mg) of the sorbents 

listed in Table 12.1 and used for the 

respective target analytes. 

Note: Although Carbopack X is the 

optimum sorbent choice for passive sampling 

of 1,3-butadiene, recovery of compounds 

with vapor pressure lower than benzene may 

be difficult to achieve without exceeding 

sorbent maximum temperature limitations 

(see Table 8.1). See ISO 16017–2:2003 

(incorporated by reference—see § 63.14) or 

ASTM D6196–03(2009) (incorporated by 

reference—see § 63.14) for more details on 

sorbent choice for air monitoring using 

passive sampling tubes. 

7.1.3 If standard passive sampling tubes 

are packed with other sorbents or used for 

analytes other than those tabulated in Section 

12.0, method performance and relevant 

uptake rates should be verified according to 

Addendum A to this method unless the 

compound or sorbent has already been 

validated and reported in one of the 

following national/international standard 

methods: ISO 16017–2:2003 (incorporated by 

reference—see § 63.14), ASTM D6196– 

03(2009) (incorporated by reference—see 

§ 63.14), or BS EN 14662–4:2005 

(incorporated by reference—see § 63.14)—or 

in the peer-reviewed open literature. A 

summary table and the supporting evaluation 

data demonstrating the selected sorbent 

meets the requirements in Addendum A to 

this method must be submitted to the 

regulatory authority as part of a request to 

use an alternative sorbent. 

7.1.4 Passive (diffusive) sampling and 

thermal desorption methods that have been 

evaluated at relatively high atmospheric 

concentrations (i.e., mid-ppb to ppm) and 

published for use in workplace air and 

industrial/mobile source emissions testing 

(References 9–20) may be applied to this 

procedure. However, the validity of any 

shorter term uptake rates must be verified 

and adjusted if necessary for the longer 

monitoring periods required by this method 

by following procedures described in 

Addendum A to this method. 

7.1.5 Suitable sorbents for passive 

sampling must have breakthrough volumes of 

at least 20 L (preferably >100 L) for the 

compounds of interest and must 

quantitatively release the analytes during 

desorption without exceeding maximum 

temperatures for the sorbent or 

instrumentation. 

7.1.6 Repack/replace the sorbent tubes or 

demonstrate tube performance following the 

requirements in Addendum A to this method 

at least yearly or every 50 uses, whichever 

occurs first. 

7.2 Gas Phase Standards. 

7.2.1 Static or dynamic standard 

atmospheres may be used to prepare 

calibration tubes and/or to validate passive 

sampling uptake rates and can be generated 

from pure chemicals or by diluting 

concentrated gas standards. The standard 

atmosphere must be stable at ambient 

pressure and accurate to ±10 percent of the 

target gas concentration. It must be possible 

to maintain standard atmosphere 

concentrations at the same or lower levels 

than the target compound concentration 

objectives of the test. Test atmospheres used 

for validation of uptake rates must also 

contain at least 35 percent relative humidity. 

Note: Accurate, low-(ppb-) level gas-phase 

VOC standards are difficult to generate from 

pure materials and may be unstable 

depending on analyte polarity and volatility. 

Parallel monitoring of vapor concentrations 

with alternative methods, such as pumped 

sorbent tubes or sensitive/selective on-line 

detectors, may be necessary to minimize 

uncertainty. For these reasons, standard 

atmospheres are rarely used for routine 

calibration. 

7.2.2 Concentrated, pressurized gas phase 

standards. Accurate (±5 percent or better), 

concentrated gas phase standards supplied in 

pressurized cylinders may also be used for 

calibration. The concentration of the 

standard should be such that a 0.5–5.0 mL 

volume contains approximately the same 

mass of analytes as will be collected from a 

typical air sample. 

7.2.3 Follow manufacturer’s guidelines 

concerning storage conditions and 

recertification of the concentrated gas phase 

standard. Gas standards must be recertified a 

minimum of once every 12 months. 

7.3 Liquid Standards. Target analytes can 

also be introduced to the sampling end of 

sorbent tubes in the form of liquid calibration 

standards. 

7.3.1 The concentration of liquid 

standards must be such that an injection of 

0.5–2 ml of the solution introduces the same 

mass of target analyte that is expected to be 

collected during the passive air sampling 

period. 

7.3.2 Solvent Selection. The solvent 

selected for the liquid standard must be pure 

(contaminants <10 percent of minimum 

analyte levels) and must not interfere 

chromatographically with the compounds of 

interest. 

7.3.3 If liquid standards are sourced 

commercially, follow manufacturer’s 

guidelines concerning storage conditions and 

shelf life of unopened and opened liquid 

stock standards. 

Note: Commercial VOC standards are 

typically supplied in volatile or noninterfering solvents such as methanol. 

7.3.4 Working standards must be stored at 

6 °C or less and used or discarded within two 

weeks of preparation. 

7.4 Gas Phase Internal Standards. 

7.4.1 Gas-phase deuterated or fluorinated 

organic compounds may be used as internal 

standards for MS-based systems. 

7.4.2 Typical compounds include 

deuterated toluene, perfluorobenzene and 

perfluorotoluene. 

7.4.3 Use multiple internal standards to 

cover the volatility range of the target 

analytes. 

7.4.4 Gas-phase standards must be 

obtained in pressurized cylinders and 

containing vendor certified gas 

concentrations accurate to ±5 percent. The 

concentration should be such that the mass 

of internal standard components introduced 

is similar to those of the target analytes 

collected during field monitoring. 

7.5 Preloaded Standard Tubes. Certified, 

preloaded standard tubes, accurate within ±5 

percent for each analyte at the microgram 

level and ±10 percent at the nanogram level, 

are available commercially and may be used 

for auditing and quality control purposes. 

(See Section 9.5 for audit accuracy evaluation 

criteria.) Certified preloaded tubes may also 

be used for routine calibration. 

Note: Proficiency testing schemes are also 

available for TD/GC/MS analysis of sorbent 

tubes preloaded with common analytes such 

as benzene, toluene, and xylene. 

7.6 Carrier Gases. Use inert, 99.999- 

percent or higher purity helium as carrier 


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gas. Oxygen and organic filters must be 

installed in the carrier gas lines supplying 

the analytical system according to the 

manufacturer’s instructions. Keep records of 

filter and oxygen scrubber replacement. 

8.0 Sorbent Tube Handling (Before and 

After Sampling) 

8.1 Sample Tube Conditioning. 

8.1.1 Sampling tubes must be 

conditioned using the apparatus described in 

Section 6.2. 

8.1.2 New tubes should be conditioned 

for 2 hours to supplement the vendor’s 

conditioning procedure. Recommended 

temperatures for tube conditioning are given 

in Table 8.1. 

8.1.3 After conditioning, the blank must 

be verified on each new sorbent tube and on 

10 percent of each batch of reconditioned 

tubes. See Section 9.0 for acceptance criteria. 

TABLE 8.1—EXAMPLE SORBENT TUBE CONDITIONING PARAMETERS

Sampling sorbent 

Maximum 

temperature 

(°C) 

Conditioning 

temperature 

(°C) 

Carrier gas flow 

rate 

Carbotrap C® ............................................................................................................. >400 350 100 mL/min. 

Carbopack C®

Anasorb® GCB2 

Carbograph 1 TD 

Carbotrap®

Carbopack B®

Anasorb® GCB1 

Tenax® TA ................................................................................................................. 350 330 100 mL/min. 

Carbopack® X 

8.2 Capping, Storage and Shipment of 

Conditioned Tubes. 

8.2.1 Conditioned tubes must be sealed 

using long-term storage caps (see Section 6.4) 

pushed fully down onto both ends of the PS 

sorbent tube, tightened by hand and then 

tighten an additional quarter turn using an 

appropriate tool. 

8.2.2 The capped tubes must be kept in 

appropriate containers for storage and 

transportation (see Section 6.4.2). Containers 

of sorbent tubes may be stored and shipped 

at ambient temperature and must be kept in 

a clean environment. 

8.2.3 You must keep batches of capped 

tubes in their shipping boxes or wrap them 

in uncoated aluminum foil before placing 

them in their storage container, especially 

before air freight, because the packaging 

helps hold caps in position if the tubes get 

very cold. 

8.3 Calculating the Number of Tubes 

Required for a Monitoring Exercise. 

8.3.1 Follow guidance given in Method 

325A to determine the number of tubes 

required for site monitoring. 

8.3.2 The following additional samplers 

will also be required: Laboratory blanks as 

specified in Section 9.3.2 (two per sampling 

episode minimum), field blanks as specified 

in Section 9.3.4 (two per sampling episode 

minimum), calibration verification tubes as 

specified in Section 10.9.4. (at least one per 

analysis sequence or every 24 hours), and 

paired (duplicate) samples as specified in 

Section 9.4 (at least one pair of duplicate 

samples is required for every 10 sampling 

locations during each monitoring period). 

8.4 Sample Collection. 

8.4.1 Allow the tubes to equilibrate with 

ambient temperature (approximately 30 

minutes to 1 hour) at the monitoring location 

before removing them from their storage/

shipping container for sample collection. 

