[Federal Register Volume 63, Number 176 (Friday, September 11, 1998)]
[Proposed Rules]
[Pages 48890-48924]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-23508]
[[Page 48889]]
_______________________________________________________________________
Part III
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Source
Categories; National Emission Standards for Hazardous Air Pollutants
From Petroleum Refineries--Catalytic Cracking (Fluid and Other) Units,
Catalytic Reforming Units, and Sulfur Plant Units; Proposed Rule
Federal Register / Vol. 63, No. 176 / Friday, September 11, 1998 /
Proposed Rules
[[Page 48890]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[IL-64-2-5807; FRL-6154-3]
RIN 2060-AF28
National Emission Standards for Hazardous Air Pollutants for
Source Categories; National Emission Standards for Hazardous Air
Pollutants from Petroleum Refineries--Catalytic Cracking (Fluid and
Other) Units, Catalytic Reforming Units, and Sulfur Plant Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule and notice of public hearing.
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SUMMARY: This action proposes national emission standards for hazardous
air pollutants (NESHAP) from process vents associated with certain new
and existing affected sources at petroleum refineries. Hazardous air
pollutants (HAP) that would be reduced by this proposed rule include
organics (acetaldehyde, benzene, formaldehyde, hexane, phenol, dioxins,
furans, toluene, and xylene) and reduced sulfur compounds (carbonyl
sulfide, carbon disulfide); inorganics (hydrogen chloride, chlorine);
and particulate metals (antimony, arsenic, beryllium, cadmium,
chromium, cobalt, lead, manganese, and nickel). The health effects of
exposure to these HAP can include cancer, respiratory irritation, and
damage to the nervous system.
The standards are proposed under the authority of section 112(d) of
the Clean Air Act (the Act) as amended and are based on the
Administrator's determination that petroleum refinery catalytic
cracking units (CCU), catalytic reforming units (CRU), and sulfur plant
units (SRU) may reasonably be anticipated to emit one or more of the
HAP listed in section 112(b) of the Act from the various process vents
found within these petroleum refinery process units. The proposed
NESHAP would protect the public health and environment by requiring all
petroleum refineries that are major sources to meet emission standards
reflecting application of the maximum available control technology
(MACT).
DATES: Comments. Comments on the proposed rule must be received on or
before November 10, 1998.
Public Hearing. If anyone contacts the EPA requesting to speak at a
public hearing by October 2, 1998, a public hearing will be held on
October 13, 1998, beginning at 10 a.m. For more information, see
section VII.B of SUPPLEMENTARY INFORMATION.
ADDRESSES: Comments. Interested parties may submit written comments (in
duplicate, if possible) to Docket No. A-97-36 at the following address:
Air and Radiation Docket and Information Center (6102), U.S.
Environmental Protection Agency, 401 M Street, SW., Washington, DC
20460. The EPA requests that a separate copy of the comments also be
sent to the contact person listed below. The docket is located at the
above address in Room M-1500, Waterside Mall (ground floor).
A copy of today's document, technical background information, and
other materials related to this rulemaking are available for review in
the docket. Copies of this information may be obtained by request from
the Air Docket by calling (202) 260-7548. A reasonable fee may be
charged for copying docket materials.
Public Hearing. If anyone contacts the EPA requesting a public
hearing by the required date (see DATES), the public hearing will be
held at the EPA Office of Administration Auditorium, Research Triangle
Park, NC. Persons interested in presenting oral testimony should notify
Ms. Jolynn Collins, Waste and Chemical Process Group, Emission
Standards Division (MD-13), U.S. Environmental Protection Agency,
Research Triangle Park, NC 27711, telephone number (919) 547-5671.
FOR FURTHER INFORMATION CONTACT: For information concerning the
proposed regulation, contact Robert B. Lucas, Waste and Chemical
Process Group, Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, NC 27711,
telephone number (919) 541-0884, facsimile number (919) 541-0246,
electronic mail address, ``[email protected].''
SUPPLEMENTARY INFORMATION:
Regulated Entities. Entities potentially regulated by this action
are facilities (i.e., petroleum refineries) that utilize fluid or other
CCU, CRU, or SRU in their refining processes. Regulated categories and
entities include:
------------------------------------------------------------------------
Examples of regulated
Category entities
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Industry.................................. Petroleum Refineries (SIC
2911).
Federal government........................ Not affected.
State/local/tribal government............. Not affected.
------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that the Agency is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table also could be regulated. To determine
whether your facility or company is regulated by this action, you
should carefully examine the applicability criteria in section III.A of
this document and in Sec. 63.1560 of the proposed rule. If you have
questions regarding the applicability of this action to a particular
entity, consult the person listed in the preceding FOR FURTHER
INFORMATION CONTACT section.
Internet. The text of today's document also is available on the
EPA's web site on the Internet under recently signed rules at the
following address: http://www.epa.gov/ttn/oarpg/rules.html. The EPA's
Office of Air and Radiation (OAR) homepage on the Internet also
contains a wide range of information on the air toxics program and many
other air pollution programs and issues. The OAR's homepage address is:
http://www.epa.gov/oar/.
Electronic Access and Filing Addresses. The official record for
this rulemaking, as well as the public version, has been established
for this rulemaking under Docket No. A-97-36 (including comments and
data submitted electronically). A public version of this record,
including printed, paper versions of electronic comments, which does
not include any information claimed as confidential business
information (CBI), is available for inspection from 8 a.m. to 5:30
p.m., Monday through Friday, excluding legal holidays. The official
rulemaking record is located at the address in ADDRESSES at the
beginning of this document.
Electronic comments can be sent directly to the EPA's Air and
Radiation Docket and Information Center at: ``A-and-R-
D[email protected].'' Electronic comments must be submitted as an
ASCII file avoiding the use of special characters and any form of
encryption. Comments and data will also be accepted on disks in
WordPerfect in 5.1 file format or ASCII file format. All comments and
data in electronic form must be identified by the docket number (A-97-
36). No CBI should be submitted through electronic mail. Electronic
comments on this proposed rule may be filed online at many Federal
Depository Libraries.
Outline. The information in this preamble is organized as shown
below.
I. Statutory Authority
II. Introduction
A. Background
B. NESHAP for Source Categories
C. Health Effects of Pollutants
[[Page 48891]]
D. Petroleum Refining Industry
1. Catalytic Cracking Units
2. Catalytic Reforming Units
3. Sulfur Plant Units
III. Summary of the Proposed Rule
A. Applicability
B. Subcategories
C. Emission Control Technology
D. Emission Limits
E. Emission Monitoring and Compliance Provisions
F. Notification, Reporting, and Recordkeeping Requirements
1. Notifications
2. Periodic Reports
3. Recordkeeping
IV. Selection of Proposed Standards
A. Selection of Source Category
B. Selection of Emission Sources and Pollutants
C. Selection of Proposed Standards for Existing and New Sources
1. Background
2. MACT Floor Technology and Emission Limits
D. Selection of Monitoring Requirements
V. Summary of Impacts of Proposed Standards
A. Air Quality Impacts
B. Cost Impacts
C. Economic Impacts
D. Non-air Health and Environmental Impacts
E. Energy Impacts
VI. Request for Comments
A. Non-fluidized Catalytic Cracking Units and Non-Claus Sulfur
Recovery Units
B. Potential Emission Sources
C. Catalytic Cracking Unit Control Device Maintenance
D. Subcategorization of Catalytic Cracking Units
E. Catalytic Reforming Unit Depressuring/Purging Cutoff Value
F. Monitoring of Catalytic Reforming Units with Internal
Scrubbing Systems
G. Alternative CCU Standard
H. Overlap with New Source Performance Standard
I. Status of Exceedances and Excursions
VII. Administrative Requirements
A. Docket
B. Public Hearing
C. Executive Order 12866
D. Enhancing the Intergovernmental Partnership Under Executive
Order 12875
E. Unfunded Mandates Act
A. Executive Order 13045
G. Regulatory Flexibility
H. Paperwork Reduction Act
I. Pollution Prevention Act
J. National Technology Transfer and Advancement Act
K. Clean Air Act
L. Executive Order 13084
I. Statutory Authority
The statutory authority for this proposal is provided by sections
101, 112, 114, 116, and 301 of the Clean Air Act, as amended (42 U.S.C.
7401, 7412, 7414, 7416, and 7601).
II. Introduction
A. Background
Section 112 of the Act lists HAP and directs the EPA to develop
rules to control all major and some area sources emitting HAP. On July
16, 1992 (57 FR 31576), the EPA published a list of major and area
source categories for which NESHAP are to be promulgated. Petroleum
refineries were listed under two source categories. On December 3, 1993
(58 FR 83941), the EPA published a schedule for promulgating standards
for the listed major and area sources. Standards for the first source
category, ``Other Sources Not Distinctly Listed,'' were scheduled for
promulgation on November 15, 1994. The EPA promulgated those standards
under a July 28, 1995, court-ordered deadline; the regulations,
``National Emission Standards for Hazardous Air Pollutants: Petroleum
Refineries,'' were published on August 18, 1995 (60 FR 43244). Those
standards, however, did not address three process unit vents which are
the subject of today's proposed rulemaking. ``Petroleum Refineries:
Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units,
and Sulfur Plant Units'' is the second listed source category and the
published schedule requires the EPA to promulgate standards for this
source category by November 15, 1997.
The proposed NESHAP was developed by the EPA in concert with State
regulators, industry representatives, individual States (California,
Louisiana, Texas, and Illinois) and associated groups including STAPPA/
ALAPCO (State and Territorial Air Pollution Program Administrators
Association/Association of Local Air Pollution Control Officials). The
rule development process included a cooperative effort in identifying
data needs; collecting additional data; conducting emission testing
with shared funding from the EPA and the California Air Resources Board
(CARB); and meeting with representatives of the various stakeholders to
share technical information.
Refineries affected by the standards could achieve the proposed
requirements by upgrading existing emission controls, installing new
control devices, or implementing source reduction measures, depending
on site-specific characteristics of the source and the associated
refinery operation. Alternative compliance options also are included to
provide operational flexibility and to encourage pollution prevention.
For example, facilities which hydrotreat to remove metals from the feed
can meet the alternative nickel (Ni) standard with a less effective
control device. Similarly, sulfur plants which recover additional
sulfur with effective tail gas treatment can meet performance levels
equivalent to facilities with a vapor incinerator.
The EPA estimates nationwide HAP emissions from the process vents
on these three unit operations at about 7,270 megagrams per year (Mg/
yr) (8,000 tons per year (tpy)) at current levels of control. Raising
the control performance of affected petroleum refinery process units
with MACT-level standards would reduce nationwide HAP emissions from
process vents on the three affected unit operations by about 82 percent
from the current level, with higher reductions achieved at particular
sites. Other benefits of this action would include a significant
decrease in nationwide emissions of non-HAP pollutants (over 132,000
tpy) and lowered occupational exposure levels for employees.
This emission reduction would be achieved with no adverse economic
effects on the industry or small refineries. The nationwide total
capital and annualized costs of control equipment are estimated at $173
million and $43.7 million/yr, respectively. An additional $6.5 million
in total capital investment with a total annual cost of $9.8 million/yr
is estimated for monitoring/implementation costs.
B. NESHAP for Source Categories
Section 112 of the Act requires that the EPA promulgate regulations
for the control of HAP emissions from both new and existing major
sources. The regulations must reflect the maximum degree of reduction
in emissions of HAP that is achievable taking into consideration the
cost of achieving the emission reduction, any non-air quality health
and environmental impacts, and energy requirements. This level of
control is commonly referred to as maximum achievable control
technology (MACT). For new sources, MACT standards cannot be less
stringent that the emission control that is achieved in practice by the
best-controlled similar source. (See CAA section 112(d)(3).) The MACT
standards for existing sources cannot be less stringent than the
average emission limitation achieved by the best-performing 12 percent
of existing sources for categories and subcategories with 30 or more
sources, or the best-performing 5 sources for categories or
subcategories with fewer than 30 sources.
The control of HAP is achieved through the promulgation of either
technology-based emission standards
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under sections 112(d) and 112(f) or work practice standards under
112(h) for categories of sources that emit HAP. Emission reductions may
be accomplished through the application of measures, processes,
methods, systems, or techniques including, but not limited to: (1)
Reducing the volume of, or eliminating emissions of, such pollutants
through process changes, substitution of materials, or other
modifications; (2) enclosing systems or processes to eliminate
emissions; (3) collecting, capturing, or treating such pollutants when
released from a process, stack, storage or fugitive emissions point;
(4) design, equipment, work practice, or operational standards
(including requirements for operator training or certification) as
provided in section (h); or (5) a combination of the above. (See CAA
section 112(d)(2).)
C. Health Effects of Pollutants
The Clean Air Act was created in part to protect and enhance the
quality of the Nation's air resources so as to promote the public
health and welfare and the productive capacity of its population. (See
CAA section 101(b)(1).) Section 112(b) of the Act lists HAP believed to
cause adverse health or environmental effects. Section 112(d) of the
Act requires that emission standards be promulgated for all categories
and subcategories of major sources of these HAP and for many smaller
``area'' sources listed for regulation under section 112(c) in
accordance with the schedules established under sections 112(c) and
112(e). Major sources are defined as those that emit or have the
potential to emit at least 10 tpy of any single HAP or 25 tpy of any
combination of HAP.
As previously explained, in the 1990 Amendments to the CAA,
Congress specified that each standard for major sources must require
the maximum reduction in emissions of HAP that the EPA determines is
achievable considering cost, health and environmental impacts, and
energy impacts. In essence, these MACT standards would ensure that all
major sources of air toxic emissions achieve the level of control
already being achieved by the better controlled and lower emitting
sources in each category. This approach provides assurance to citizens
that each major source of toxic air pollution will be required to
effectively control its emissions. At the same time, this approach
provides a level economic playing field, ensuring that facilities that
employ cleaner processes and good emissions control are not at an
economic disadvantage relative to competitors with poorer controls.
Emission data collected during development of the proposed NESHAP
show that pollutants that are listed in section 112(b)(1) and are
emitted from vents on CCU, CRU, and SRU include both inorganic HAP
(including metal HAP) and organic HAP. Hazardous air pollutants from
CCU include acetaldehyde, antimony, arsenic compounds, beryllium,
benzene, 1,3-butadiene, cadmium, chromium, cobalt compounds, 2,3,7,8-
TCDD, formaldehyde, hexane, lead compounds, mercury compounds,
manganese, nickel compounds, phenol, polycyclic organic matter,
toluene, and xylene. Catalytic reforming units emit benzene, chlorine,
organic chlorides, naphthalene, dibenzo furans and 2,3,7,8-TCDD,
polycyclic organic matter, toluene, xylene, hexane, and hydrogen
chloride. Sulfur recovery plants release emissions of benzene, toluene,
carbonyl sulfide, carbon disulfide, and formaldehyde. The majority of
these pollutants will be reduced by implementation of the proposed
emission limits. Following is a summary of the potential health and
environmental effects associated with exposures, at some level, to
emitted pollutants that would be reduced by the standard.
Several metals appearing on the section 112(b) list of HAP are
emitted from CCU, CRU, and SRU at petroleum refineries. The nonvolatile
metals of greatest concern that would be reduced by the standard are
antimony, cadmium, chromium, nickel, beryllium, and manganese. These
metals can cause effects such as mucous membrane irritation (e.g.,
bronchitis, decreased lung capacity), gastrointestinal effects, nervous
system disorders (from loss of function to tremor and numbness), skin
irritation, and reproductive and developmental disorders. Additionally,
several of the metals accumulate in the environment and in the human
body. Cadmium, for example, is a cumulative pollutant, which can cause
kidney effects even after the cessation of exposure. Similarly, the
onset of effects from beryllium exposure may be delayed 3 months to 15
years. Many of the metals also are known (arsenic, chromium VI, and
certain nickel compounds) or probable (cadmium, lead, and beryllium)
human carcinogens.
Organic compounds that would be reduced by this standard include
benzene, formaldehyde, and phenol, among others. Some of the effects of
these pollutants are similar to those caused by metal HAP and include
irritation from short-term exposures to eye, nose, and throat;
respiratory effects (expressed as labored breathing, impaired lung
function); and reproductive and developmental effects. Developmental
and kidney effects and cardiac effects have been reported for phenol,
which is considered to be quite toxic to humans via oral exposure. In
addition to these noncancer effects, formaldehyde has been classified
as a probable human carcinogen. Benzene, a class A or known human
carcinogen, is a concern because long-term exposure causes an increased
risk of cancer in humans, and is also associated with aplastic anemia,
pancytopenia, chromosomal breakages, and weakening of the bone marrow.
Emissions of carbonyl sulfide (COS) also would be reduced by the
standard. Information as to the potential health effects of COS are
limited. Short-term inhalation of a high concentration of COS may cause
narcotic central nervous system effects and skin and eye irritation in
humans. No information is available on reproductive or developmental
effects from COS exposure, and the EPA has not classified this
pollutant with respect to its potential carcinogenicity.
Adverse health effects from exposure to hydrogen chloride (HCl)
also have been documented. Chronic occupational exposure to HCl has
been reported to cause gastritis, chronic bronchitis, dermatitis, and
photosensitization in workers. Acute inhalation exposure many cause
coughing, hoarseness, inflammation and ulceration of the respiratory
tract, chest pain, and pulmonary edema in humans. No information is
available on any potential carcinogenic effects of HCl in humans and
the EPA has not classified this chemical with respect to potential
carcinogenicity. Only limited data are available on the reproductive
and developmental effects of HCl.
In addition to HAP, the proposed standard also would reduce some of
the pollutants whose emissions are controlled to meet National Ambient
Air Quality Standards (NAAQS). These pollutants include particulate
matter (PM), carbon monoxide (CO), volatile organic compounds (VOC),
and lead. The effects of PM, CO, ozone (derived, in part, from VOC) and
lead that would be reduced by this standard are described in the EPA's
Criteria Documents, which support the NAAQS. Briefly, PM emissions have
been associated with aggravation of existing respiratory and
cardiovascular disease and increased risk of premature death. Volatile
organic compounds (e.g., formaldehyde) are precursors to the formation
of ozone in the ambient air.
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At elevated levels, ozone has been shown in human laboratory and/or
community studies to be responsible for the reduction of lung function,
respiratory symptoms (e.g., cough, chest pain, throat and nose
irritation), increased hospital admissions for respiratory causes, and
increased lung inflammation. Animal studies have shown increased
susceptibility to respiratory infection and lung structure changes.
Ambient ozone also has been linked to adverse effects on agricultural
crops and forests. Carbon monoxide enters the blood stream and reduces
oxygen delivery to the body's organs and tissues. Exposure to CO has
been associated with reduced time to onset of angina pain, impairment
of visual perception, work capacity, manual dexterity, learning
ability, and performance of complex tasks. Depending on the degree of
exposure, lead can cause subtle effects on behavior and cognition,
increased blood pressure, reproductive effects, seizures, and even
death.
The EPA recognizes that the degree of adverse effects to health can
range from mild to severe. The extent and degree to which the health
effects may be experienced is dependent upon: (1) The ambient
concentrations observed in the area, (e.g., as influenced by emission
rates, meteorological conditions, and terrain); (2) the frequency of
and duration of exposures; (3) characteristics of exposed individuals
(e.g., genetics, age, pre-existing health conditions, and lifestyle)
which vary significantly with the population; and (4) pollution
specific characteristics (e.g., toxicity, half-life in the environment,
bioaccumulation, and persistence).
D. Petroleum Refining Industry
The petroleum refining industry in 1997 consisted of 162 petroleum
refineries operated by 90 firms in 33 States nationwide that refined
approximately 15 million barrels of crude oil daily. Of the total
number of U.S. refineries, 71 were located in three States (i.e.,
California, Texas, and Louisiana) and accounted for about 54 percent of
the crude capacity. The three types of process units (CCU, CRU, and
SRU) classified within the source category regulated in today's
proposed rule are commonly found at petroleum refineries throughout the
U.S. The processes are described below.
1. Catalytic Cracking Units
Catalytic cracking is a decomposition process whereby heavier
weight, higher boiling hydrocarbons such as gas oil are broken down by
heat in the presence of a catalyst to lighter weight, lower boiling,
higher value hydrocarbons such as gasoline blend stocks and heating
fuels. Technological developments have allowed catalytic cracking units
to accept a wide range of feedstocks varying from naphtha to heavy
crude residues. Current cracking catalysts incorporate zeolites
(molecular sieves) with alumina-silica matrix.
Fluidized-bed or moving bed reactors are used by 101 petroleum
refineries for catalytic cracking. The fluidized-bed processes are
predominant but some moving bed units are still in operation. Non-
fluidized CCU, which account for only 2.9 percent of the total
catalytic cracking process charge rate, were operated by 7 refineries
in 1997.
Fluid catalytic cracking has gained dominance in the catalytic
cracking industry because these units are typically more versatile and
flexible than other (non-fluid) CCU, i.e., they have improved control
of process variables to maximize desired product yields. In January
1997, catalytic cracking (fluid or other) charge capacity was 5.2
million barrels per calendar day. Catalytic cracking charge capacities
of less than 10,000 barrels per calendar day were reported by 9
refineries. Charge capacities of greater than 100,000 barrels per
calendar day were reported by 8 refineries. About one-half of the
refineries with large charge capacities have more than one CCU.
Several proprietary fluidized-bed catalytic cracking processes are
available from various engineering construction companies and oil
refining research and development groups. In addition, each fluidized-
bed CCU operation is customized based on refinery specific process,
feedstock, and product mix requirements. Catalyst and feedstock are
introduced to the reactor through a vertical tube leading to the
reactor, i.e., the riser; the feedstock undergoes a cracking reaction
(typically in the riser) and some reaction products are deposited on
the catalyst; as the mixture of catalyst and products enter the reactor
vessel, steam is injected to strip products from the catalyst. With
use, the catalyst in an fluidized-bed CCU unit loses activity; coke and
some metals remain deposited on the catalyst. To restore catalyst
activity, the used or spent catalyst is routed continuously from the
reactor to a regenerator vessel; the catalyst activity is restored
substantially by burning off the coke in a controlled combustion
reaction; burning the coke also provides process heat necessary for the
proper functioning of the fluidized-bed CCU. The source of emissions
from both fluidized-bed units and moving-bed units is the regenerator
flue gas stream.
There are two basic types of fluidized-bed CCU regenerators:
complete burn/combustion regenerators and partial burn/combustion
regenerators. In partial burn/combustion regenerators, the controlled
burn involves addition of less than stoichiometric amounts of air, and
thus CO is generated rather than carbon dioxide (CO2). In
complete burn/combustion (also called high temperature) regenerators,
the regenerator is operated with a slight excess of oxygen (1 to 2
percent) to ensure complete combustion of the coke to CO2;
newer units are typically designed for complete combustion. The CO
content of the flue gas from a high temperature, complete burn/
combustion regenerator is about 0.4 percent by weight as compared to
the uncontrolled CO content of about 9.3 percent from a partial burn/
combustion regenerator system.
2. Catalytic Reforming Units
A CRU is designed to reform (i.e., change the chemical structure)
of naphtha into higher octane aromatics. This is accomplished by
passing naphtha through a reactor containing a catalyst at elevated
pressure and temperature to promote dehydrogenation, isomerization, and
hydrogenolysis reactions. The reforming process uses a platinum or
bimetal (e.g., platinum and rhenium) catalyst material. Halides
(chlorine and fluorine) promote the activity of the platinum-alumina
catalyst and are stripped from the surface of the catalyst as HCl or
hydrogen fluoride (HF) during the reforming reactions, thus reducing
catalyst activity.
Dehydrogenation reactions are favored by low pressure and high
temperature; however, coke (carbon) is also formed at low pressure
which tends to deactivate the catalyst and reduce yields. Coke
formation can be reduced by operating under high hydrogen pressure;
other important variables in dehydrogenation activity include
temperature, space velocity, recycle gas rate, and particle size of the
catalyst used. The desired product quality (octane number) may be
obtained by balancing the system pressure, temperature, space velocity,
and recycle gas rate even as catalyst activity decreases. When yields
can no longer be obtained, the catalyst must be regenerated.
In January 1997, catalytic reforming charge capacity was 3.65
million barrels per calendar day. Some form of CRU was operated by 124
refineries. The three major types of catalytic reforming processes are
semi-regenerative, cyclic, and continuous. Semi-regenerative,
[[Page 48894]]
used by 111 refineries with 49 percent of reforming capacity, is
characterized by the shutdown of the entire reforming unit (which
employs three to four separate reactors) at specified intervals or at
the operator's convenience, for in situ catalyst regeneration. Cyclic
regeneration, used by 23 refineries with 24 percent of reforming
capacity, is characterized by batch regeneration of catalyst in situ in
any one of several reactors (four or five separate reactors) that can
be isolated from and returned to the reforming operation, while
maintaining continuous reforming process operations (i.e., feedstock
continues flowing through the remaining reactors). Continuous
regeneration, used by 32 refineries with 27 percent of reforming
capacity, is characterized by continuous flow of catalyst material
through a reactor where it mixes with feedstock in counter-current
direction, and a portion of the catalyst is continuously removed and
sent to a special regenerator where it is regenerated and recycled back
to the reactor.
3. Sulfur Plant Units
Sulfur compounds present in crude oil are converted to hydrogen
sulfide (H2S) in the cracking and hydro treating processes.
The H2S or ``acid gas'' is removed from the process vapors
using amine scrubbers. Amine scrubbers also remove CO2, COS,
carbon disulfide (CS2), nitrogen (N2) and water
(H2O). The H2S ``rich'' amine solution is
subsequently heated to release the H2S and other absorbed
components, which is then treated in the SRU to yield high purity
elemental sulfur that is sold as product. Sour water [water that
contains ammonia (NH3) and H2S] gases are also
commonly fed to the SRU. The NH3 is oxidized to nitrogen
dioxide (NO2) and H2O, and the H2S is
converted to elemental sulfur in the SRU.
Sulfur recovery (the conversion of H2S to elemental
sulfur) is typically accomplished using the modified-Claus process,
which consists of a thermal reactor and multi-stage catalytic reactors
in series. First, one-third of the H2S is burned with air in
a thermal reactor furnace to yield sulfur dioxide (SO2). The
SO2 then reacts reversibly with H2S in the
presence of a catalyst to produce sulfur, water, and heat. Since the
reaction is reversible, the reaction occurs in a series of catalytic
reactors (or stages), and the vapors are cooled to condense the sulfur
between each reactor to drive the reaction towards completion. The
Claus gas is then reheated prior to introduction to the next catalytic
reactor (or stage). The conversion efficiencies of SRU range from 92
percent for a two-stage to 97 percent for a three-stage unit.