8.4.2 Tubes must be used for sampling 

within 30 days of conditioning (Reference 4). 

8.4.3 During field monitoring, the longterm storage cap at the sampling end of the 

tube is replaced with a diffusion cap and the 

whole assembly is arranged vertically, with 

the sampling end pointing downward, under 

a protective hood or shield—See Section 6.1 

of Method 325A for more details. 

8.5 Sample Storage. 

8.5.1 After sampling, tubes must be 

immediately resealed with long-term storage 

caps and placed back inside the type of 

storage container described in Section 6.4.2. 

8.5.2 Exposed tubes may not be placed in 

the same container as clean tubes. They 

should not be taken back out of the container 

until ready for analysis and after they have 

had time to equilibrate with ambient 

temperature in the laboratory. 

8.5.3 Sampled tubes must be inspected 

before analysis to identify problems such as 

loose or missing caps, damaged tubes, tubes 

that appear to be leaking sorbent or container 

contamination. Any and all such problems 

must be documented together with the 

unique identification number of the tube or 

tubes concerned. Affected tubes must not be 

analyzed but must be set aside. 

8.5.4 Intact tubes must be analyzed 

within 30 days of the end of sample 

collection (within one week for limonene, 

carene, bis-chloromethyl ether, labile sulfur 

or nitrogen-containing compounds, and other 

reactive VOCs). 

Note: Ensure ambient temperatures stay 

below 23 °C during transportation and 

storage. Refrigeration is not normally 

required unless the samples contain reactive 

compounds or cannot be analyzed within 30 

days. If refrigeration is used, the atmosphere 

inside the refrigerator must be clean and free 

of organic solvents. 

9.0 Quality Control 

9.1 Analytical System Blank. The 

analytical system must be demonstrated to be 

contaminant free by carrying out an analysis 

without a sorbent tube—i.e., by desorbing an 

empty tube or by desorbing the focusing trap 

alone. Since no internal standards can be 

added directly to the empty tube, the system 

blank must have less than or equal to 0.2 

ppbv or three times the detection limit for 

each target compound, whichever is larger 

based on the response factors for the 

continuing calibration verification sample. 

Perform a system blank analysis at the 

beginning of each analytical sequence to 

demonstrate that the secondary trap and TD/ 

GC/MS analytical equipment are free of any 

significant interferents. Flag all sample data 

from analytical sequences that fail the system 

blank check and provide a narrative on how 

the failure affects the data use. 

9.2 Tube Conditioning. 

9.2.1 Conditioned tubes must be 

demonstrated to be free of contaminants and 

interference by running 10 percent of the 

blank tubes selected at random from each 

conditioned batch (see Section 8.1). 

9.2.2 Confirm that artifacts and 

background contamination are ≤ 0.2 ppbv or 

less than three times the detection limit of 

the procedure or less than 10 percent of the 

target compound(s) mass that would be 

collected if airborne concentrations were at 

the regulated limit value, whichever is larger. 

Only tubes that meet these criteria can be 

used for field monitoring, field or laboratory 

blanks, or for system calibration. 

9.2.3 If unacceptable levels of VOCs are 

observed in the tube blanks, then the 

processes of tube conditioning and checking 

the blanks must be repeated. 

9.3 Field and Laboratory Blanks. 

9.3.1 Field and laboratory blank tubes 

must be prepared from tubes that are 

identical to those used for field sampling— 

i.e., they should be from the same batch, have 

a similar history, and be conditioned at the 

same time. 

9.3.2 At least two laboratory blanks are 

required per monitoring episode. These 

laboratory blanks must be stored in the 

laboratory under clean controlled ambient 

temperature conditions throughout the 

monitoring period. Analyze one laboratory 

blank at the beginning and one at the end of 

the associated field sample runs. 

9.3.3 Laboratory blank/artifact levels 

must meet the requirements of Section 9.2.2 

(see also Table 17.1). Flag all data that do not 

meet this criterion with a note that associated 

results are estimated, and likely to be biased 

high due to laboratory blank background. 


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9.3.4 Field blanks must be shipped to the 

monitoring site with the sampling tubes and 

must be stored at the sampling location 

throughout the monitoring exercise (see 

Method 325B). The long-term storage caps 

must be in place and must be stored outside 

the shipping container at the sampling 

location (see Method 325B). The field blanks 

are then shipped back to the laboratory in the 

same container as the sampled tubes. One 

field blank tube is required for every 10 

sampled tubes on a monitoring exercise and 

no less than two field blanks should be 

collected, regardless of the size of the 

monitoring study. 

9.3.5 Field blanks must contain no greater 

than one-third of the measured target analyte 

or compliance limit for field samples (see 

Table 17.1). Flag all data that do not meet 

this criterion with a note that the associated 

results are estimated and likely to be biased 

high due to field blank background. 

9.4 Duplicate Samples. Duplicate 

(collocated) samples collected must be 

analyzed and reported as part of method 

quality control. They are used to evaluate 

sampling and analysis precision. Relevant 

performance criteria are given in Section 9.9. 

9.5 Method Performance Criteria. Unless 

otherwise noted, monitoring method 

performance specifications must be 

demonstrated for the target compounds using 

the procedures described in Addendum A to 

this method and the statistical approach 

presented in Method 301. 

9.6 Limit of Detection. Determine the 

limit of detection under the analytical 

conditions selected (see Section 11.3) using 

the procedure in Section 15 of Method 301. 

The limit of detection is defined for each 

system by making seven replicate 

measurements of a concentration of the 

compound of interest within a factor of five 

of the detection limit. Compute the standard 

deviation for the seven replicate 

concentrations, and multiply this value by 

three. The results should demonstrate that 

the method is able to measure analytes such 

as benzene at concentrations as low as 10 ppt 

or 1/3rd (preferably 1/10th) of the lowest 

concentration of interest, whichever is larger. 

Note: Determining the detection limit may 

be an iterative process as described in 40 CFR 

part 136, Appendix B. 

9.7 Analytical Bias. Analytical bias must 

be demonstrated to be within ±30 percent 

using Equation 9.1. Analytical bias must be 

demonstrated during initial setup of this 

method and as part of the routine, singlelevel calibration verification carried out with 

every sequence of 10 samples or less (see 

Section 9.14). Calibration standard tubes (see 

Section 10.0) may be used for this purpose. 

Where: 

Spiked Value = A known mass of VOCs 

added to the tube. 

Measured Value = Mass determined from 

analysis of the tube. 

9.8 Analytical Precision. Demonstrate an 

analytical precision within ±20 percent using 

Equation 9.2. Analytical precision must be 

demonstrated during initial setup of this 

method and at least once per year. 

Calibration standard tubes may be used (see 

Section 10.0) and data from daily single-level 

calibration verification checks may also be 

applied for this purpose. 

Where: 

A1 = A measurement value taken from one 

spiked tube. 

A2 = A measurement value taken from a 

second spiked tube. 

A ̄ = The average of A1 and A2. 

9.9 Field Replicate Precision. Use 

Equation 9.3 to determine and report 

replicate precision for duplicate field 

samples (see Section 9.4). The level of 

agreement between duplicate field samples is 

a measure of the precision achievable for the 

entire sampling and analysis procedure. Flag 

data sets for which the duplicate samples do 

not agree within 30 percent. 

Where: 

F1 = A measurement value (mass) taken from 

one of the two field replicate tubes used 

in sampling. 

F2 = A measurement value (mass) taken from 

the second of two field replicate tubes 

used in sampling. 

F = The average of F1 and F2. 

9.10 Desorption Efficiency and 

Compound Recovery. The efficiency of the 

thermal desorption method must be 

determined. 

9.10.1 Quantitative (>95 percent) 

compound recovery must be demonstrated by 

repeat analyses on a same standard tube. 

9.10.2 Compound recovery through the 

TD system can be demonstrated by 

comparing the calibration check sample 

response factor obtained from direct GC 

injection of liquid standards with that 

obtained from thermal desorption analysis 

response factor using the same column under 

identical conditions. 

9.10.3 If the relative response factors 

obtained for one or more target compounds 

introduced to the column via thermal 

desorption fail to meet the criteria in Section 

9.10.1, you must adjust the TD parameters to 

meet the criteria and repeat the experiment. 

Once the thermal desorption conditions have 

been optimized, you must repeat this test 

each time the analytical system is 

recalibrated to demonstrate continued 

method performance. 

9.11 Audit Samples. Certified reference 

standard samples must be used to audit this 

procedure (if available). Accuracy within 30 

percent must be demonstrated for relevant 

ambient air concentrations (0.5 to 25 ppb). 

9.12 Mass Spectrometer Tuning Criteria. 

Tune the mass spectrometer (if used) 

according to manufacturer’s specifications. 

Verify the instrument performance by 

analyzing a 50 hg injection of 

bromofluorobenzene. Prior to the beginning 

of each analytical sequence or every 24 hours 

during continuous GC/MS operation for this 

method demonstrate that the 

bromofluorobenzene tuning performance 

criteria in Table 9.1 have been met. 