The gas from the final condenser of the SRU (referred to as the
``tail gas'') typically consists primarily of inert gases with less
than two percent sulfur compounds, which may include H2S,
SO2, CS2, and COS. There are numerous Claus tail
gas desulfurization systems in commercial operation in the U.S. Tail
gas treatment processes fall mainly into two categories: low-
temperature processes and single compound processes (e.g.,
SCOTTM, BeavonTM, and Wellman-LordTM.
SCOTTM tail gas treatment includes: Catalytic reduction to
convert the tail gas sulfur compounds to H2S; amine
adsorption to recover and recycle any H2S present in the
tail gas; and incineration to convert the remaining tail gas sulfur
compounds to SO2. Sulfur recovery efficiencies of catalytic
reduction followed by amine recovery typically range from 92 to 97
percent; therefore, the combined efficiency of the SRU and tail gas
recovery systems can exceed 99.5 percent. After incineration, the
treated tail gas consists primarily of inert gases with an
SO2 concentration of between 200 and 500 parts per million
(ppm) with trace amounts of H2S, COS, and CS2.
In 1985, production of sulfur from petroleum refineries was
reported at 2.9 million Mg compared to 4.2 million Mg in 1990. In 1992,
130 U.S. refineries reported operating some form of SRU with a
production capacity of approximately 20,500 Mg/day. Capacities of less
than 50 Mg/day were reported by 52 refineries. Capacities of greater
than 300 Mg/day were reported by 24 refineries and 5 refineries
reported capacities of greater than 500 Mg/day. Of the 130 refineries,
88 provided the number of SRU or Claus trains at the facility. The
total number of SRU reported was 144; 38 refineries reported multiple
trains with 13 refineries reporting 3 or more SRU.
A new source performance standard (NSPS) for petroleum refineries
(40 CFR part 60, subpart J) limits PM and CO from fluidized-bed CCU
catalyst regeneration vents, H2S from fuel gas combustion
devices, and SO2 from SRU vents on Claus plants of greater
than 20 long tons per day. This rule affects fluidized-bed CCU
constructed or modified after June 11, 1973, and Claus SRU constructed
or modified after October 4, 1976. Any fluidized-bed CCU, constructed
or modified before January 17, 1984, in which a contact material reacts
with petroleum derivatives to improve feedstock quality and in which
the contact material is regenerated by burning-off coke and/or other
deposits is exempt from the NSPS.
III. Summary of the Proposed Rule
A. Applicability
The proposed standard would apply to emissions of HAP from process
vents on each affected source at any petroleum refinery that is a major
source of HAP emissions as defined in Sec. 63.2 of 40 CFR part 63. All
of the nation's 162 petroleum refineries are believed to be major
sources of HAP.
New and existing sources subject to the proposed NESHAP are: (1)
The process vent or group of process vents on each fluidized-bed and
other (i.e., non-fluid) CCU that is associated with regeneration of the
catalyst used in the unit (i.e., the catalyst regeneration flue gas
vent); (2) the process vent or group of process vents on each semi-
regenerative, cyclic, or continuous CRU that is associated with
regeneration of the catalyst used in the unit; and (3) the process vent
or group of process vents that vent from each Claus or other (i.e.,
non-Claus) SRU or the tail gas treatment unit serving the sulfur
recovery plant, that is associated with sulfur recovery. Processes
which do not recover elemental sulfur do not meet the definition of a
SRU, and therefore, are not subject to the proposed standards. Gaseous
streams routed to a fuel gas system also are not subject to the
proposed standards.
The proposed standard would prevent facilities subject to the NSPS
control requirements for CCU and SRU from having to do a second
compliance demonstration for the MACT standard. The owner or operator
of a fluidized-bed CCU catalyst regenerator subject to and
demonstrating compliance with the NSPS PM and CO standards and all
associated requirements (e.g., performance test, monitoring,
recordkeeping, and reporting) is considered to be in compliance with
the MACT standard and associated requirements for CCU. The owner or
operator of a Claus SRU subject to and demonstrating compliance with
the NSPS sulfur oxides standard and associated requirements is
considered to be in compliance with the MACT standard and associated
requirements for SRU. Any CCU or SRU not subject to the NSPS that is
subject to this MACT standard must comply with the requirements of this
subpart. For example, an existing CCU not subject to the NSPS must
demonstrate compliance in accordance with the requirements of this
subpart. This approach is intended to reduce burden by minimizing
duplication without affecting the NSPS
[[Page 48895]]
requirements and related requirements such as new source review,
prevention of significant deterioration, and other Title I
requirements. The EPA requests comments on this regulatory approach or
other approaches that minimize duplication without reducing or changing
the NSPS standards.
B. Subcategories
Section 112(d) of the Act requires the EPA to establish emission
standards for each category or subcategory of major and area sources.
Section 112(d)(1) of the Act provides that the Administrator may
distinguish among classes, types, and sizes of sources within a
category in establishing the standards. In establishing subcategories,
the EPA has considered factors such as air pollution control
engineering differences, process operations (including differences
between batch and continuous operations), emission characteristics,
control device applicability, and opportunities for pollution
prevention.
The EPA's analysis of existing CRU resulted in the designation of
two subcategories for the proposed emission standard for HCl during the
coke burn-off step that are based primarily on differences in the
process operations, process equipment, and emissions. One subcategory
is for existing units using the semi-regenerative regeneration process,
and the other is a separate subcategory for units using either
continuous or cyclic regeneration. The composition, quantity, and
frequency of HCl emissions as well as the level of control achieved
from the semi-regenerative process are quite different from those
associated with the other processes. In the semi-regenerative process,
emissions occur at a much lower frequency and duration because the
regeneration is performed infrequently at specified intervals, which in
turn affects the short-term emission rate as well as the performance
and effectiveness of emission control techniques. No separate
subcategories were developed for the depressurization or purge cycle
because the emissions and applicable controls are similar for all three
types of CRU regeneration processes. However, the proposed control
requirements for CRU do not apply to depressuring and purging
operations at a differential pressure between the reactor vent and the
gas transfer system to the control device of less than 1 pound per
square inch gauge (psig) or if the reactor vent pressure is 1 psig or
less.
No subcategories were developed for the CCU catalyst regeneration
vent or process vents associated with sulfur recovery plants. The MACT
emission control technologies for these sources were found to be
generally applicable for all of these units. However, the EPA is
collecting additional information to evaluate whether additional
subcategories may be warranted due to process variations and is
requesting comments on this topic as discussed in section VI.D of this
document. (Additional discussion of subcategorization for this source
category is contained in section IV.C.1 of this document.)
C. Emission Control Technology
No additional control technology options were identified that had
been demonstrated to be more effective than the MACT floor technologies
that would achieve significant additional reductions in HAP emissions.
Consequently, the technologies associated with the MACT floor were also
determined to represent the MACT technology from this source category.
The MACT control option for emissions of metal HAP from the CCU
catalyst regeneration vent during the coke burn-off is the control of
PM or Ni by a wet scrubber or electrostatic precipitator (ESP), which
were found to provide equivalent levels of emission control for metal
HAP. The MACT control option for organic HAP from the regeneration
vents for CCUs and for CRUs is complete combustion to destroy the
organic compounds using complete burn/combustion regeneration process
for the CCU, or venting either type of unit to a boiler, process
heater, flare, or other combustion device. The MACT emission control
technology for the coke burn-off during catalytic reforming
regeneration is the use of a wet scrubber to remove HCl. For sulfur
recovery plants, the MACT control option for organic HAP, which are
reduced sulfur compounds (COS and CS2), is oxidation to
SO2 using a vapor incinerator.
D. Emission Limits
Analysis of available information and data led the EPA to conclude
that the MACT level of control for metal HAP from each new, existing,
and reconstructed CCU is a PM limit for the catalyst regeneration vent
of 1.0 kilogram (kg) per 1,000 kg (1.0 lb per 1,000 lb) of coke burn-
off, where PM is a surrogate for total metal HAP. The proposed limit is
in the same format as the NSPS (40 CFR part 60, subpart J)--kg of PM
per 1,000 kg of coke burn-off. To provide flexibility in compliance and
to encourage pollution prevention (such as the use of feedstocks with
lower metal content), an alternative limit of 13,000 milligrams per
hour (mg/hr) (0.029 lb/hr) of Ni for the catalyst regenerator vent on
each CCU also is proposed.
For organic HAP from each new, existing, or reconstructed CCU, the
MACT control for the catalyst regeneration vent is complete combustion,
which is characterized as an emission limit of 500 parts per million by
volume (ppmv) for CO as an indicator of combustion efficiency. This
also is the NSPS level used to characterize complete combustion of a
fluidized-bed CCU catalyst regeneration vent stream.
Proposed standards also were developed for HCl emissions from the
catalyst regeneration vent on each new, existing, or reconstructed CRU.
For an existing semi-regenerative unit, uncontrolled HCl emissions
during coke burn-off and catalyst regeneration must be reduced by at
least 92 percent or to an outlet concentration of 30 ppmv or less. For
an existing unit using cyclic or continuous regeneration or a new or
reconstructed unit using a semi-regenerative, cyclic, or continuous
process, HCl emissions must be reduced by at least 97 percent or to an
outlet concentration of 10 ppmv or less.
Organic emissions from the catalyst regeneration vent on each new,
existing, or reconstructed CRU must be controlled by combustion. The
owner or operator may vent emissions to a flare that meets the EPA's
design and operation requirements, or use a control device to reduce
uncontrolled emissions by at least 98 percent or to an outlet
concentration of 20 ppmv or less.
Emissions of HAP from each new, existing, or reconstructed SRU,
expressed as total reduced sulfur (TRS) compounds to represent COS and
CS2, cannot exceed a concentration of 300 ppmv.
E. Emission Monitoring and Compliance Provisions
The proposed standard requires an initial performance test to
demonstrate compliance with the emission limits for vents on each CCU,
CRU, and SRU. The proposed rule allows 150 days following the
compliance test date to conduct the tests and report the results in the
notification of compliance status report. The initial performance test
for a semi-regenerative CRU may be conducted at the first regeneration
cycle following the compliance date. The initial performance test, and
all subsequent performance tests, are to be conducted according to the
provisions in the NESHAP general provisions in 40 CFR part 63, subpart
A and in the proposed rule.
For CCU, Methods 5B or 5F (40 CFR part 60, appendix A) are used to
[[Page 48896]]
determine PM emissions, and Method 29 (40 CFR part 60, appendix A) is
used to determine Ni emissions. The proposed rule includes calculation
procedures to demonstrate compliance with the proposed PM limit in the
kg/1,000 kg (lb/1,000 lb) of coke burn-off format and the Ni limit in
the mg/hr (lb/hr) format.
The proposed rule requires a performance test by Method 10 (40 CFR
part 60, appendix A) to demonstrate compliance with the CO limit for
CCU catalyst regeneration vents. To determine compliance with the
requirements for 98 percent removal or an outlet concentration of 20
ppmv for organic emissions from the CCU catalyst regeneration vent,
either Methods 18 or 25A (40 CFR part 60, appendix A) can be used. The
proposed rule contains calculation procedures and equations.
Emissions of HCl from the CRU catalyst regeneration vent are
measured using Method 26A (40 CFR part 60, appendix A) to establish
reduction efficiency or outlet concentration. Method 15 (40 CFR part
60, appendix A) is used to determine the concentration of TRS compounds
from SRU.
Performance tests to show 98 percent destruction of organic
compounds or an outlet concentration of 20 ppmv or less are not
required when any of three types of control devices are used: (1) A
boiler or process heater with a design heat input capacity of 44
megawatts (MW) or greater; (2) a boiler or process heater in which all
vent streams are introduced into the flame zone; or (3) a flare that
complies with the requirements for the proper design and operation of
flares in * 63.11(b) of the NESHAP general provisions. Flares must also
meet the requirements in 40 CFR 60.11(b), including the standard for
visible emissions as determined using Method 22 in appendix A to 40 CFR
part 60.
The owner or operator of an existing affected source has up to 3
years from the promulgation date of the final rule to demonstrate
compliance. The owner or operator may request an additional year
(resulting in a compliance date up to 4 years following the
promulgation date of the final rule) under section 112(i)(3)(B) of the
Act. A new or reconstructed source must demonstrate compliance upon
startup or by the date of promulgation of this subpart, whichever is
later.
The proposed standard requires the owner or operator to establish a
maximum or minimum value, as appropriate, for the process and control
device parameters being monitored that ensures the process or control
device is operating properly so that the emission limit is not
exceeded. The proposed standard allows the owner or operator to measure
and record process or operating parameters on a daily average or hourly
average basis, depending on the type of control device. Daily averages
would be calculated as the average of all values for a monitored
parameter recorded during the operating day. The average will cover a
24-hour period if the operation is continuous or the number of hours of
operation per day if operation is not continuous. Monitoring data
recorded during periods of unavoidable monitoring system breakdowns,
repairs, calibration checks, and zero (low-level) and high-level
adjustments; startup, shutdowns, and malfunctions; and periods of
nonoperating of the process unit resulting in cessation of the
emissions to which the monitoring applies would not be included in
monitoring averages. As discussed in section VI.C of this document, the
EPA requests comments on whether the monitoring averages also should
exclude periods of excess emissions resulting from non-operation of a
CCU control device during planned routine maintenance approved by the
applicable permitting authority.