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TABLE 9.1—GC/MS TUNING CRITERIA 1

Target mass Rel. to mass Lower limit % Upper limit % 

50 ........................................................................................................................... 95 8 40 

75 ........................................................................................................................... 95 30 66 

95 ........................................................................................................................... 95 100 100 

96 ........................................................................................................................... 95 5 9 

173 ......................................................................................................................... 174 0 2 

174 ......................................................................................................................... 95 50 120 

175 ......................................................................................................................... 174 4 9 

176 ......................................................................................................................... 174 93 101 

177 ......................................................................................................................... 176 5 9 

1All ion abundances must be normalized to m/z 95, the nominal base peak, even though the ion abundance of m/z 174 may be up to 120 percent that of m/z 95. 

9.13 Routine Calibrations Checks at the 

Start of a Sequence. Run single-level 

calibration checks before each sequence of 

analyses and after every tenth sample to 

ensure that the previous multi-level 

calibration (see Section 10.6.3) is still valid. 

9.13.1 The sample concentration used for 

the routine calibration check should be near 

the mid-point of the multi-level calibration 

range. 

9.13.2 Quantitation software must be 

updated with response factors determined 

from the daily calibration standard. The 

percent deviation between the initial 

calibration and the daily calibration check for 

all compounds must be within 30 percent. 

9.14 Calibration Verification at the End of 

a Sequence. Run another single level 

standard after running each sequence of 

samples. The initial calibration check for a 

subsequent set of samples may be used as the 

final calibration check for a previous 

analytical sequence, provided the same 

analytical method is used and the subsequent 

set of samples is analyzed immediately 

(within 4 hours) after the last calibration 

verification. 

9.15 Additional Verification. Use a 

calibration check standard from a second, 

separate source to verify the original 

calibration at least once every three months. 

9.16 Integration Method. Document the 

procedure used for integration of analytical 

data including field samples, calibration 

standards and blanks. 

9.17 QC Records. Maintain all QC 

reports/records for each TD/GC/MS 

analytical system used for application of this 

method. Routine quality control 

requirements for this method are listed below 

and summarized in Table 17.1. 

10.0 Calibration and Standardization 

10.1 Calibrate the analytical system using 

standards covering the range of analyte 

masses expected from field samples. 

10.2 Analytical results for field samples 

must fall within the calibrated range of the 

analytical system to be valid. 

10.3 Calibration standard preparation 

must be fully traceable to primary standards 

of mass and/or volume, and/or be confirmed 

using an independent certified reference 

method. 

10.3.1 Preparation of calibration standard 

tubes from standard atmospheres. 

10.3.1.1 Subject to the requirements in 

Section 7.2.1, low-level standard 

atmospheres may be introduced to clean, 

conditioned sorbent tubes in order to 

produce calibration standards. 

10.3.1.2 The standard atmosphere 

generator or system must be capable of 

producing sufficient flow at a constant rate 

to allow the required analyte mass to be 

introduced within a reasonable time frame 

and without affecting the concentration of 

the standard atmosphere itself. 

10.3.1.3 The sampling manifold may be 

heated to minimize risk of condensation but 

the temperature of the gas delivered to the 

sorbent tubes may not exceed 100 °F. 

10.3.1.4 The flow rates passed through 

the tube should be in the order of 50–100 ml/ 

min and the volume of standard atmosphere 

sampled from the manifold or chamber must 

not exceed the breakthrough volume of the 

sorbent at the given temperature. 

10.4 Preparation of calibration standard 

tubes from concentrated gas standards. 

10.4.1 If a suitable concentrated gas 

standard (see Section 7.2.2) can be obtained, 

follow the manufacturer’s recommendations 

relating to suitable storage conditions and 

product lifetime. 

10.4.2 Introduce precise 0.5 to 5.0 ml 

aliquots of the standard to the sampling end 

of conditioned sorbent tubes in a 50–100 ml/ 

min flow of pure carrier gas. 

Note: This can be achieved by connecting 

the sampling end of the tube to an unheated 

GC injector (see Section 6.6) and introducing 

the aliquot of gas using a suitable gas syringe. 

Gas sample valves could alternatively be 

used to meter the standard gas volume. 

10.4.3 Each sorbent tube should be left 

connected to the flow of gas for 2 minutes 

after standard introduction. As soon as each 

spiked tube is removed from the injection 

unit, seal it with long-term storage caps and 

place it in an appropriate tube storage/

transportation container if it is not to be 

analyzed within 24 hours. 

10.5 Preparation of calibration standard 

tubes from liquid standards. 

10.5.1 Suitable standards are described in 

Section 7.3. 

10.5.2 Introduce precise 0.5 to 2 ml 

aliquots of liquid standards to the sampling 

end of sorbent tubes in a flow of carrier gas 

using a precision syringe and an unheated 

injector (Section 6.6). The flow of gas should 

be sufficient to completely vaporize the 

liquid standard. 

Note: If the analytes of interest are higher 

boiling than n-decane, reproducible analyte 

transfer to the sorbent bed is optimized by 

allowing the tip of the syringe to gently touch 

the sorbent retaining gauze at the sampling 

end of the tube. 

10.5.3 Each sorbent tube is left connected 

to the flow of gas for 5 minutes after liquid 

standard introduction. 

10.5.3.1 As soon as each spiked tube is 

removed from the injection unit, seal it with 

long-term storage caps and place it in an 

appropriate tube storage container if it is not 

to be analyzed within 24 hours. 

Note: In cases where it is possible to 

selectively purge the solvent from the tube 

while all target analytes are quantitatively 

retained, a larger 2 mL injection may be made 

for optimum accuracy. However, if the 

solvent cannot be selectively purged and will 

be present during analysis, the injection 

volume should be as small as possible (e.g., 

0.5 mL) to minimize solvent interference. 

Note: This standard preparation technique 

requires the entire liquid plug including the 

tip volume be brought into the syringe barrel. 

The volume in the barrel is recorded, the 

syringe is inserted into the septum of the 

spiking apparatus and allowed to warm to 

the temperature of the injection body. The 

liquid is then quickly injected. The result is 

the cool liquid contacts the hot syringe tip 

and the sample is completely forced into the 

injector and onto the sorbent cartridge. A bias 

occurs with this method when sample is 

drawn continuously up into the syringe to 

the specified volume and the calibration 

solution in the syringe tip is ignored. 

10.6 Preparation of calibration standard 

tubes from multiple standards. 

10.6.1 If it is not possible to prepare one 

standard containing all the compounds of 

interest (e.g., because of chemical reactivity 

or the breadth of the volatility range), 

standard tubes can be prepared from multiple 

gas or liquid standards. 

10.6.2 Follow the procedures described 

in Sections 10.4 and 10.5, respectively, for 

introducing each gas and/or liquid standard 

to the tube and load those containing the 

highest boiling compounds of interest first 

and the lightest species last. 

10.7 Additional requirements for 

preparation of calibration tubes. 

10.7.1 Storage of Calibration Standard 

Tubes. 

10.7.1.1 Seal tubes with long-term storage 

caps immediately after they have been 

disconnected from the standard loading 

manifold or injection apparatus. 

10.7.1.2 Calibration standard tubes may 

be stored for no longer than 30 days and 


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should be refrigerated if there is any risk of 

chemical interaction or degradation. 

10.8 Keep records for calibration standard 

tubes to include the following: 

10.8.1 The stock number of any 

commercial liquid or gas standards used. 

10.8.2 A chromatogram of the most recent 

blank for each tube used as a calibration 

standard together with the associated 

analytical conditions and date of cleaning. 

10.8.3 Date of standard loading. 

10.8.4 List of standard components, 

approximate masses and associated 

confidence levels. 

10.8.5 Example analysis of an identical 

standard with associated analytical 

conditions. 

10.8.6 A brief description of the method 

used for standard preparation. 

10.8.7 The standard’s expiration date. 

10.9 TD/GC/MS using standard tubes to 

calibrate system response. 

10.9.1 Verify that the TD/GC/MS 

analytical system meets the instrument 

performance criteria given in Section 9.1 and 

relevant parts of Section 9.5. 

10.9.2 The prepared calibration standard 

tubes must be analyzed using the analytical 

conditions applied to field samples (see 

Section 11.0) and must be selected to ensure 

quantitative transfer and adequate 

chromatographic resolution of target 

compounds, surrogates, and internal 

standards in order to enable reliable 

identification and quantitation of compounds 

of interest. The analytical conditions should 

also be sufficiently stringent to prevent 

buildup of higher boiling, non-target 

contaminants that may be collected on the 

tubes during field monitoring. 

10.9.3 Calibration range. Each TD/GC/MS 

system must be calibrated at five 

concentrations that span the monitoring 

range of interest before being used for sample 

analysis. This initial multi-level calibration 

determines instrument sensitivity under the 

analytical conditions selected and the 

linearity of GC/MS response for the target 

compounds. One of the calibration points 

must be within a factor of five of the 

detection limit for the compounds of interest. 