If a thermal incinerator is used, the proposed standard requires
the owner or operator to monitor the daily average combustion zone
temperature. Monitoring of the daily average combustion temperature
also would be required for any facility using a boiler or process
heater less than 44 MW design heat input capacity where the vent stream
is not introduced into the flame zone. For a catalytic incinerator, the
owner or operator will monitor the daily average upstream temperature
and temperature difference across the catalyst bed. When a flare is
used, a device capable of detecting the presence of a pilot flame is
required, and the owner or operator will be required to record, for
each 1-hour period, whether the monitor was continuously operating and
whether the pilot flame was continuously present.
Where the owner or operator elects to use an ESP to comply with the
emission limits for CCU, the average hourly voltage and secondary
current to the control device or the average hourly total power input
must be monitored. If the owner or operator uses a wet scrubber to
comply with the requirements for either a CCU or CRU, the parameters to
be monitored include the average daily pressure drop across the
scrubber and the daily average flow rates of gas and water to the
scrubber from which the liquid-to-gas ratio would be calculated.
For facilities complying with the CO limit of 500 ppmv for
catalytic cracking regeneration, the owner or operator has a variety of
monitoring options. If a combustion control device is not used to
control emissions from a CCU, the average hourly temperature of the
regeneration process and the oxygen content of the regeneration vent
gas must be monitored. The owner or operator is not required to further
monitor the process or control device if he/she demonstrates that CO
emissions are less than 50 ppmv based on 30 days of continuous
monitoring. Alternatively, the owner or operator could install and
operate a CEM in accordance with the requirements of the NESHAP general
provisions (40 CFR part 63, subpart A), Performance Specification 4A in
appendix A to 40 CFR part 60, and the quality control requirements in
40 CFR part 60, appendix F.
The proposed standard would require monitoring of the daily average
coke burn-off rate for each fluidized-bed CCU catalyst regeneration
vent. The owner or operator would calculate and record the burn-off
rate using the equation in the proposed rule.
An owner or operator using a vent system that contains a bypass
line that could divert a vent stream away from the control device would
be required to install a flow indicator that determines, at least once
an hour, whether a vent stream flow is present or to secure the bypass
line valve in a closed position with a car-seal or a lock and key
configuration. If a flow indicator is used, a visual inspection must be
conducted at least once every hour to demonstrate that the monitor is
operating properly and that gas flow or vapor is not present. If a car-
seal or lock-and-key mechanism is used, a visual inspection must be
conducted at least once a month to ensure that the valve is maintained
in the closed position and that no gas or vapor are present. For all
bypass lines, the proposed rule also requires the owner or operator to
record the times and durations of any period when the vent stream is
diverted through a bypass line.
Following the performance test, more than one exceedance or
excursion during a semi-annual reporting period would be a violation of
the standard. As discussed in section VI.I of this document, EPA
requests comment on this proposed provision. An exceedance or excursion
may include: (1) An operating day when the daily average value of the
monitored parameter or any period when the average hourly value of the
monitored parameter, as applicable, falls below the minimum value (or
exceeds the maximum value) established for the monitored parameter; (2)
the average hourly CO concentration
[[Page 48897]]
measured by a CEM exceeds 500 ppmv; (3) an operating day when all pilot
flames of a flare are absent; (4) an operating day when monitoring data
are available for less than 75 percent of the operating hours (or less
than 18 values are recorded if an alterative data compression system is
used). For a control device where more than one parameter is monitored,
an excursion by more than one parameter would be considered a single
violation.
The proposed NESHAP contains provisions that would allow the owner
or operator to change control device and process parameter values from
those established, for example, during an initial performance test, by
conducting additional emission tests to verify and document compliance.
A new performance test also is required to establish a revised value
for the monitored parameter if there has been any change to process or
operating conditions that could result in a change in control system
performance since the last performance test. The owner or operator also
may request to monitor other parameters. Provisions are included for
the use of alternative monitoring systems such as an automated data
compression system.
F. Notification, Reporting, and Recordkeeping Requirements
General notification, reporting, and recordkeeping requirements for
all MACT standards are established in Sec. 63.10(b) of the NESHAP
general provisions (40 CFR part 63, subpart A). The proposed standard
incorporates most of these provisions, except that minor changes were
made to the notification and reporting requirements. Many initial
notifications are not required or are included in the notification of
compliance status report to reduce the burden and to streamline the
reporting requirements. The EPA believes that these provisions will
provide sufficient information to determine compliance or operating
problems at the source. At the same time, the provisions are not labor
intensive, do not require expensive, complex equipment, and are not
burdensome in terms of recordkeeping.
1. Notifications
The proposed requirements include one-time initial written
notifications of applicability for an area source that subsequently
becomes a major source and for a new or reconstructed source that has
an initial startup after the effective date and for which an
application for approval of construction or reconstruction is not
required. Notifications of intent to construct or reconstruct, the date
construction or reconstruction commenced, the anticipated startup date,
and the actual startup date are required for a new or reconstructed
major source that has an initial startup after the effective date and
for which an application for approval of construction or reconstruction
is required. The owner or operator who intends to construct a new
affected source or reconstruct an affected source subject to the rule,
or reconstruct an affected source such that it becomes subject to the
rule also must provide written notification. The application for
approval of construction or reconstruction may be used to fulfill this
requirement. This application must be submitted as far in advance of
startup as practicable, but not later than 90 days prior to startup for
a newly constructed or reconstructed source that has not started-up
before the effective date. The proposed NESHAP also requires written
notification of the expected date for conducting performance tests and
visible emission observations for flares.
Within 150 days of the effective date, the owner or operator of an
existing, new, or reconstructed affected source is required to submit a
notification of compliance status report to the applicable permitting
authority. In a State with an approved permit program which has not
been delegated authority under section 112(l) of the Act, a duplicate
report must be provided to the applicable Regional Administrator. The
owner or operator may submit the information in a permit application or
amendment, in a separate submittal, or in any combination. If the
information has already been submitted, a separate notification is not
required. The notification of compliance status report would include
information on applicability; affected sources; exempted sources;
control equipment or method of compliance; methods used to determine
compliance (e.g., performance test results, engineering assessments,
monitoring parameter values); and monitoring, maintenance, and quality
assurance/quality control.
To ensure continued proper operation of the control devices, the
proposed rule requires the owner or operator to include a maintenance
program for control devices in the notification of compliance status
report. Examples of the elements likely to be included in a maintenance
plan for wet scrubbers are shown below; similar elements would be
included in the plan for other types of control devices:
(1) Perform the manufacturer's recommended maintenance at the
recommended intervals on fresh solvent pumps, recirculating pumps,
discharge pumps, and other liquid pumps, and exhaust system and
scrubber fans and motors associated with pumps and fans;
(2) Clean the scrubber internals and mist eliminators at intervals
sufficient to prevent buildup of solids or other fouling that degrades
performance below emission limits or standards;
(3) Conduct a periodic inspection of each scrubber and: (a) Clean
or replace any plugged spray nozzles or other liquid delivery devices,
(b) repair or replace missing, damaged, or misaligned baffles, trays,
and other internal components, (c) repair or replace droplet eliminator
elements as needed, (d) repair or replace any heat exchanger elements
used for temperature control of fluids entering or leaving the
scrubber, and (e) check damper settings for consistency with the air
flow level used to maintain compliance and adjust as required;
(4) Initiate appropriate repair, replacement, or other corrective
action when detected; and,
(5) Maintain a record (i.e., checklist), signed by a responsible
plant official, showing the date of each inspection, any problems
detected, a description of the repair, replacement, or other action
taken, and the date of repair or replacement.
In addition to correcting defects, the owner or operator is
required to ensure that the equipment is being operated at an
appropriate level of reliability, i.e., without the need for continual
or unusually frequent repairs or alterations that require down time.
Frequent excursions of control device operating parameters would
indicate that some aspect of the maintenance program or procedures is
flawed.
2. Periodic Reports
The proposed NESHAP requires the owner or operator to develop and
implement a written plan containing specific procedures for operating
and maintaining the source during periods of startup, shutdown, and
malfunctions and a program of corrective action for malfunctioning
process and control systems. Each plan must contain corrective action
procedures to be followed in the event any periods of excess emissions
occur, including procedures to determine the cause of the problem, the
time the exceedance began and ended, and for recording the actions
taken to correct the cause of the exceedance or deviation. Examples of
corrective action procedures that might be included in the plan for
incinerators include: (1) Inspection of burner assemblies and pilot
sensing devices for proper operation and cleaning; (2) adjusting
primary and secondary
[[Page 48898]]
chamber combustion air; (3) inspecting dampers, fans, blowers, and
motors for proper operation; and (4)shutdown procedures.
Streamlined recordkeeping and reporting requirements also are
included in the proposed rule. If actions taken during a startup,
shutdown, or malfunction are consistent with the plan, no reporting
would be required but a record of the event must be kept. If the
actions during such an event are not consistent with the plan, the
report of this occurrence must be made in the next semi-annual startup,
shutdown, and malfunction report (which may be included in the semi-
annual excess emissions report).
The owner or operator must submit a semi-annual report within 60
calendar days after the end of each 6-month period if any period of
excess emissions occurs during the reporting period. Reports required
by other regulations may be used in place or as part of the excess
emissions report if the report(s) contain the required information. A
report would not be required if no exceedances or excursions occurred
during the reporting period. The report also would include any request
for changing selection of the CCU emission standard (e.g., the PM or Ni
limit) or the applicability of emission standards and requirements for
CCU or SRU under the NSPS in 40 CFR part 60, subpart J or subpart UUU.
Permitting regulations in 40 CFR parts 70 and 71 require the owner
or operator to make annual certifications of compliance. To aid the
permitting process, the proposed NESHAP establishes conditions that
must be met for the compliance certification.
3. Recordkeeping
Records required under the proposed rule are streamlined to include
the minimal amount of information needed by the EPA to confirm
compliance. These requirements are described in Sec. 63.1567(e)(4) of
this proposed rule. The major requirements include:
All documentation supporting notification of compliance
status;
Startup, shutdown, and malfunction plan with supporting
documentation;
Monitoring records required by Sec. 63.10(c) of the NESHAP
general provisions;
Each period when a monitoring system or device was
inoperative or malfunctioning;
All maintenance, corrective action, and quality assurance/
quality control actions and documentation;
Any changes to a regulated process;
Hourly or monthly inspections of bypass line valves and
bypasses;
Hourly inspections of flare pilot flame; and
Daily average coke burn-off rate for fluidized-bed CCU
catalyst regeneration vent with supporting documentation.
All records must be retained for at least 5 years following the
date of each occurrence, measurement, maintenance, corrective action,
report, or record. The records for the most recent 2 years must be
retained on site; records for the remaining 3 years may be retained off
site but still must be readily available for review. The files may be
retained on microfilm, on microfiche, on a computer, or on computer or
magnetic disks.
IV. Selection of Proposed Standards
A. Selection of Source Category
Section 112(c) of the Act directs the EPA to list each category of
major and areas sources as appropriate emitting one or more of the HAP
listed in section 112(b) of the Act. ``Petroleum Refineries--Catalytic
Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur
Plant Units'' is one of the 174 categories of sources included on the
initial list of source categories (57 FR 31576, July 16, 1992).
According to the EPA's schedule for rule development for these
source categories (58 FR 83841, December 3, 1993), MACT standards for
these petroleum refinery process unit vents must be promulgated no
later than November 15, 1997. If standards are not promulgated by May
15, 1999 (18 months following the promulgation deadline), section
112(j) of the Act requires States or local agencies with approved
permit programs to issue new or revised permits containing either an
emission limitation that is equivalent to the limitation that would
apply if the MACT standard had been promulgated in a timely manner or
an alternate emission limitation for HAP control.
Section 112(c)(3) of the Act directs the Agency to list each
category of area sources that the Agency finds presents a threat of
adverse effects to human health or the environment warranting
regulation. Based on information and data collected during development
of the proposed standard, the EPA estimates that all process units
within this source category are located at major sources of HAP
emission (60 FR 43245, August 18, 1995).
B. Selection of Emission Sources and Pollutants
The petroleum refinery source category, defined in the EPA report,
``Documentation for Developing the Initial Source Category List,''
(Docket Item II-A-1) specifies these three petroleum refinery process
units as a source category for regulation. Because little or no HAP
emission data for this source category were available at the beginning
of this study, the EPA collected information and data through review of
existing literature. Section 114 questionnaires were sent to nine
corporations (representing 27 refineries) and information collection
requests (ICRs) were sent to the remainder of existing U.S. refineries
to obtain information and data on refineries during development of the
initial MACT rule for petroleum refineries (60 FR 43244, August 18,
1995). Site surveys were conducted by the EPA at 20 petroleum
refineries as part of the refinery process vent rule development. Also,
as part of the information and data collection process, a series of
meetings were held with State representatives and industry trade
associations (i.e., the American Petroleum Institute (API) and the
National Petroleum Refiners Association (NPRA)) to first inform the
industry of the EPA's intentions to develop a MACT for this source
category and also to solicit their input. As a result, the trade
associations conducted surveys of their member companies to collect
additional information and data relative to the three process unit
operations which would be regulated by today's proposed rule. Based on
this information and data, and for the reasons described below, the EPA
is regulating these three vents as emission sources under the proposed
rule.
C. Selection of Proposed Standards for Existing and New Sources
1. Background
After the EPA has identified the specific source category or
subcategories of major sources for regulation under section 112, MACT
standards must be established for each category or subcategory. Section
112 of the Act sets a minimum level or floor for the standards. For new
sources, standards for a source category or subcategory cannot be less
stringent than the emission control that is achieved in practice by the
best-controlled similar source. (See CAA section 112(d)(3).) The
standards for existing sources can be less stringent than the standards
for new sources, but they cannot be less stringent than the average
emission limitation achieved by the best-performing 12 percent of
existing sources for categories or subcategories with 30 or more total
sources, or the
[[Page 48899]]
best performing 5 sources for categories or subcategories with fewer
than 30 sources. These minimum requirements for the MACT emission
limitation(s) for new and existing sources are termed the ``MACT
floor.''
After the floor has been determined for a new or existing source in
a source category or subcategory, the Administrator must set MACT
standards that are technically achievable and no less stringent than
the floor. Such standards must be met by all sources within the
category or subcategory. In establishing the standards, the EPA may
distinguish among classes, types, and sizes of sources within a
category or subcategory. (See CAA section 112(d)(1).)
The next step in establishing MACT standards is traditionally the
investigation of regulatory alternatives. With MACT standards, only
alternatives at least as stringent as the floor may be selected.
Information about the industry is analyzed to develop model plants for
projecting national impacts, including HAP emission reduction levels
and cost, energy, and secondary impacts. Regulatory alternatives, which
may be different levels of emissions control equal to or more stringent
than the floor levels, are then evaluated to select the regulatory
alternative that best reflects the appropriate MACT level. The selected
alternative may be more stringent than the MACT floor, but the control
level selected must be technically achievable. The regulatory
alternatives and emission limits selected for new and existing sources
may be different because of different MACT floors.
When the EPA considers an alternative which is beyond-the-floor,
the EPA examines the achievable emission reductions of HAP (and
possibly other pollutants that are co-controlled), cost and economic
impacts, energy impacts, and other non-air environmental impacts. The
objective is to achieve the maximum degree of emissions reduction
without unreasonable economic or other impacts. (See CAA section
112(d)(2).)
Under the Act, subcategorization within a source category may be
considered when there is enough evidence to demonstrate clearly that
there are significant differences among the subcategories. The criteria
to consider include process operations (including differences between
batch and continuous operations), emission characteristics, control
device applicability, safety, and opportunities for pollution
prevention.
The EPA examined the three process unit operations, the operating
characteristics of these units, and other relevant factors to determine
if separate classes of units, operations, or other criteria have an
affect on air emissions from any of the three process unit operations
in this source category. For SRU, no basis was established to
subcategorize or develop separate standards within these unit
operations. For CCU, the EPA requests additional information and data
needed to address the potential need for subcategorization due to
process variations (e.g., the differences between fluidized-bed and
non-fluidized bed CCU). However, for CRU, an analysis of the
information and data in the EPA refinery database indicated significant
differences in both the operating processes and emission controls
associated with semi-regenerative CRU during the catalyst regeneration
coke burn-off step. Therefore, the EPA established a subcategory for
semi-regenerative CRU based on the operating differences and control
device performance during the coke burn-off step; a separate
performance standard was established for this subcategory. Cyclic and
continuous CRU were grouped together and have a different performance
standard for the coke burn-off step. Subcategorization of semi-
regenerative CRU is further discussed in sections III.B and IV.C.2.b of
this document.
2. MACT Floor Technology and Emission Limits
In establishing the MACT floor for existing sources, sections
112(d)(3) (A) and (B) of the Act directs the EPA to set standards that
are no less stringent than the ``average'' emission limitation achieved
by the best performing 12 percent (for which there are emissions data)
where there are more than 30 sources in the category or subcategory or
the best performing five sources (for which there are emissions data)
where there are fewer than 30 sources. Among the possible meanings for
the word ``average'' as the term is used in the Act, the EPA considered
two of the most common.
First, ``average'' could be interpreted as the arithmetic mean. The
arithmetic mean of a set of measurements is the sum of the measurements
divided by the number of measurements in the set. The EPA has
determined that the arithmetic mean of the emission limitations
achieved by the best performing 12 percent of existing sources (or best
five sources where there are fewer than 30 sources) in some cases would
yield an emission limitation that fails to correspond to the emission
limitation achieved by any particular technology. In such cases, the
EPA would not select this approach. The word ``average'' could also be
interpreted as the median emission limitation value. The median is the
value in a set of measurements below and above which there are an equal
number of values (when the measurements are arranged in order of
magnitude). This approach identifies the emission limitation achieved
by those sources within the top 12 percent (or top five where there are
fewer than 30 sources), arranges those emissions limitations in order
of magnitude, and the control level achieved by the median source is
selected. Either of these two approaches could be used in developing
standards for different source categories.
A ``technology'' approach also was used in developing these
proposed standards. For each source type, the control technologies were
ranked in the database by performance and the median technology
represented by the best-controlled sources was selected as the MACT
floor. Sources having control technology representative of the MACT
floor were then evaluated and analyzed in order to determine an
appropriate emission limitation to characterize performance of the MACT
floor technology.
As previously noted, data related to operating procedures and
emissions for the three process unit operations were obtained through a
combination of literature sources, site visits, ICR, discussions with
industry and State Agency representatives, and information surveys
conducted by industry trade associations. These data were then compiled
into a comprehensive database that was used for the floor analysis.
a. MACT floor for catalytic cracking units. Catalytic cracking
(fluid and other) units emit a variety of HAP during catalyst
regeneration; these HAP can be broadly categorized into two groups:
metallic HAP (e.g., antimony, beryllium, mercury, and nickel) and
organic HAP (e.g., benzene, formaldehyde, hexane, and xylene). While
not exclusively so, the metallic HAP emitted from CCU catalyst
regeneration vents are primarily emitted as PM. Mercury is the one
metallic HAP that is expected to be emitted in both solid and gaseous
forms. The organic HAP emitted from CCU catalyst regeneration vents are
in the vapor phase. These two HAP emission forms require significantly
different control technologies.
The EPA database for CCU contains a considerable amount of
information on control device types as well as process information, but
very limited information on vent stream composition
[[Page 48900]]
or HAP concentration for either the metallic HAP or the organic HAP.
The amount of constituent data currently available is not adequate to
establish a MACT floor for each individual HAP; the limited data on
individual HAP cannot be considered representative of the entire
industry in all but a few cases. Therefore, the floor for CCU (both
fluidized bed and non-fluidized bed) catalyst regeneration vent HAP
emissions is being established for the broad classes of HAP that are
grouped as either metallic HAP or organic HAP.
The EPA is aware that there are significant process differences
between the fluidized-bed and non-fluidized bed CCU. These process
differences include such things as catalyst size and composition, as
well as reactor operation (e.g., plug downflow versus fluidized riser
processes). At this time, the EPA does not have adequate data to
characterize the HAP emissions from the non-fluidized CCU, but
preliminary data currently available indicate, based on the EPA's
current understanding, that these units are likely operating at
emission levels that meet the MACT floor criteria. However, the EPA is
gathering additional information and data on these processes and, based
on the new information, will reexamine the possible need to set a
separate standard for these few non-fluidized CCU.
(1) Organic HAP MACT floor.
(a) Existing catalytic cracking units. Available emission data have
been reviewed to identify the best performing 12 percent of existing
sources. The available emissions data that relate to organic HAP
control performance are presented in the database in terms of VOC, THC,
and CO with only minimal data on individual HAP constituents. The
performance level formats available in the database that relate to
organic HAP are an emission rate normalized to coke burn, an emission
rate expressed in terms of an exit concentration, and a performance
level expressed as a percent reduction achieved. The amount of
individual constituent data currently available is not adequate to
establish a MACT floor for each individual organic HAP; the limited
data on individual organic HAP cannot be considered representative of
the entire industry. Therefore, emissions data on VOC, THC, and CO were
reviewed since these data are indicative of emissions of individual
organic HAP.
The CCU catalyst regeneration step that generates the affected gas
stream involves an initial combustion operation, and the catalyst
regeneration step can be conducted either as a partial combustion
operation or a complete combustion operation. A complete burn/
combustion CCU has a catalyst regeneration coke burn stage designed and
operated with a residence time, temperature, and excess oxygen level to
achieve complete oxidation of the coke or carbon to CO2; a
partial burn/combustion CCU has a catalyst regeneration coke burn stage
designed and operated with less than stoichiometric oxygen, which
results in incomplete combustion of the carbon and is characterized by
high levels of CO.
The emission data for CCU catalyst regeneration vents indicate
that: (1) Complete burn/combustion CCU and (2) partial burn/combustion
CCU that are followed by a CO boiler or other combustion device achieve
similar organic emission rates. Both of these configurations achieve
complete combustion of the CCU catalyst regeneration vent gases and
demonstrate similar emissions rates and as a result, both are
considered types of ``complete combustion.'' These complete combustion
units have significantly less organic HAP emissions than partial burn/
combustion CCU that are not followed by an additional combustion
device.
The petroleum refinery NSPS (40 CFR part 60, subpart J) is a
regulation that requires catalyst regeneration vent gases from new or
reconstructed fluidized-bed CCU to have complete combustion by limiting
the CO concentration to less than or equal to 500 ppmv (dry).
Information gathered by the EPA indicates that more than 12 percent of
the existing CCU are currently subject to the petroleum refinery NSPS.
The NSPS thus represents the average emission limitation achieved, in
terms of a regulatory requirement, by the best performing 12 percent of
existing sources. Therefore, a complete burn/combustion CCU or partial
burn/combustion CCU followed by a CO boiler or other combustion device
that reduces the CO concentration in the catalyst regeneration vent gas
to 500 ppmv or less is deemed to be meeting the MACT floor for existing
CCU.
(b) New catalytic cracking units. Based on the information and data
available, the EPA concluded that the MACT floor determination for
existing CCU sources of organic HAP (i.e., complete combustion of the
vent gases) also represents the HAP emission control that is achieved
in practice by the best-controlled similar source in the source
category. Therefore, the MACT floor for new sources is the same as that
for existing sources for organic HAP. This fact also leads to the
conclusion that there is no technology that has been demonstrated in
this industry to provide a level of control more stringent than the
MACT floor for organic HAP.
(2) Metallic (or inorganic) HAP MACT floor.
(a) Existing catalytic cracking units. Along with low emissions,
the best-performing existing sources are expected to have the best-
performing control technologies; for metallic HAP that would involve
either a modern ESP or a venturi scrubber. Available data shows these
two devices, used by approximately 45 percent of the industry, provide
similar control of PM and metallic HAP. However, some refineries with
CCU controlled only by tertiary cyclones, control devices typically
considered less effective, have told the EPA that their emissions are
equivalent to those achieved by the more efficient control devices.
This is in large part a function of the site-specific characteristics
of the unit (e.g., a low Ni feed) Therefore, rather than set an
equipment standard based on a control device, the EPA prefers to
establish a performance standard associated with the best performing
control technology.
The petroleum refinery NSPS (40 CFR part 60, subpart J) is a
performance standard that requires new or reconstructed fluidized-bed
CCU to reduce PM emissions from the catalyst regeneration vent to 1 kg/
1,000 kg (1 lb/1,000 lb) of coke burn-off. As previously noted, the
information gathered by the EPA and contained in the petroleum refinery
database indicates that more that 12 percent of the existing CCU are
currently subject to the petroleum refinery NSPS. The EPA reviewed this
emission standard to determine its appropriateness as a performance
standard to characterize the best-performing control technology for CCU
metallic HAP emissions. The EPA concluded that for a variety of
reasons, PM is considered a reasonable surrogate for total metallic HAP
(excluding mercury):
(1) The metallic HAP emitted from CCU catalyst regenerator vents
are primarily emitted as PM;
(2) In the EPA report, ``Study of Hazardous Air Pollutant Emissions
from Electric Utility Steam Generating Units--Final Report'' (Docket
Item II-A-6), it was determined that for those combustion operation
vent gases ``the HAP metals that exist primarily in particulate form
are readily controlled by PM control devices''; and
(3) There is a considerable amount of emission data available for
PM emitted from CCU catalyst regeneration vents.
The performance level formats available in the data base for PM are
an emission rate normalized to coke burn, an emission rate expressed in
terms of
[[Page 48901]]
an exit concentration, and a performance level expressed as a percent
reduction achieved. The EPA refinery database shows that CCU ESP
achieve a PM emission rate that ranges from 0.0002 to 3.6 lb/1,000 lb
coke; the 26 values reported have a median of 0.81 and a mean of 0.86
lb/1,000 lb. The NSPS value is 1.0. Nineteen of the 26 CCU have a
catalyst regeneration PM emission rate of less than 1 lb/1,000 lb of
coke burn-off. The five CCU that use a venturi scrubber and that have
PM data show a range of emissions from 0.36 to 0.86 lb/1,000 lb of coke
burn-off, which is within the range of performance shown by the ESP.