10.9.4 One of the calibration points from 

the initial calibration curve must be at the 

same concentration as the daily single-level 

calibration verification standard (e.g., the 

mass collected when sampling air at typical 

concentrations). 

10.9.5 Calibration frequency. Each GC/

MS system must be recalibrated with a full 

5-point calibration curve following corrective 

action (e.g., ion source cleaning or repair, 

column replacement) or if the instrument 

fails the daily calibration acceptance criteria. 

10.9.5.1 Single-level calibrations checks 

must be carried out on a regular routine basis 

as described in Section 9.6. 

10.9.5.2 Quantitation ions for the target 

compounds are shown in Table 10.1. Use the 

primary ion unless interferences are present, 

in which case you should use a secondary 

ion. 

TABLE 10.1—CLEAN AIR ACT VOLATILE ORGANIC COMPOUNDS FOR PASSIVE SORBENT SAMPLING

Compound CAS No. BP 

(°C) 

Vapor 

pressure 

(mmHg)a

MW b

Characteristic ion(s) 

Primary Secondary 

1,1-Dichloroethene ............... 75–35–4 32 500 96 .9 61 96 

3-Chloropropene .................. 107–05–1 44 .5 340 76 .5 76 41, 39, 78 

1,1,2-Trichloro-1,2,2- 

trifluoroethane ................... ........................ .......................... ............................ .......................... .............................. ..............................

1,1-Dichloroethane ............... 75–34–3 57 .0 230 99 63 65, 83, 85, 98, 

100. 

1,2-Dichloroethane ............... 107–06–2 83 .5 61 .5 99 62 98 

1,1,1-Trichloroethane ........... 71–55–6 74 .1 100 133 .4 97 99, 61 

Benzene ............................... 71–43–2 80 .1 76 .0 78 78 ..............................

Carbon tetrachloride ............ 56–23–5 76 .7 90 .0 153 .8 117 119 

1,2-Dichloropropane ............. 78–87–5 97 .0 42 .0 113 63 112 

Trichloroethene .................... 79–01–6 87 .0 20 .0 131 .4 95 97, 130, 132 

1,1,2-Trichloroethane ........... 79–00–5 114 19 .0 133 .4 83 97, 85 

Toluene ................................ 108–88–3 111 22 .0 92 92 91 

Tetrachloroethene ................ 127–18–4 121 14 .0 165 .8 164 129, 131, 166 

Chlorobenzene ..................... 108–90–7 132 8 .8 112 .6 112 77, 114 

Ethylbenzene ....................... 100–41–4 136 7 .0 106 91 106 

m,p-Xylene ........................... 108–38–3, 

106–42–3 

138 6 .5 106 .2 106 91 

Styrene ................................. 100–42–5 145 6 .6 104 104 78 

o-Xylene ............................... 95–47–6 144 5 .0 106 .2 106 91 

p-Dichlorobenzene ............... 106–46–7 173 0 .60 147 146 111, 148 

aPressure in millimeters of mercury. 

b Molecular weight. 

11.0 Analytical Procedure 

11.1 Preparation for Sample Analysis. 

11.1.1 Each sequence of analyses must be 

ordered as follows: 

11.1.1.1 A calibration verification. 

11.1.1.2 A laboratory blank. 

11.1.1.3 Field blank. 

11.1.1.4 Sample(s). 

11.1.1.5 Field blank. 

11.1.1.6 A single-level calibration 

verification standard tube after 10 field 

samples. 

11.1.1.7 A single-level calibration 

verification standard tube at the end of the 

sample batch. 

11.2 Pre-desorption System Checks and 

Procedures. 

11.2.1 Ensure all sample tubes and field 

blanks are at ambient temperature before 

removing them from the storage container. 

11.2.2 If using an automated TD/GC/MS 

analyzer, remove the long-term storage caps 

from the tubes, replace them with 

appropriate analytical caps, and load them 

into the system in the sequence described in 

Section 11.1. Alternatively, if using a manual 

system, uncap and analyze each tube, one at 

a time, in the sequence described in Section 

11.1. 

11.2.3 The following thermal desorption 

system integrity checks and procedures are 

required before each tube is analyzed. 

Note: Commercial thermal desorbers 

should implement these steps automatically. 

11.2.3.1 Tube leak test: Each tube must be 

leak tested as soon as it is loaded into the 

carrier gas flow path before analysis to ensure 

data integrity. 

11.2.3.2 Conduct the leak test at the GC 

carrier gas pressure, without heat or gas flow 

applied. Tubes that fail the leak test should 

not be analyzed, but should be resealed and 

stored intact. On automated systems, the 

instrument should continue to leak test and 

analyze subsequent tubes after a given tube 

has failed. Automated systems must also 

store and record which tubes in a sequence 

have failed the leak test. Information on 

failed tubes should be downloaded with the 

batch of sequence information from the 

analytical system. 

11.2.3.3 Leak test the sample flow path. 

Leak check the sample flow path of the 

thermal desorber before each analysis 

without heat or gas flow applied to the 


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sample tube. Stop the automatic sequence of 

tube desorption and GC analysis if any leak 

is detected in the main sample flow path. 

This process may be carried out as a separate 

step or as part of Section 11.2.3.2. 

11.2.4 Optional dry purge. 

11.2.4.1 Tubes may be dry purged with a 

flow of pure dry gas passing into the tube 

from the sampling end, to remove water 

vapor and other very volatile interferents if 

required. 

11.2.5 Internal standard (IS) addition. 

11.2.5.1 Use the internal standard 

addition function of the automated thermal 

desorber (if available) to introduce a precise 

aliquot of the internal standard to the 

sampling end of each tube after the leak test 

and shortly before primary (tube) 

desorption). 

Note: This step can be combined with dry 

purging the tube (Section 11.2.4) if required. 

11.2.5.2 If the analyzer does not have a 

facility for automatic IS addition, gas or 

liquid internal standard can be manually 

introduced to the sampling end of tubes in 

a flow of carrier gas using the types of 

procedure described in Sections 10.3 and 

10.4, respectively. 

11.2.6 Pre-purge. Each tube should be 

purged to vent with carrier gas flowing in the 

desorption direction (i.e., flowing into the 

tube from the non-sampling end) to remove 

oxygen before heat is applied. This is to 

prevent analyte and sorbent oxidation and to 

prevent deterioration of key analyzer 

components such as the GC column and mass 

spectrometer (if applicable). A series of 

schematics illustrating these steps is 

presented in Figures 17.2 and 17.3. 

11.3 Analytical Procedure. 

11.3.1 Steps Required for Thermal 

Desorption. 

11.3.1.1 Ensure that the pressure and 

purity of purge and carrier gases supplying 

the TD/GC/MS system, meet manufacturer 

specifications and the requirements of this 

method. 

11.3.1.2 Ensure also that the analytical 

method selected meets the QC requirements 

of this method (Section 9) and that all the 

analytical parameters are at set point. 

11.3.1.3 Conduct predesorption system 

checks (see Section 11.2). 

11.3.1.4 Desorb the sorbent tube under 

conditions demonstrated to achieve >95 

percent recovery of target compounds (see 

Section 9.5.2). 

Note: Typical tube desorption conditions 

range from 280–350 °C for 5–15 minutes with 

a carrier gas flow of 30–100 mL/min passing 

through the tube from the non-sampling end 

such that analytes are flushed out of the tube 

from the sampling end. Desorbed VOCs are 

concentrated (refocused) on a secondary, 

cooled sorbent trap integrated into the 

analytical equipment (see Figure 17.4). The 

focusing trap is typically maintained at a 

temperature between ¥30 and +30 °C during 

focusing. Selection of hydrophobic sorbents 

for focusing and setting a trapping 

temperature of +25 to 27 °C aid analysis of 

humid samples because these settings allow 

selective elimination of any residual water 

from the system, prior to GC/MS analysis. 

Note: The transfer of analytes from the tube 

to the focusing trap during primary (tube) 

desorption can be carried out splitless or 

under controlled split conditions (see Figure 

17.4) depending on the masses of target 

compounds sampled and the requirements of 

the system—sensitivity, required calibration 

range, column overload limitations, etc. 

Instrument controlled sample splits must be 

demonstrated by showing the reproducibility 

using calibration standards. Field and 

laboratory blank samples must be analyzed at 

the same split as the lowest calibration 

standard. During secondary (trap) desorption 

the focusing trap is heated rapidly (typically 

at rates > 40 °C/s) with inert (carrier) gas 

flowing through the trap (3–100 mL/min) in 

the reverse direction to that used during 

focusing. 

11.3.1.5 The split conditions selected for 

optimum field sample analysis must also be 

demonstrated on representative standards. 