Thus, the NSPS PM emission limit for the catalyst regeneration vent of
1 lb/1,000 lb of coke burn-off appears to a reasonable characterization
of PM control device performance on a ``not-to-be-exceeded'' basis,
based on the available data. As a result of this analysis, a PM
emission limit of 1 lb/1,000 lb of coke burn-off is selected to
characterize the MACT floor for catalyst regeneration vents on existing
units.
In addition to characterizing the MACT floor performance in terms
of a PM emission limit, it is possible to determine an alternative MACT
floor technology emission limit in terms of the entire metal HAP
population or an individual metal HAP (i.e., Ni) within that
population. The reason for determining a MACT floor emission limit as
an alternative to the PM level but formatted in a terms of total metal
HAP or an individual metal HAP is to provide for increased operational
flexibility and to allow opportunities for pollution prevention when
complying with a MACT standard for this source category.
In developing a MACT floor emission level formatted in terms of the
population of metal HAP emitted by CCU, the approach used involved
analysis of the available metal HAP data. This is most readily done
using Ni as a surrogate for total metal HAP. Nickel emissions data were
used for this comparative analysis because of the relative abundance of
measured Ni emissions data and the paucity of emissions data available
for other metal HAP. Nickel emissions data (formatted in terms of mass
per unit time) for catalyst regeneration vents are available for 23
CCUs. The available measured Ni emissions data from CCU catalyst
regeneration vents in the EPA refinery database were examined and
compared to determine the representativeness of these data.
In examining the database, EPA determined that the Ni emission data
currently available for CCU catalyst regeneration vents is
representative of the best-performing units in the industry. The EPA
based this conclusion on the following considerations. A primary factor
that influences the Ni emissions from the CCU catalyst regeneration
vent is the Ni content in the CCU feed. The Ni emission rates in the
refinery database are for the most part from units with low Ni feed.
There are 72 CCU that reported the Ni content in their CCU feed. Of
these 72 CCU, 43 (or 60 percent) of the units had Ni feed
concentrations of 1 ppmw or lower. However, 12 of 14 CCU (or 86 percent
of the CCU) that reported both Ni emissions data and Ni feed content,
had Ni feed concentrations of 1 ppmw or lower. In addition, the
database reflects Ni emission rates of refineries that hydrotreat the
CCU feed. Hydrotreating the CCU feed tends to lower the CCU feed Ni
content. There are 98 CCU that reported the use or non-use of
hydrotreating. Of these 98 CCU, 56 (or 57 percent) of the units
hydrotreat. However, 13 of 17 CCU (or 76 percent of the CCU) that
reported both Ni emissions data and hydrotreating information,
hydrotreat their CCU feed.
A second factor that influences the Ni emissions from the CCU
catalyst regeneration vent is the level of PM control on the unit. The
EPA refinery database is comprised of units that are subject to
stringent regulatory requirements that result in control of Ni
emissions. For example, from the data collected by API and provided to
the EPA as a part of the database, it appears that at least 36 percent
of the CCU that reported Ni emissions data are subject to the NSPS,
whereas the EPA estimates that there are approximately 17 percent of
the CCU in the entire industry subject to the NSPS. In addition,
approximately 41 percent of the Ni emissions data are from CCU at
California refineries, where the State regulations on PM control are
basically the same as the NSPS PM emission control requirements,
whereas California refineries operate only about 10 percent of the
total number of CCU in the U.S. Also, approximately 81 percent of the
CCU in the database that reported Ni emissions data operate either an
ESP or venturi wet scrubber on the CCU catalyst regeneration vent,
whereas only 63 percent of the CCU nationwide operate either an ESP or
venturi wet scrubber on the CCU catalyst regeneration vent.
For the reasons discussed above, the EPA considers the available Ni
emissions data to be representative of the best-performing CCU sources,
rather than the industry as a whole. Examination of the emission data
shows an emission rate for the top 12 percent to be 0.055 tpy. In
conjunction with this, the available Ni source test data were analyzed
to determine the variability of individual source test runs for a given
CCU source test. Based on analysis of the relative standard deviation
of the individual CCU source test data, the standard deviation for a
unit with emissions of 0.055 tpy is 0.042. Using the upper 95th
percentile of a normal distribution (i.e., a z-statistic equal to
1.645), the Ni emission limit determined to reflect the best performing
12 percent of existing sources is a Ni emission limit on a not-to-be-
exceeded basis of 0.125 tpy (250 lb/yr) or 0.029 lb/hr (i.e., the mean
+ 1.645 standard deviations). Therefore, a metal HAP MACT floor
emission limit of 13,000 mg/hr or 0.029 lb/hr of Ni also has been
determined to characterize the performance of the MACT floor control
technology for existing CCU catalyst regeneration vents.
(b) New catalytic cracking units. Based on the information and data
available, the EPA concluded that the MACT floor determination for
existing CCU sources of metallic HAP (i.e., use of a PM control device
such as an ESP or venturi scrubber) also represents the HAP emission
control that is achieved in practice by the best-controlled similar
source in the source category. Therefore, the MACT floor for new
sources is the same as that for existing sources for metallic HAP. This
fact also leads to the conclusion that there is no technology that has
been demonstrated in this industry to provide a level of control more
stringent than the MACT floor for metallic HAP.
(3) Mercury MACT floor. Mercury (Hg) is not well controlled by PM
air pollution control devices (ESPs as well as PM scrubbers). This
situation would be expected because Hg is likely emitted in both a
solid and gaseous or vapor-phase (elemental) form; the fact that
``conventional (PM) controls are generally inconsistent in their
effectiveness'' with regard to Hg removal is documented in the EPA
report, ``Study of Hazardous Air Pollutant Emissions from Electric
Utility Steam Generating Units--Final Report''. (See Docket Item II-A-
6.) Combustion devices for control of organic vapor would also provide
no control for Hg. There are a number of emerging technologies (such as
activated carbon injection) but none have been show to be applicable to
CCU catalyst regeneration vents. Therefore, the MACT floor for Hg is
determined to be no control for both new and existing units.
[[Page 48902]]
b. MACT floor for catalytic reforming units. Developing a MACT
floor for CRU catalyst regeneration vents is complicated by the fact
that there are three types of CRU (continuous, cyclic; and semi-
regenerative), and there are different steps (times and locations)
during which vent emissions may occur during CRU catalyst regeneration:
(1) Initial depressurization/purge; (2) coke burn-off; (3) catalyst
rejuvenation; and (4) final purge. The depressurization/purge vent gas
contains primarily hydrocarbons from the CRU feedstock that remain on
the reforming catalyst feed (e.g., benzene, toluene, hexane, and
ethylbenzene). The predominant HAP emitted during coke burn-off are HCl
and Cl2. Chlorinated organic compounds used for catalyst
rejuvenation (e.g., trichloromethane and perchloromethane) as well as
residual HCl on the reforming catalyst may be emitted during catalyst
rejuvenation and final purge.
The EPA database for CRU contains a considerable amount of
information on control device types as well as process information for
177 CRU, but very limited information on vent stream composition or HAP
concentration. There are some data available to characterize HCl
emissions during coke burn-off; however, the limited data on HCl
emissions cannot be considered representative of the entire industry as
most HCl emissions data are from continuous or cyclic units. The
available data on HAP emissions from CRU catalyst regeneration vents is
inadequate to characterize the emission reductions achieved by the top-
performing 12 percent of the units during the depressurization/purge,
catalyst rejuvenation, and final purge cycles. Therefore, the MACT
floor for CRU catalyst regeneration vent HAP emissions is established
for each potential CRU vent based on current industry practices rather
than HAP specific emissions data.
(1) MACT floor determination for existing CRU catalyst regeneration
vents.
(a) MACT floor for CRU depressurization/purge vent. Given the
limitations of the available data, the MACT floor determination for the
CRU depressurization/purge vent is based on current practices in use
and control equipment in place at CRU. Flares, process heaters or other
combustion devices are used for 21 of the CRU catalyst regeneration
vents. Based on current information in the EPA database, it is
difficult to discern whether these control devices are used
specifically for the depressurization/purge vent. However, all of the
20 refineries visited by either the EPA or CARB during information
collection site visits to support the development of this rule vented
the depressurization/purge gases to either the refinery fuel gas system
or to a flare. Therefore, based on operational practices for over 12
percent of the CRU (and 100 percent of the units for which the EPA has
firsthand information), the MACT floor for emissions vented during the
depressurization/purge cycle is venting to a combustion device.
In the first petroleum refinery MACT rule (60 FR 43244, August 18,
1995), the EPA assigned a performance value for combustion units
serving miscellaneous process vents. In that floor analysis, it was
assumed that the various combustors were all well designed and operated
and would achieve 98 percent destruction of total VOC (and HAP). (See
Docket A-93-48, Docket Item IV-B-12.) This same performance level is
therefore assumed for combustion devices that are used on CRU catalyst
regeneration vents. Therefore, the MACT floor for emissions vented
during the depressurization/ purge cycle is venting to a combustion
device that achieves a 98 percent destruction efficiency or reduces the
total organic HAP or the TOC concentration to below 20 ppmv.
The 20 ppmv concentration format is included as an alternative in
the proposed standard because the rule could apply to dilute process
vent streams and the proposed standard for combustion devices is
formatted in terms of a weight-percent reduction. The EPA believes the
proposed standard for combustion devices needs to include the volume
concentration alternative to account for the technological limitations
of enclosed combustion devices treating dilute streams. (See 48 FR
48933, October 21, 1983.) Below a critical concentration level, the
maximum achievable efficiency for enclosed combustion devices decreases
as inlet concentration decreases. Consequently, for streams with low
organic vapor concentrations, the 98-percent mass reduction may not be
technologically achievable in all cases. Available data show that 20
ppmv is the lowest outlet concentration of total organic compounds
achievable with control device inlet streams below approximately 2,000
ppmv total organics. Therefore, the concentration limit of 20 ppmv has
been added as an alternative standard for incinerators, process
heaters, and boilers to allow for the drop in achievable destruction
efficiency with decreasing inlet organics concentration.
(b) MACT floor for CRU catalyst regeneration coke burn-off vent.
The EPA examined the available HCl emissions data for catalyst
regeneration vents on 22 CRU that reported HCl emissions during the
coke burn-off cycle, along with the type of CRU and the control device
used; 17 of these units operate with no emission controls (or unknown
emission controls). With the limited data available, it is not possible
to characterize these emissions data as either representative of the
industry as a whole or representative of the top-performing CRU. For
example, only 3 (or 14 percent) of the 22 units that reported HCl
emissions are semi-regenerative CRU, while semi-regenerative CRU
represent 61 percent of all CRU. It appears that due to the limited
frequency and duration of the emissions from catalyst regeneration
vents on semi-regenerative units, few emission source tests have been
performed at semi-regenerative CRU. Therefore, a MACT floor
determination cannot be based on the available HCl emissions data for
the coke burn-off cycle. However, a determination based on control
technology can be made.
From a review of the process equipment data, two classes of
scrubbers were designated to characterize the general classes or groups
of scrubbers being used to control emissions from CRU catalyst
regeneration vents during the coke burn-off step: single theoretical
stage scrubbers and multiple theoretical stage scrubbers. The single
theoretical stage scrubber classification was used to reflect the
following CRU scrubbing systems, most of which are considered internal
to the process: Caustic injection, spray circulating solution,
hydrocyclone, and once through spray scrubbers. Multiple theoretical
stage scrubbers which are, for the most part, external to the process
include: Packed tower, packed column, plate and spray, venturi, and
otherwise unspecified absorbers or scrubbers. Although there are
inadequate CRU emissions data to differentiate the removal efficiency
between single stage scrubbers and multiple stage scrubbers,
theoretical considerations suggest that multiple stage scrubbers will
have a higher HCl removal efficiency than a single stage scrubber.
A summary of the numbers of each type of control device (single or
multiple stage) for catalyst regeneration vents on each type of CRU
(continuous, cyclic, or semi-regenerative) shows that for continuous
CRU, 28 percent use multiple stage scrubbers while only 6 percent use
single stage; for cyclic CRU, 36 percent use multiple stage while only
[[Page 48903]]
11 percent use single scrubbers; and for semi-regenerative CRU, only 3
percent use multiple while 72 percent use a single stage scrubber.
Based on these data, the MACT floor for catalyst regeneration vents on
continuous and cyclic CRU is the use of a multiple stage scrubber
during the coke burn-off process. The MACT floor for catalyst
regeneration vents on semi-regenerative CRU is the use of a single
stage scrubber during the coke burn-off process. Subcategorizing semi-
regenerative CRU is justified based on the operational differences of
semi-regenerative units (i.e., primarily annual hours the system is
regenerating). Based on the similarities of the types of controls used
for catalyst regeneration vents on cyclic and continuous CRU and the
annual operating hours in which regeneration occurs, it appear
reasonable that cyclic and continuous CRU be grouped together.
The performance of CRU scrubbers can be characterized based on
industry surveys and source test data on HCl scrubbers used in another
industry--the steel pickling industry. Data from that industry contains
a range of flow rates and HCl concentrations which span the flow rates
and HCl concentrations expected for the CRU catalyst regeneration coke
burn-off vent. The characteristics of the single and multiple stage
scrubbers that constitute existing source and new source levels of
control were determined in terms of both HCl reduction efficiency and
maximum outlet concentration by evaluating the results of emissions
tests conducted on units currently employed in the steel pickling
industry. The data from these tests are presented and discussed in
detail in the preamble to the proposed rule (62 FR 49052, September 18,
1997) and in the background information document for the proposed
standard. (See Docket Items II-A-4.) While wet scrubber control devices
are normally designed for a target emission reduction efficiency, the
EPA is aware that high reduction efficiencies for process gases that
contain low concentrations of HCl or HCl in aerosol or droplet form may
not always be achievable. The EPA therefore has characterized scrubber
performance in terms of a maximum exhaust gas concentration as well as
reduction efficiency in recognition of the limitations of the
technology.