Note: Typical trap desorption temperatures 

are in the range 250–360 °C, with a ‘‘hold’’ 

time of 1–3 minutes at the highest 

temperature. Trap desorption automatically 

triggers the start of GC analysis. The trap 

desorption can also be carried out under 

splitless conditions (i.e., with everything 

desorbed from the trap being transferred to 

the analytical column and GC detector) or, 

more commonly, under controlled split 

conditions (see Figure 17.4). The selected 

split ratio depends on the masses of target 

compounds sampled and the requirements of 

the system—sensitivity, required calibration 

range, column overload limitations, etc. If a 

split is selected during both primary (trap) 

desorption and secondary (trap) desorption, 

the overall split ratio is the product of the 

two. Such ‘double’ split capability gives 

optimum flexibility for accommodating 

concentrated samples as well as trace-level 

samples on the TD/GC/MS analytical system. 

High resolution capillary columns and most 

GC/MS detectors tend to work best with 

approximately 20–200 ng per compound per 

tube to avoid saturation. The overall split 

ratio must be adjusted such that, when it is 

applied to the sample mass that is expected 

to be collected during field monitoring, the 

amount reaching the column will be 

attenuated to fall within this range. As a rule 

of thumb this means that ∼20 ng samples will 

require splitless or very low split analysis, ∼2 

mg samples will require a split ratio in the 

order of ∼50:1 and 200 mg samples will 

require a double split method with an overall 

split ratio in the order of 2,000:1. 

11.3.1.6 Analyzed tubes must be resealed 

with long-term storage caps immediately 

after analysis (manual systems) or after 

completion of a sequence (automated 

systems). This prevents contamination, 

minimizing the extent of tube reconditioning 

required before subsequent reuse. 

11.3.2 GC/MS Analytical Procedure. 

11.3.2.1 Heat/cool the GC oven to its 

starting set point. 

11.3.2.2 If using a GC/MS system, it can 

be operated in either MS-Scan or MS–SIM 

mode (depending on required sensitivity 

levels and the type of mass spectrometer 

selected). As soon as trap desorption and 

transfer of analytes into the GC column 

triggers the start of the GC/MS analysis, 

collect mass spectral data over a range of 

masses from 35 to 300 amu. Collect at least 

10 data points per eluting chromatographic 

peak in order to adequately integrate and 

quantify target compounds. 

11.3.2.3 Use secondary ion quantitation 

only when there are sample matrix 

interferences with the primary ion. If 

secondary ion quantitation is performed, flag 

the data and document the reasons for the 

alternative quantitation procedure. 

11.3.2.4 Whenever the thermal 

desorption—GC/MS analytical method is 

changed or major equipment maintenance is 

performed, you must conduct a new fivelevel calibration (see Section 10.6.3). System 

calibration remains valid as long as results 

from subsequent routine, single-level 

calibration verification standards are within 

30 percent of the most recent 5-point 

calibration (see Section 10.9.5). Include 

relevant routine, single-level calibration data 

in the supporting information in the data 

report for each set of samples. 

11.3.2.5 Document, flag and explain all 

sample results that exceed the calibration 

range. Report flags and provide 

documentation in the analytical results for 

the affected sample(s). 

12.0 Data Analysis, Calculations, and 

Reporting 

12.1 Recordkeeping Procedures for 

Sorbent Tubes. 

12.1.1 Label sample tubes with a unique 

identification number as described in Section 

6.3. 

12.1.2 Keep records of the tube numbers 

and sorbent lots used for each sampling 

episode. 

12.1.3 Keep records of sorbent tube 

packing if tubes are manually prepared in the 

laboratory and not supplied commercially. 

These records must include the masses and/ 

or bed lengths of sorbent(s) contained in each 

tube, the maximum allowable temperature 

for that tube and the date each tube was 

packed. If a tube is repacked at any stage, 

record the date of tube repacking and any 

other relevant information required in 

Section 12.1. 

12.1.4 Keep records of the conditioning 

and blanking of tubes. These records must 

include, but are not limited to, the unique 

identification number and measured 

background resulting from the tube 

conditioning. 

12.1.5 Record the location, dates, tube 

identification and times associated with each 

sample collection. Record this information 

on a Chain of Custody form that is sent to the 

analytical laboratory. 

12.1.6 Field sampling personnel must 

complete and send a Chain of Custody to the 

analysis laboratory (see Section 8.6.4 of 

Method 325A for what information to 

include and Section 17.0 of this method for 

an example form). Duplicate copies of the 

Chain of Custody must be included with the 

sample report and stored with the field test 

data archive. 

12.1.7 Field sampling personnel must 

also keep records of the daily unit vector 

wind direction, daily average temperature, 

and daily average barometric pressure for the 

sample collection period. See Section 8.6.5 of 

Method 325A. 

12.1.8 Laboratory personnel must record 

the sample receipt date, and analysis date. 


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12.1.9 Laboratory personnel must 

maintain records of the analytical method 

and sample results in electronic or hardcopy 

in sufficient detail to reconstruct the 

calibration, sample, and quality control 

results from each sampling episode. 

12.2 Calculations. 

12.2.1 Complete the calculations in this 

section to determine compliance with 

calibration quality control criteria (see also 

Table 17.1). 

12.2.1.1 Response factor (RF). Calculate 

the RF using Equation 12.1: 

Where: 

As = Peak area for the characteristic ion of the 

analyte. 

Ais = Peak area for the characteristic ion of 

the internal standard. 

Ms = Mass of the analyte. 

Mis = Mass of the internal standard. 

12.2.1.2 Standard deviation of the 

response factors (SDRF). Calculate the SDRF

using Equation 12.2: 

Where: 

RFi = RF for each of the calibration 

compounds. 

RF = Mean RF for each compound from the 

initial calibration. 

n = Number of calibration standards. 

12.2.1.3 Percent deviation (%DEV). 

Calculate the %DEV using Equation 12.3: 

Where: 

SDRF = Standard deviation. 

RF = Mean RF for each compound from the 

initial calibration. 

12.2.1.4 Relative percent difference 

(RPD). Calculate the RPD using Equation 

12.4: 

Where: 

R1, R2 = Values that are being compared (i.e., 

response factors in calibration 

verification). 

12.2.2 Determine the equivalent 

concentration of compounds in atmospheres 

as follows. 

12.2.3 For passive sorbent tube samples, 

calculate the concentration of the target 

compound(s) in the sampled air, in mg/m3 by 

using Equation 12.5 (Reference 21). 

Where: 

Cm = The concentration of target compound 

in the air sampled (mg/m3). 

mmeas = The mass of the compound as 

measured in the sorbent tube (mg). 

U = The diffusive uptake rate (sampling rate) 

(mL/min). 

t = The exposure time (minutes). 

Note: Diffusive uptake rates for common 

VOCs, using carbon sorbents packed into 

sorbent tubes of the dimensions specified in 

Section 6.1, are listed in Table 12.1. Adjust 

analytical conditions to keep expected 

sampled masses within range (see Sections 

11.3.1.3 to 11.3.1.5). Best possible limits of 

detection are typically in the order of 0.1 ppb 

for 1,3-butadiene and 0.05 ppb for volatile 

aromatics such as benzene for 14-day 

monitoring. However, actual detection limits 

will depend upon the analytical conditions 

selected. 

TABLE 12.1—VALIDATED SORBENTS

AND UPTAKE RATES FOR SELECTED

CLEAN AIR ACT COMPOUNDS

Compound 

Carbopack X 

uptake rate 

(ml/min) a

1,1-Dichloroethene ............... 0.57±0.14 

3-Chloropropene ................... 0.51±0.3 

1,1-Dichloroethane ............... 0.57±0.1 

1,2-Dichloroethane ............... 0.57±0.08 

1,1,1-Trichloroethane ............ 0.51±0.1 

Benzene ................................ 0.66±0.06 

Carbon tetrachloride ............. 0.51±0.06 

1,2-Dichloropropane ............. 0.52±0.1 

TABLE 12.1—VALIDATED SORBENTS

AND UPTAKE RATES FOR SELECTED

CLEAN AIR ACT COMPOUNDS—Continued 

Compound 

Carbopack X 

uptake rate 

(ml/min) a

Trichloroethene ..................... 0.5±0.05 

1,1,2-Trichloroethane ............ 0.49±0.13 

Toluene ................................. 0.52±0.14 

Tetrachloroethene ................. 0.48±0.05 

Chlorobenzene ..................... 0.51±0.06 

Ethylbenzene ........................ 0.46±0.07 

m,p-Xylene ............................ 0.46±0.09 

Styrene ................................. 0.5±0.14 

o-Xylene ................................ 0.46±0.12 


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Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37065 

TABLE 12.1—VALIDATED SORBENTS

AND UPTAKE RATES FOR SELECTED

CLEAN AIR ACT COMPOUNDS—Continued 

Compound 

Carbopack X 

uptake rate 

(ml/min) a

p-Dichlorobenzene ................ 0.45±0.05 

a Reference 3, McClenny, J. Environ. Monit. 

7:248–256. 

12.2.4 Correct target concentrations 

determined at the sampling site temperature 

and atmospheric pressure to standard 

conditions (25 °C and 760 mm mercury) 

using Equation 12.6 (Reference 22). 

Where: 

tss = The temperature at the sampling site (K). 