Based on the median performance of the multiple stage type
scrubbers tested, the EPA selected an HCl scrubber removal efficiency
of 97 percent or an outlet concentration of 10 ppmv or less to
characterize the performance of a multiple stage HCl scrubber. That is,
the EPA considers that a well-operated and well-maintained scrubber,
i.e., those considered to be the MACT floor for catalyst regeneration
vents on continuous and cyclic CRU, can achieve a 97 percent removal
efficiency or reduce the outlet concentration to 10 ppmv or less.
Therefore, the MACT floor for the coke burn-off vent for continuous and
cyclic CRU is to operate a scrubber that achieves 97 percent or greater
removal of HCl or achieves an outlet concentration of 10 ppmv or less.
As previously noted, there are few data to support the selection of
emission limits or HCl control efficiency values for the MACT floor for
catalyst regeneration vents on semi-regenerative CRU (i.e., single
stage scrubbers). Examination of performance data of scrubbers used
outside the source category shows that the lowest control efficiency of
HCl scrubbers tested by the EPA in the steel pickling industry was
approximately about 92 percent. (See Docket Item II-A-4.) Based on
these available data and theoretical engineering design considerations
of the various HCl single stage scrubber types, a single stage HCl
scrubber can reasonably be expected to achieve a 92 percent HCl removal
efficiency on an industry-wide basis for semi-regenerative CRU catalyst
regeneration coke burn-off vents. This is equivalent to an outlet
concentration limit of 30 ppmv, based on the 92 percent HCl removal
efficiency. Therefore, the MACT floor for the catalyst regeneration
coke burn-off vent for semi-regenerative CRU is to operate a scrubber
that achieves 92 percent or greater removal of HCl or achieves an
outlet concentration of 30 ppmv or less.
(c) MACT floor for CRU catalyst regeneration rejuvenation vent. As
noted previously, there are very few data available to characterize
emissions from the CRU catalyst regeneration rejuvenation/final purge
vent. Additionally, from information gathered during site visits to
petroleum refineries, there appear to be differences in how/when the
rejuvenation process occurs. Some units dose the chlorination agent
into the CRU reactors during the coke burn-off cycle (``coincidental
rejuvenation''). In this instance, the rejuvenation and coke burn-off
vent coincide, and the MACT floor for coke burn-off vents previously
described would apply. Other units circulate the chloriding agent
through the reactor(s) upon completion of the coke burn-off cycle
(``sequential rejuvenation''). In this instance, the system is a closed
recirculation loop with no atmospheric venting. If venting does occur
during sequential rejuvenation, then the MACT floor is venting to an
HCl scrubber with the same efficiencies specified for the coke burn-off
vent. The EPA requests specific comments regarding the prevalence,
operations, and controls typically associated with this vent.
(d) MACT floor for CRU catalyst regeneration final purge vent. Upon
completion of the rejuvenation/coke burn-off cycles, the CRU system is
purged to remove oxygen from the system and to create a reducing
atmosphere prior to bringing the unit or reactor back on-line for
reforming (or returning the catalyst to the reforming reactor in the
case of continuous units). This final purge vent may be scrubbed,
released to the atmosphere, vented to the refineries fuel gas system,
or vented to a flare or other combustion control device. Flares,
process heaters or other combustion devices are used for catalyst
regeneration vents on 21 of the CRU. Based on current information in
the EPA database, it is not possible to discern whether these control
devices are used specifically for the final purge vent. However, from
information collected during the site visits to 20 refineries, it is
known that approximately one-half of these refineries vented the final
purge vent to a combustion control device. Using the control efficiency
determined by the EPA for combustion devices (refer to the discussion
for the depressurization/purge vent), the MACT floor for the final
purge vent is to vent this stream to a combustion control device that
achieves 98 percent destruction efficiency or reduces total organic HAP
or TOC concentration to below 20 ppmv.
(2) MACT floor determination for new CRU catalyst regeneration
vents. Except for the catalyst regeneration coke burn-off vent for
semi-regenerative CRU, the MACT floor for catalyst regeneration vents
on new CRU is the same as for catalyst regeneration vents on existing
CRU for all CRU catalyst regeneration vents. This is because the
catalyst regeneration vent on the best-controlled or top-performing CRU
applies the same work practices or control devices as the top 12
percent of CRU catalyst regeneration vents employ (i.e., the MACT floor
for existing sources). There are two semi-regenerative CRU that employ
multiple stage type scrubbers to control catalyst regeneration coke
burn vents. These represent the best-controlled sources for this vent.
Therefore, the MACT floor for catalyst regeneration vents on new semi-
regenerative CRU (as well as continuous and cyclic CRU) is the use of a
multiple stage scrubber (i.e., a scrubber that achieves 97 percent or
greater removal
[[Page 48904]]
of HCl or achieves an outlet concentration of 10 ppmv or less as
specified in the MACT floor for catalyst regeneration vents on existing
continuous and cyclic CRU).
c. MACT floor for sulfur recovery plants. Developing a MACT floor
for SRU is complicated by the fact that there are different types of
processes (although Claus units predominate the industry) and numerous
types of emission control techniques (including different types of tail
gas treatment units, thermal incineration, or a combination of a tail
gas treatment unit and incineration). The EPA database for SRU contains
information regarding the number and types of SRUs as well as the
control device configuration for 144 units at 82 refineries. The
database also has information regarding process capacities or sulfur
production rates and information regarding applicability of the NSPS
for approximately 60 percent of these SRU.
The predominant HAP emitted from SRU are COS and CS2.
There are very few data available regarding HAP emissions from SRUs.
Consequently, the available data on HAP emissions from the SRU vents
are inadequate to characterize the emission reductions achieved by the
top performing 12 percent of the units. Additionally, there are
inadequate data to determine and differentiate the emission reduction
efficiencies achieved by the various types of emission control process
configurations. Therefore, the floor for SRU vent HAP emissions is
being established based on current industry regulations rather than
emissions data or process equipment.
(1) MACT floor determination for existing SRU/sulfur plant vents.
There are 144 units in the current data base for SRU; information
regarding the applicability of the refinery NSPS was specifically
requested for 91 of these units. Of the 91 SRU for which NSPS
applicability information was requested, 38 units were subject to the
NSPS, 47 units were not, and 6 units did not respond. Due to the lack
of emissions data, a MACT floor determination cannot be made based on
the emission reduction achieved by the top-performing 12 percent of the
industry. Alternatively, the MACT floor determination can be made based
on either the emission control equipment in-place for the SRU vent or
the existing regulations limiting HAP emissions from these vents.
Although the database contains information regarding the types of
equipment in-place at the SRU, due to the variety of different tail gas
treatment units and process configurations and the lack of emissions
data, it is not possible to make a ranking of the tail gas treatment
unit types and the process configurations that yield the greatest
reduction in HAP emissions. On the other hand, the petroleum refinery
NSPS (Sec. 60.104) specifies emission limits (some of which are
primarily HAP emission limits) for Claus sulfur recovery plants. As
Claus units represent 96 percent of the SRU in the EPA database (138 of
the 144 SRU are Claus units), and approximately 40 percent of the SRU
(for which NSPS applicability information is available) are subject to
the NSPS, it is concluded that over 12 percent of all SRU are subject
to the refinery NSPS. Therefore, the MACT floor for the control of HAP
emission from the SRU vents is based on the emission reductions
achieved by facilities subject to the NSPS for petroleum refineries.
The EPA is aware that there are significant process differences
between the Claus sulfur units and the non-Claus units. At this time,
the EPA does not have adequate data to characterize the HAP emissions
from these non-Claus sulfur units but available data indicate that
these units are likely operating at emission levels that meet the MACT
floor criteria. The EPA is requesting comment on these processes and,
based on the new information, will reexamine the possible need to set a
separate standard for these few non-Claus SRU.
The refinery NSPS outlines two options for the control of emissions
from SRU: (1) For oxidative control systems or reductive control
systems followed by incineration, the emission limit is 250 ppmv of
SO2 at zero percent excess air; and (2) for reductive
control systems not followed by incineration, the emission limit is 300
ppmv of reduced sulfur compounds and 10 ppmv of H2S, each
calculated as ppmv SO2 at zero percent excess air. The
second option translates well into a HAP emission limit because TRS
compounds are defined as H2S, COS, and CS2. The
fact that H2S is a component of the TRS and cannot exceed 10
ppmv suggests that the COS and CS2 (i.e., the HAP) are at
least 290 ppmv and at most 300 ppmv. The first option is not easily
translated into a HAP emission limit (i.e., there is no direct way to
determine the contribution of H2S, a non-HAP, to the total
limit), but it suggests that use of an oxidation control system or
incineration effectively controls emissions of TRS. Therefore, it is
concluded that the MACT floor for the SRU vent is a combined HAP or TRS
emission limit of 300 ppmv measured as ppmv SO2 at zero
percent excess air. It is important to note that the EPA is still in
the process of collecting and validating additional data for both the
Claus and non-Claus SRU and will re-evaluate and possibly revise the
floor determination based on the new data.
(2) MACT floor determination for new SRU/sulfur plant vents. Based
on the limited information and data available, EPA concluded that the
MACT floor determination for existing SRU sources of HAP (i.e., the 300
ppmv HAP emission limit derived from the refinery NSPS) also represents
the HAP emission control that is achieved by the best-controlled
similar source in the source category. Therefore, the MACT floor for
new SRUs is the same as the MACT floor for existing SRUs. No options
have been identified for this source that would provide a level of
control more stringent that the MACT floor.
D. Selection of Monitoring Requirements
The EPA evaluated the hierarchy of monitoring options available for
this source category. The EPA identified and analyzed several different
monitoring options taking into consideration the various unit
operations, the HAP emitted, and the proposed control equipment for
each of the respective vents. This hierarchy includes measurement of
HAP (e.g., HCl) by a CEMS, installation of measurement devices for
continuous monitoring of process and/or control device operating
parameters, and periodic or one-time performance tests. Each option was
evaluated relative to its technical feasibility, cost, ease of
implementation, and relevance to the process or control device.
A CEMS provides a direct measurement of emissions. For this source
category, CEMS are commercially available for a number of the
pollutants of concern, e.g., HCl, CO, metallic HAP/PM, and TRS
compounds. However, it is important to note that for some of these
systems the technical feasibility of monitoring the unit operations
that comprise the source category has not yet been demonstrated. There
also are other concerns. For example, the EPA believes that HCl
monitors can be used for CRU catalyst regeneration vent applications
and TRS monitors can be used for SRU vent COS and CS2
emissions; but the nationwide capital cost of this option (CEMS for all
reformer unit HCl scrubbers and sulfur plants) is estimated at $18.5
million for the HCl monitors and $6.1 million for the TRS monitors,
with annual costs of $14.2 million and $4.3 million, respectively, for
operation and maintenance, quality assurance and quality control
performance evaluation,
[[Page 48905]]
and reporting/recordkeeping requirements. Because of the high cost of
using CEMS compared with the costs of the emission control devices and
the cost of monitoring control device and process parameters, the EPA
is not requiring the blanket use of CEMS to demonstrate compliance for
this source category. However, CEMS for CO are included as an
alternative under the proposed rule for affected CCU. These devices are
commonly used to monitor CCU process operations and are also required
under the refinery NSPS. The cost associated with continuous CO
monitors is considered reasonable. Although CEMS are not required, the
proposed rule does provide the owner or operator a general option of
installing and operating a CEMS and complying with most of the
requirements in the general provisions that apply to a CEMS.
Another option for compliance assurance is monitoring process and/
or control device operating parameters plus conducting routine (e.g.,
annual) emission tests. With the exception of complete burn/combustion
CCUs, process parameters were not selected as indicators for HAP
emissions for the unit operations in this source category because an
adequate correlation does not exist between production or process
parameters and emission rates. Control device operating parameters were
selected instead because the EPA's experience has shown that
measurements outside a specified range of values, for example
established during an initial performance test, could be used to
indicate the control device was not operating properly. The estimated
nationwide capital costs of this option are $7.4 million; annual costs
are $10.6 million for all three vents in the source category. Note that
the periodic emission tests required for these vents (for example
testing using Method 26A in appendix A to 40 CFR part 60 for HCl
emissions from CRU) would not require a capital investment. The
estimated cost assumes the use of a test contractor and includes time
for participation by plant personnel.