Pss = The pressure at the sampling site (mm 

Hg). 

13.0 Method Performance 

The performance of this procedure for VOC 

not listed in Table 12.1 is determined using 

the procedure in Addendum A of this 

Method. 

13.1 The valid range for measurement of 

VOC is approximately 0.5 mg/m3 to 5 mg/m3

in air, collected over a 14-day sampling 

period. The upper limit of the useful range 

depends on the split ratio selected (Section 

11.3.1) and the dynamic range of the 

analytical system. The lower limit of the 

useful range depends on the noise from the 

analytical instrument detector and on the 

blank level of target compounds or 

interfering compounds on the sorbent tube 

(see Section 13.3). 

13.2 Diffusive sorbent tubes compatible 

with passive sampling and thermal 

desorption methods have been evaluated at 

relatively high atmospheric concentrations 

(i.e., mid-ppb to ppm) and published for use 

in workplace air and industrial/mobile 

source emissions (References 15–16, 21–22). 

13.3 Best possible detection limits and 

maximum quantifiable concentrations of air 

pollutants range from sub-part-per-trillion 

(sub-ppt) for halogenated species such as 

CCl4 and the freons using an electron capture 

detector (ECD), SIM Mode GC/MS, triple 

quad MS or GC/TOF MS to sub-ppb for 

volatile hydrocarbons collected over 72 hours 

followed by analysis using GC with 

quadrupole MS operated in the full SCAN 

mode. 

13.3.1 Actual detection limits for 

atmospheric monitoring vary depending on 

several key factors. These factors are: 

• Minimum artifact levels. 

• GC detector selection. 

• Time of exposure for passive sorbent 

tubes. 

• Selected analytical conditions, 

particularly column resolution and split 

ratio. 

14.0 Pollution Prevention 

This method involves the use of ambient 

concentrations of gaseous compounds that 

post little or no danger of pollution to the 

environment. 

15.0 Waste Management 

Dispose of expired calibration solutions as 

hazardous materials. Exercise standard 

laboratory environmental practices to 

minimize the use and disposal of laboratory 

solvents. 

16.0 References 

1. Winberry, W.T. Jr., et al., Determination of 

Volatile Organic Compounds in Ambient 

Air Using Active Sampling onto Sorbent 

Tubes: Method TO–17r, Second Edition, 

U.S. Environmental Protection Agency, 

Research Triangle Park, NC 27711, 

January 1999. http://www.epa.gov/ 

ttnamti1/airtox.html#compendium. 

2. Ciccioli, P., Brancaleoni, E., Cecinato, A., 

Sparapini, R., and Frattoni, M., 

‘‘Identification and Determination of 

Biogenic and Anthropogenic VOCs in 

Forest Areas of Northern and Southern 

Europe and a Remote Site of the 

Himalaya Region by High-resolution GC– 

MS,’’ J. of Chrom., 643, pp 55–69, 1993. 

3. McClenny, W.A., K.D. Oliver, H.H. 

Jacumin, Jr., E.H. Daughtrey, Jr., D.A. 

Whitaker. 2005. 24 h diffusive sampling 

of toxic VOCs in air onto Carbopack X 

solid adsorbent followed by thermal 

desorption/GC/MS analysis— laboratory 

studies. J. Environ. Monit. 7:248–256. 

4. Markes International (www.markes.com/ 

publications): Thermal desorption 

Technical Support Note 2: Prediction of 

uptake rates for diffusive tubes. 

5. Ciccioli, P., Brancaleoni, E., Cecinato, A., 

DiPalo, C., Brachetti, A., and Liberti, A., 

‘‘GC Evaluation of the Organic 

Components Present in the Atmosphere 

at Trace Levels with the Aid of 

CarbopackTM B for Preconcentration of 

the Sample,’’ J. of Chrom., 351, pp 433– 

449, 1986. 

6. Broadway, G.M., and Trewern, T., ‘‘Design 

Considerations for the Optimization of a 

Packed Thermal Desorption Cold Trap 

for Capillary Gas Chromatography,’’ 

Proc. 13th Int’l Symposium on Capil. 

Chrom., Baltimore, MD, pp 310–320, 

1991. 

7. Broadway, G.M., ‘‘An Automated System 

for use Without Liquid Cryogen for the 

Determination of VOC’s in Ambient 

Air,’’ Proc. 14th Int’l. Symposium on 

Capil. Chrom., Baltimore, MD, 1992. 

8. Gibitch, J., Ogle, L., and Radenheimer, P., 

‘‘Analysis of Ozone Precursor 

Compounds in Houston, Texas Using 

Automated Continuous GCs,’’ in 

Proceedings of the Air and Waste 

Management Association Conference: 

Measurement of Toxic and Related Air 

Pollutants, Air and Waste Management 

Association, Pittsburgh, PA, May 1995. 

9. Vandendriessche, S., and Griepink, B., 

‘‘The Certification of Benzene, Toluene 

and m-Xylene Sorbed on Tenax TA in 

Tubes,’’ CRM–112 CEC, BCR, EUR12308 

EN, 1989. 

10. MDHS 2 (Acrylonitrile in Air), 

‘‘Laboratory Method Using Porous 

Polymer Adsorption Tubes, and Thermal 

Desorption with Gas Chromatographic 

Analysis,’’ Methods for the 

Determination of Hazardous Substances 

(MDHS), UK Health and Safety 

Executive, Sheffield, UK. 

11. MDHS 22 (Benzene in Air), ‘‘Laboratory 

Method Using Porous Polymer 

Adsorbent Tubes, Thermal Desorption 

and Gas Chromatography,’’ Method for 

the Determination of Hazardous 

Substances (MDHS), UK Health and 

Safety Executive, Sheffield, UK. 

12. MDHS 23 (Glycol Ether and Glycol 

Acetate Vapors in Air), ‘‘Laboratory 

Method Using Tenax Sorbent Tubes, 

Thermal Desorption and Gas 

Chromatography,’’ Method for the 

Determination of Hazardous Substances 

(MDHS), UK Health and Safety 

Executive, Sheffield, UK. 

13. MDHS 40 (Toluene in air), ‘‘Laboratory 

Method Using Pumped Porous Polymer 

Adsorbent Tubes, Thermal Desorption 

and Gas Chromatography,’’ Method for 

the Determination of Hazardous 

Substances (MDHS), UK Health and 

Safety Executive, Sheffield, UK. 

14. MDHS 60 (Mixed Hydrocarbons (C to C) 

in Air), ‘‘Laboratory Method Using 

Pumped Porous Polymer 3 10 and 

Carbon Sorbent Tubes, Thermal 

Desorption and Gas Chromatography,’’ 

Method for the Determination of 

Hazardous Substances (MDHS), UK 


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Health and Safety Executive, Sheffield, 

UK. 

15. Price, J. A., and Saunders, K. J., 

‘‘Determination of Airborne Methyl tertButyl Ether in Gasoline Atmospheres,’’ 

Analyst, Vol. 109, pp. 829–834, July 

1984. 

16. Coker, D. T., van den Hoed, N., Saunders, 

K. J., and Tindle, P. E., ‘‘A Monitoring 

Method for Gasoline Vapour Giving 

Detailed Composition,’’ Ann. Occup, 

Hyg., Vol 33, No. 11, pp. 15–26, 1989. 

17. DFG, ‘‘Analytische Methoden zur prufing 

gesundheitsschadlicher Arbeistsstoffe,’’ 

Deutsche Forschungsgemeinschaft, 

Verlag Chemie, Weinheim FRG, 1985. 

18. NNI, ‘‘Methods in NVN Series 

(Luchtkwaliteit; Werkplekatmasfeer),’’ 

Nederlands Normailsatie—Institut, Delft, 

The Netherlands, 1986–88. 

19. ‘‘Sampling by Solid Adsorption 

Techniques,’’ Standards Association of 

Australia Organic Vapours, Australian 

Standard 2976, 1987. 

20. Woolfenden, E. A., ‘‘Monitoring VOCs in 

Air Using Pumped Sampling onto 

Sorbent Tubes Followed by Thermal 

Desorption-capillary GC Analysis: 

Summary of Reported Data and Practical 

Guidelines for Successful Application,’’ 

J. Air & Waste Manage. Assoc., Vol. 47, 

1997, pp. 20–36. 

21. ASTM D4597–10, Standard Practice for 

Sampling Workplace Atmospheres to 

collect Gases or Vapors with Solid 

Sorbent Diffusive Samplers. 

22. Validation Guidelines for Air Sampling 

Methods Utilizing Chromatographic 

Analysis, OSHA T–005, Version 3.0, May 

2010, http://www.osha.gov/dts/sltc/

methods/chromguide/chromguide.pdf. 

23. Martin, http://www.hsl.gov.uk/media/

1619/issue14.pdf. 

24. BS EN 14662–4:2005, Ambient air 

quality—Standard method for the 

measurement of benzene 

concentrations—Part 4: Diffusive 

sampling followed by thermal desorption 

and gas chromatography. 

25. ISO 16017–2:2003: Indoor, ambient and 

workplace air—Sampling and analysis of 

volatile organic compounds by sorbent 

tube/thermal desorption/capillary gas 

chromatography—Part 2: Diffusive 

sampling. 

17.0 Tables, Diagrams, Flowcharts and 

Validation Data 

TABLE 17.1—SUMMARY OF GC/MS ANALYSIS QUALITY CONTROL PROCEDURES

Parameter Frequency Acceptance criteria Corrective action 

Bromofluorobenzene Instrument 

Tune Performance Check.

Daily a prior to sample analysis .... Evaluation criteria presented in 

Section 9.5 and Table 9.2.

1) Retune and or 

2) Perform Maintenance. 

Five point calibration bracketing the 

expected sample concentration.

Following any major change, repair or maintenance or if daily 

CCV does not meet method requirements. Recalibration not to 

exceed three months.

1) Percent Deviation (%DEV) of 

response factors ±30%.

1) Repeat calibration sample 

analysis. 

2) Relative Retention Times 

(RRTs) for target peaks ±0.06 

units from mean RRT.

2) Repeat linearity check 

3) Prepare new calibration standards as necessary and repeat 

analysis. 

Calibration Verification (CCV Second source calibration verification 

check).

Following the calibration curve .... The response factor ±30% DEV 

from calibration curve average 

response factor.

1) Repeat calibration check 

2) Repeat calibration curve. 

System Blank Analysis .................... Daily a following 

bromofluorobenzene and calibration check; prior to sample 

analysis.

1) ≤0.2 ppbv per analyte or ≤3 

times the LOD, whichever is 

greater.

1) Repeat analysis with new 

blank tube. 

2) Internal Standard (IS) area response ±40% and IS Retention 

Time (RT) ±0.33 min. of most 

recent calibration check.

2) Check system for leaks, contamination. 

3) Analyze additional blank. 

Blank Sorbent Tube Certification .... One tube analyzed for each batch 

of tubes cleaned or 10 percent 

of tubes whichever is greater.

<0.2 ppbv per VOC targeted compound or 3 times the LOD, 

whichever is greater.

Reclean all tubes in batch and reanalyze. 

Samples—Internal Standards ......... All samples ................................... IS area response ±40% and IS 

RT ±0.33 min. of most recent 

calibration validation.

Flag Data for possible invalidation. 

aEvery 24 hours. 


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BILLING CODE 6560–50–C Addendum A to Method 325B—Method 325 

Performance Evaluation 

A.1 Scope and Application 

A.1.1 To be measured by Methods 325A 

and 325B, each new target volatile organic 

compound (VOC) or sorbent that is not listed 

in Table 12.1 must be evaluated by exposing 

the selected sorbent tube to a known 

concentration of the target compound(s) in an 

exposure chamber following the procedure in 

this Addendum, unless the compound or 


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sorbent has already been validated and 

reported in one of the following national/

international standard methods: ISO 16017– 

2:2003 (incorporated by reference—see 

§ 63.14), ASTM D6196–03(2009) 

(incorporated by reference—see § 63.14), or 

BS EN 14662–4:2005 (incorporated by 

reference—see § 63.14), or in peer-reviewed 

open literature. 

A.1.2 You must determine the uptake rate 

and the relative standard deviation compared 

to the theoretical concentration of volatile 

material in the exposure chamber for each of 

the tests required in this method. If data that 

meet the requirement of this Addendum are 

available in the peer reviewed open literature 

for VOCs of interest collected on your passive 

sorbent tube configuration, then such data 

may be submitted in lieu of the testing 

required in this Addendum. 

A.1.3 You must expose sorbent tubes in 

a test chamber to parts per trillion by volume 

(pptv) and low parts per billion by volume 

(ppbv) concentrations of VOCs in humid 

atmospheres to determine the sorbent tube 

uptake rate and to confirm compound 

capture and recovery. 

A.2 Summary of Method 

A.2.1 Known concentrations of VOC are 

metered into an exposure chamber 

containing sorbent tubes filled with media 

selected to capture the volatile organic 

compounds of interest (see Figure A.1 for an 

example exposure chamber). VOC are diluted 

with humid air and the chamber is allowed 

to equilibrate for 6 hours. Clean passive 

sampling devices are placed into the chamber 

and exposed for a measured period of time. 

The passive uptake rate of the passive 

sampling devices is determined using the 

standard and dilution gas flow rates. 

Chamber concentrations are confirmed with 

active SUMMA canister sampling. 

A.2.2 An exposure chamber and known 

gas concentrations must be used to challenge 

and evaluate the collection and recovery of 

target compounds from the sorbent and tube 

selected to perform passive measurements of 

VOC in atmospheres. 

A.3 Definitions 

A.3.1 cc is cubic centimeter. 

A.3.2 ECD is electron capture detector. 

A.3.3 FID is flame ionization detector. 

A.3.4 LED is light-emitting diode. 

A.3.5 MFC is mass flow controller. 

A.3.6 MFM is mass flow meter. 

A.3.7 min is minute. 

A.3.8 ppbv is parts per billion by volume. 

A.3.9 ppmv is parts per million by 

volume. 

A.3.10 PSD is passive sampling device. 

A.3.11 psig is pounds per square inch 

gauge. 

A.3.12 RH is relative humidity. 

A.3.13 VOC is volatile organic 

compound. 

A.4 Interferences 

A.4.1 VOC contaminants in water can 

contribute interference or bias results high. 

Use only distilled, organic-free water for 

dilution gas humidification. 

A.4.2 Solvents and other VOC-containing 

liquids can contaminate the exposure 

chamber. Store and use solvents and other 

VOC-containing liquids in the exhaust hood 

when exposure experiments are in progress 

to prevent the possibility of contamination of 

VOCs into the chamber through the 

chamber’s exhaust vent. 

Note: Whenever possible, passive sorbent 

evaluation should be performed in a VOC 

free laboratory. 

A.4.3 PSDs should be handled by 

personnel wearing only clean, white cotton 

or powder free nitrile gloves to prevent 

contamination of the PSDs with oils from the 

hands. 

A.4.4 This performance evaluation 

procedure is applicable to only volatile 

materials that can be measured accurately 

with SUMMA canisters. Alternative methods 

to confirm the concentration of volatile 

materials in exposure chambers are subject to 

Administrator approval. 

A.5 Safety 

A.5.1 This procedure does not address all 

of the safety concerns associated with its use. 

It is the responsibility of the user of this 

standard to establish appropriate field and 

laboratory safety and health practices and 

determine the applicability of regulatory 

limitations prior to use. 

A.5.2 Laboratory analysts must exercise 

appropriate care in working with highpressure gas cylinders. 

A.6 Equipment and Supplies 

A.6.1 You must use an exposure chamber 

of sufficient size to simultaneously generate 

a minimum of four exposed sorbent tubes. 

A.6.2 Your exposure chamber must not 

contain VOC that interfere with the 

compound under evaluation. Chambers made 

of glass and/or stainless steel have been used 

successfully for measurement of known 

concentration of selected VOC compounds. 

A.6.3 The following equipment and 

supplies are needed: 

• Clean, white cotton or nitrile gloves; 

• Conditioned passive sampling device 

tubes and diffusion caps; and 

• NIST traceable high resolution digital gas 

mass flow meters (MFMs) or flow controllers 

(MFCs). 

A.7 Reagents and Standards 

A.7.1 You must generate an exposure gas 

that contains between 35 and 75 percent 

relative humidity and a concentration of 

target compound(s) within 2 to 5 times the 

concentration to be measured in the field. 

A.7.2 Target gas concentrations must be 

generated with certified gas standards and 

diluted with humid clean air. Dilution to 

reach the desired concentration must be done 

with zero grade air or better. 

A.7.3 The following reagents and 

standards are needed: 

• Distilled water for the humidification; 

• VOC standards mixtures in high-pressure 

cylinder certified by the supplier (Note: The 

accuracy of the certified standards has a 

direct bearing on the accuracy of the 

measurement results. Typical vendor 

accuracy is ±5 percent accuracy but some 

VOC may only be available at lower accuracy 

(e.g., acrolein at 10 percent); and 

• Purified dilution air less than 0.2 ppbv 

of the target VOC. 

A.8 Sample Collection, Preservation and 

Storage 

A.8.1 You must use certified gas 

standards diluted with humid air. Generate 

humidified air by adding distilled organic 

free water to purified or zero grade air. 

Humidification may be accomplished by 

quantitative addition of water to the air 

dilution gas stream in a heated chamber or 

by passing purified air through a humidifying 

bubbler. You must measure the relative 

humidity in the test gas as part of the record 

of the passive sorbent sampler evaluation. 

Note: The RH in the exposure chamber is 

directly proportional to the fraction of the 

purified air that passes through the water in 

the bubbler before entering the exposure 

chamber. Achieving uniform humidification 

in the proper range is a trial-and-error 

process with a humidifying bubbler. You 

may need to heat the bubbler to achieve 

sufficient humidity. An equilibration period 

of approximately 15 minutes is required 

following each adjustment of the air flow 

through the humidifier. Several adjustments 

or equilibration cycles may be required to 

achieve the desired RH level. 

Note: You will need to determine both the 

dilution rate and the humidification rate for 

your design of the exposure chamber by trial 

and error before performing method 

evaluation tests. 

A.8.2 Prepare and condition sorbent 

tubes following the procedures in Method 

325B Section 7.0. 

A.8.3 You must verify that the exposure 

chamber does not leak. 

A.8.4 You must complete two evaluation 

tests using a minimum of eight passive 

sampling tubes in each test with less than 5- 

percent depletion of test analyte by the 

samplers. 

A.8.4.1 Perform at least one evaluation at 

five times the estimated analytical detection 

limit or less. 

A.8.4.2 Perform second evaluation at a 

concentration equivalent to the middle of the 

analysis calibration range. 

A.8.5 You must evaluate the samplers in 

the test chamber operating between 35 

percent and 50 percent RH, and at 25 ±5 °C. 

Allow the exposure chamber to equilibrate 

for 6 hours before starting an evaluation. 

A.8.6 The flow rate through the chamber 

must equal 100 percent of the volume of the 

chamber per minute (i.e., one chamber air 

change per minute) and be ≤ 0.5 meter per 

second face velocity across the sampler face. 

A.8.7 Place clean, ready to use sorbent 

tubes into the exposure chamber for 

predetermined amounts of time to evaluate 

collection and recovery from the tubes. The 

exposure time depends on the concentration 

of volatile test material in the chamber and 

the detection limit required for the sorbent 

tube sampling application. Exposure time 

should match sample collection time. The 

sorbent tube exposure chamber time may not 

be less than 24 hours and should not be 

longer than 2 weeks. 

A.8.7.1 To start the exposure, place the 

clean PSDs equipped with diffusion caps on 

the tube inlet into a retaining rack. 

A.8.7.2 Place the entire retaining rack 

inside the exposure chamber with the 

diffusive sampling end of the tubes facing 


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into the chamber flow. Seal the chamber and 

record the exposure start time, chamber RH, 

chamber temperature, PSD types and 

numbers, orientation of PSDs, and volatile 

material mixture composition (see Figure 

A.2). 

A.8.7.3 Diluted, humidified target gas 

must be continuously fed into the exposure 

chamber during cartridge exposure. Measure 

the flow rate of target compound standard gas 

and dilution air to an accuracy of 5 percent. 

A.8.7.4 Record the time, temperature, and 

RH at hourly intervals or at the beginning, 

middle, and end of the exposure time, 

whichever is greater. 

A.8.7.5 At the end of the exposure time, 

remove the PSDs from the exposure chamber. 

Record the exposure end time, chamber RH, 

and temperature. 


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A.9 Quality Control 

A.9.1 Monitor and record the exposure 

chamber temperature and RH during PSD 

exposures. 

A.9.2 Measure the flow rates of standards 

and purified house air immediately following 

PSD exposures. 

A.10 Calibration and Standardization 

A.10.1 Follow the procedures described 

in Method 325B Section 10.0 for calibration. 

A.10.2 Verify chamber concentration by 

direct injection into a gas chromatograph 

calibrated for the target compound(s) or by 

collection of an integrated SUMMA canister 

followed by analysis using a 

preconcentration gas chromatographic 

method such as EPA Compendium Method 

TO–15, Determination of VOCs in Air 

Collected in Specially-Prepared Canisters 

and Analyzed By GC/MS. 

A.10.2.1 To use direct injection gas 

chromatography to verify the exposure 

chamber concentration, follow the 

procedures in Method 18 of 40 CFR part 60, 

Appendix A–6. 

A.10.2.2 To verify exposure chamber 

concentrations using SUMMA canisters, 

prepare clean canister(s) and measure the 

concentration of VOC collected in an 

integrated SUMMA canister over the period 

used for the evaluation (minimum 24 hours). 

Analyze the TO–15 canister sample following 

EPA Compendium Method TO–15. 

A.10.2.3 Compare the theoretical 

concentration of volatile material added to 

the test chamber to the measured 

concentration to confirm the chamber 

operation. Theoretical concentration must 


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agree with the measured concentration 

within 30 percent. 

A.11 Analysis Procedure 

Analyze the sorbent tubes following the 

procedures described in Section 11.0 of 

Method 325B. 

A.12 Recordkeeping Procedures for 

Sorbent Tube Evaluation 

Keep records for the sorbent tube 

evaluation to include at a minimum the 

following information: 

A.12.1 Sorbent tube description and 

specifications. 

A.12.2 Sorbent material description and 

specifications. 

A.12.3 Volatile analytes used in the 

sampler test. 

A.12.4 Chamber conditions including 

flow rate, temperature, and relative humidity. 

A.12.5 Relative standard deviation of the 

sampler results at the conditions tested. 

A.12.6 95 percent confidence limit on the 

sampler overall accuracy. 

A.12.7 The relative accuracy of the 

sorbent tube results compared to the direct 

chamber measurement by direct gas 

chromatography or SUMMA canister 

analysis. 

A.13 Method Performance 

A.13.1 Sorbent tube performance is 

acceptable if the relative accuracy of the 

passive sorbent sampler agrees with the 

active measurement method by ±10 percent 

at the 95 percent confidence limit and the 

uptake ratio is greater than 0.5 mL/min (1 ng/ 

ppm-min). 

Note: For example, there is a maximum 

deviation comparing Perkin-Elmer passive 

type sorbent tubes packed with Carbopack X 

of 1.3 to 10 percent compared to active 

sampling using the following uptake rates. 

1,3-butadiene 

uptake rate 

mL/min 

Estimated 

detection 

limit 

(2 week) 

Benzene 

uptake rates 

mL/min 

Estimated 

detection 

limit 

(2 week) 

Carbopack X (2 week) ..................................................................... 0.61 ± 0.11 a 0.1 ppbv 0.67 a 0.05 ppbv 

a McClenny, W.A., K.D. Oliver, H.H. Jacumin, Jr., E.H. Daughtrey, Jr., D.A. Whitaker. 2005. 24 h diffusive sampling of toxic VOCs in air onto 

Carbopack X solid adsorbent followed by thermal desorption/GC/MS analysis—laboratory studies. J. Environ. Monit. 7:248–256. 

A.13.2 Data Analysis and Calculations for 

Method Evaluation 

A.13.2.1 Calculate the theoretical 

concentration of VOC standards using 

Equation A.1. 

Where: 

Cf = The final concentration of standard in 

the exposure chamber (ppbv). 

FRi = The flow rate of the target compound 

I (mL/min). 

FRt = The flow rate of all target compounds 

from separate if multiple cylinders are 

used (mL/min). 

FRa = The flow rate of dilution air plus 

moisture (mL/min). 

Cs = The concentration of target compound 

in the standard cylinder (parts per 

million by volume). 

A.13.2.3 Determine the uptake rate of the 

target gas being evaluated using Equation 

A.2. 

Where: 

Mx = The mass of analyte measured on the 

sampling tube (hg). 

Ce = The theoretical exposure chamber 

concentration (hg/mL). 

Tt = The exposure time (minutes). 

A.13.2.4 Estimate the variance (relative 

standard deviation (RSD)) of the intersampler results at each condition tested using 

Equation A.3. RSD for the sampler is 

estimated by pooling the variance estimates 

from each test run. 

Where: 

Xi = The measured mass of analyte found on 

sorbent tube i. 

Xi = The mean value of all Xi. 

n = The number of measurements of the 

analyte. 

A.13.2.4 Determine the percent relative 

standard deviation of the inter-sampler 

results using Equation A.4. 


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A.13.2.5 Determine the 95 percent 

confidence interval for the sampler results 

using Equation A.5. The confidence interval 

is determined based on the number of test 

runs performed to evaluate the sorbent tube 

and sorbent combination. For the minimum 

test requirement of eight samplers tested at 

two concentrations, the number of tests is 16 

and the degrees of freedom are 15. 

Where: 

D95% = 95 percent confidence interval. 

%RSD = percent relative standard deviation. 

t0.95 = The Students t statistic for f degrees 

of freedom at 95 percent confidence. 

f = The number of degrees of freedom. 

n = Number of samples. 

A.13.2.6 Determine the relative accuracy 

of the sorbent tube combination compared to 

the active sampling results using Equation 

A.6. 

Where: 

RA = Relative accuracy. 

Xi = The mean value of all Xi. 

XA = The average concentration of analyte 

measured by the active measurement 

method. 

D95% = 95 percent confidence interval. 

A.14 Pollution Prevention 

This method involves the use of ambient 

concentrations of gaseous compounds that 

post little or no pollution to the environment. 

A.15 Waste Management 

Expired calibration solutions should be 

disposed of as hazardous materials. 

A.16 References 

1. ISO TC 146/SC 02 N 361 Workplace 

atmospheres—Protocol for evaluating the 

performance of diffusive samplers. 

[FR Doc. 2014–12167 Filed 6–26–14; 8:45 am] 

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