The EPA believes that reasonable assurance of compliance is
achieved through the combination of continuous emission monitoring,
process and control device operating parameter monitoring, and the
periodic emission testing required in the proposed rule. The proposed
rule requires that each owner or operator of a CCU, CRU, or SRU using a
combustion device to limit HAP emissions must monitor temperature as a
control device operating parameter. The owner or operator of a CCU
using an ESP for control of metallic HAP emissions must monitor the
voltage and secondary current of the control device or the total power
input. If a wet scrubber is used to comply with the requirements for
metallic HAP or HCl control, the owner or operator must monitor the
pressure drop across the scrubber, the gas and water flow rate to the
scrubber, and determine the liquid-to-gas ratio. If new information is
obtained after proposal indicating the use or planned use of dry
scrubbers, appropriate monitoring provisions will be included in the
final rule. For CCU subject to the rule, such as complete burn/
combustion CCU, that do not use add-on control devices, the owner or
operator must continuously monitor the concentration of CO emissions
from the unit or measure the regeneration process operating temperature
and the oxygen content of the vent gas. An owner or operator may
request approval to monitor parameters other than those listed above by
submitting a request to the applicable permitting authority. The EPA is
soliciting comment on appropriate monitoring parameters for CRU that do
not use an external scrubber to control HCl emissions.
V. Summary of Impacts of Proposed Standards
A. Air Quality Impacts
The impacts presented in this section include the process vent
emissions from all three of the unit operations listed in the source
category. The EPA estimates nationwide HAP emissions from process vents
on these unit operations at approximately 7,270 Mg/yr (8,000 tpy) at
the current level of control. The proposed standards will reduce
nationwide HAP emissions by about 5,960 Mg/yr (6,560 tpy), an 82
percent reduction. Emissions of VOC, CO, and PM (mainly from CCUs), and
emissions of H2S (mainly from SRUs) would be reduced by
about 65 percent from the current level of about 185,900 Mg/yr (204,500
tpy). Little or no adverse secondary air impacts, water or solid waste
impacts are anticipated from the implementation of these standards.
B. Cost Impacts
Nationwide capital and annualized costs of control equipment are
estimated at $179 million and $35.5 million/yr, respectively. The
implementation of this regulation is expected to result in an overall
annual national cost of $53.5 million. This includes a cost of $43.7
million for operation/maintenance of control devices and a monitoring,
recordkeeping, and reporting cost of $9.8 million.
C. Economic Impacts
The economic impact analysis for the selected regulatory
alternatives shows that the estimated price increase of refined
petroleum products is 0.24 percent for the 127 refineries expected to
incur compliance costs as a result of the rule. The estimated decrease
in output is 0.17 percent of domestic refinery products. The decline in
domestic production is due to higher imports and reduced quantity
demanded due to higher prices. However, the value of domestic shipments
is expected to increase by 0.07 percent because the estimated price
increase more than offsets the lower production volume. Annual net
exports (exports minus imports) are predicted to decrease by 0.76
percent. Employment in the industry is likely to decrease by 0.19
percent (136 jobs). No plant closures or significant regional impacts
are expected. For more information on the economic impact analysis
methodology and results, consult the ``Economic Impact Analysis for the
Petroleum Refinery NESHAP.'' (See Docket Item II-A-5.)
D. Non-air Health and Environmental Impacts
The proposed NESHAP are based on air pollution control systems
which are currently in use in the industry. The proposed NESHAP would
reduce emissions of HAP and ambient pollutants, and consequently,
occupational exposure levels for plant employees may be lowered.
E. Energy Impacts
The national electric usage required to comply with the rule is
expected to increase by about 114,000 MW/hr, primarily for CCU PM and
CO controls and SRU incinerators. National natural gas usage, primarily
for SRU incinerators, is expected to increase by about 1.5 billion
cubic feet. Water usage for CRU scrubbers, is expected to increase by
about 6.2 million gallons nationwide.
VI. Request for Comments
The EPA seeks full public participation in arriving at its final
decisions and encourages comments on all aspects of this proposal from
all interested parties. Full supporting data and detailed analysis
should be submitted with comments to allow the EPA to make use of the
comments. All comments should be directed to the Air and Radiation
Docket and Information Center, Docket No. A-97-36 (see ADDRESSES).
Comments on this document must be submitted on or before the date
specified in DATES.
[[Page 48906]]
Commentors wishing to submit proprietary information for
consideration should clearly distinguish such information from other
comments and clearly label it ``CBI.'' Submissions containing such
proprietary information should be sent directly to the following
address, and not to the public docket, to ensure that proprietary
information is not inadvertently placed in the docket: Attention: Mr.
Bob Lucas, c/o Ms. Melva Toomer, U.S. EPA Confidential Business
Information Manager, OAQPS (MD-13), Research Triangle Park, NC 27711.
Information covered by such a claim of confidentiality will be
disclosed by the EPA only to the extent allowed and by the procedures
set forth in 40 CFR part 2. If no claim of confidentiality accompanies
the submission when it is received by the EPA, it may be made available
to the public without further notice to the commentor.
The EPA specifically requests comments on seven topics where
additional information is desired prior to promulgation. As discussed
below, topics entail: Emission characteristics and operation of non-
fluidized CCU and non-Claus SRU; HAP emissions from SRU sulfur pits;
excess emissions from CCU resulting from maintenance/repair of the
control device; potential subcategorization of CCU; selection of a
cutoff value for CRU depressuring/purging operations; appropriate
monitoring parameters for CRU with internal scrubbing systems; and
consideration of an alternative format for the proposed Ni emission
limit.
A. Non-fluidized Catalytic Cracking Units and Non-Claus Sulfur Recovery
Units
As discussed in section II.D.1 of this document, non-fluidized CCU
(accounting for only 2.9 percent of the total catalytic cracking
process charge rate), were operated by 7 refineries in 1997. Although
the exact number of non-Claus SRU is not known, Claus SRU represent 96
percent of the SRU in the EPA database. While the EPA observed a small
number of non-fluid CCU and non-Claus SRU in operation, little or no
test data are available to determine differences in emissions and
operation as compared to fluidized-bed CCU or Claus SRU. The EPA
requests information and data on control status, operating processes,
and emission measurements using EPA methodology. Based on this
information and data, the EPA will determine whether a separate
emission limit is warranted for non-fluidized bed CCU or non-Claus SRU
and analyze the associated impacts of control. Based on these analyses,
the EPA may retain the proposed standard with no distinction between
the processes, include a separate standard in the final rule, or
determine that no standard is warranted for one or both of these
subcategories.
B. Potential Emission Sources
Process observations during plant site visits indicate that SRU
sulfur recovery pits and certain types of tail gas treatment units may
be potential HAP emission sources. Emissions from sulfur pits occur at
each SRU reactor when elemental sulfur is condensed and removed from
the SRU gas and the liquid sulfur is collected and stored in bins.
Several refineries are known to purge the sulfur pits to prevent the
buildup of explosive levels of gases. Emissions are controlled by
combining the purged gases from the pits with the SRU or tail gas
treatment unit off-gas and venting to an incinerator. Certain types of
tail gas treatment units, such as ``Stretford'' units, employ a series
of open vessels as part of the solution circulation loop and a direct
air contact cooling tower to cool the solution. Limited data indicate
that HAP emissions are released from the solution tank and direct air
contact cooling towers. The EPA specifically requests information and
data on these process operations, emissions, and control practices.
Based on analyses of the information and data received, the EPA may
consider regulation of these sources when developing the final rule.
C. Catalytic Cracking Unit Control Device Maintenance
The Agency requests comment on the need for allowing operation of
CCU when control devices such as boilers or venturi scrubbers are out
of service for maintenance overhauls. Information is specifically
requested on the number of facilities which have this need, current
maintenance practices for boilers and scrubbers, their frequency and
length, safety considerations, and manufacturer's recommendations.
Should monitoring by other methods be required during such a period?
Should time limits be applied? Would more frequent, periodic
preventative maintenance, such as that envisioned by the maintenance
plan included in the proposed standard preclude or lessen the need for
2 year or 10-year overhauls? How should the EPA provide operational
flexibility while ensuring that emissions are minimized and good air
pollution control practices are followed? The EPA will use comments,
information, and suggestions received to address this issue in the
final rule.
D. Subcategorization of Catalytic Cracking Units
As discussed in section IV.C.1 of this document, the EPA recognizes
the potential need for CCU subcategorization due to the wide variety of
process variations. For this reason, additional information and data on
CCU processes, emissions, and distinguishing characteristics that meet
subcategorization criteria are requested. Based on the information and
data received, the EPA will consider whether separate standards for
different CCU processes are warranted.
E. Catalytic Reforming Unit Depressuring/Purging Cutoff Value
Under the proposed standards, CRU control requirements do not apply
to depressuring or purging operations at a differential pressure
between the gas transfer system to the control device of less than 1
psig. The EPA evaluated several different approaches to deriving the
cutoff value, but selected an approach based on differential pressure
due to the concern that an absolute value would not be appropriate for
all plants due to process variations. Because differential pressure may
be more difficult to monitor, EPA also included a cutoff of 1 psig,
consistent with State rules, for the reactor vent pressure. Comments,
information, and data on outlet unit pressures for depressuring/purging
and the feasibility of establishing a differential value are requested.
The EPA will evaluate the data and information received and address
this issue in the final rule.
F. Monitoring of Catalytic Reforming Units with Internal Scrubbing
Systems
As previously noted the MACT floor for CRU catalyst regeneration
vents is established based on current industry practices in use and
control equipment in place at CRU. Two classes of scrubbers were
designated to characterize the groups of scrubbers used to control
emissions from CRU catalyst regeneration vents during the coke burn-off
step, single stage and multiple stage scrubbers. Each of these scrubber
classes can be further categorized as either a scrubber that is
internal to the process (e.g., caustic injection) or external to the
process (e.g., a packed tower). Because the internal type scrubbers are
contained within the process units itself, there is no convenient
scrubber operating parameter that can be monitored as is the case with
an external scrubber. The EPA is therefore requesting comment on
identification of appropriate monitoring parameters for the internal
type CRU
[[Page 48907]]
scrubbing systems. For example, would use of a simplified monitoring
system (such as colorimetric tubes) be adequate to demonstrate that the
acid gases in the unit are sufficiently controlled. Or, would
monitoring of the recycle stream within the unit rather than the
exhaust gas be adequate to characterize the scrubber performance.
G. Alternative CCU Standard
The EPA is considering the addition of a third alternative standard
to reduce metal HAP emissions from the CCU regeneration vent. The
current proposal requires compliance with either a PM limit of 1.0 lb/
1,000 lbs of coke burn-off, or a Ni limit of 0.029 lb/hr. Industry
representatives have requested inclusion of a metal HAP (or Ni)
emission limit formatted in terms of lb of metal HAP (or Ni)/1,000 lbs
of coke burn-off. The EPA requests comments on the need and benefits of
a third alternative. The EPA will consider all regulatory formats.
Commenters suggesting a particular emission limit should explain how
the limit correlates to the MACT floor.
From the beginning of this project, the EPA has recognized that the
format for the CCU standard was a significant issue. During initial
discussions with stakeholders, including early site visits to
refineries, EPA asked for thoughts on possible formats. Also, from the
beginning, regulatory alternatives have included the use of PM as a
surrogate for total metal HAP.
Using the PM format established by NSPS Subpart J, the MACT floor
determination set the standard at 1.0 lb/1,000 lbs of coke burn-off as
characterizing performance of the MACT floor technology. An early draft
of the regulation included a second alternative that provided a Ni
emission limit of 0.00047 lb Ni/1,000 lbs of coke burn-off. This second
alternative was derived from the first alternative by using the average
Ni concentration in the CCU catalyst regeneration fines to convert the
PM mass to an equivalent Ni mass. These fines consist of the PM that is
collected by the air pollution control device following the CCU
regeneration vent.
Upon review of this draft regulation, representatives of small
refineries commented that the format of both regulatory alternatives
then under consideration was independent of unit size or throughput.
Therefore, both alternatives, expressed in terms of coke burn-off,
penalized small CCU. Representatives cited examples of small units with
very low annual Ni emissions (in terms of tons per year) which would
not be in compliance with either regulatory alternative. In response,
the EPA revised the draft regulation by changing the format of the Ni
standard to a lb/hr format, while keeping the PM limit expressed in
terms of coke burn-off. The second alternative in the current proposal
provides a Ni limit of 0.029 lb/hr. Industry representatives supported
the new format, while also requesting that the previous format be
included as a third alternative.
Industry representatives have recommended that the third
alternative be set at 0.007 lb of Ni/1,000 lbs of coke burn-off to
account for the highest Ni concentrations found in CCU feed streams and
to account for the variability in the crude oil. The API/NPRA
recommended Ni standard is, in their view, technically equivalent to
the floor. Documents relating to the API/NPRA recommendation are in the
docket for this rulemaking.
Since the time of EPA's original suggestion for this format, EPA
has continued to collect data on the Ni concentration in CCU fines. The
current data base shows that an alternative based on average Ni fines
concentration could be set at 0.0013 lb of Ni/1,000 lbs of coke burn-
off. The EPA is continuing to evaluate the API/NPRA recommendation.
The EPA is requesting comments on providing a third regulatory
alternative. The alternative could be based on metal HAP (or Ni)
emissions in terms of lb/1,000 lbs of coke burn-off, or it could have a
different format. The alternative must be technically equivalent to the
MACT floor. Specifically, the Agency requests comments regarding: (1)
The need for and usefulness of a third alternative for specific
refineries, (2) the use of Ni concentrations as a surrogate for total
metal HAP, and (3) the use of the arithmetic mean, median, geometric
mean, 90th percentile value, 95th percentile value, or highest value as
the representative concentration used in the factor for conversion of
PM to Ni.
H. Overlap With New Source Performance Standard
As discussed in section III.A of this document, the EPA recognizes
that some fluidized-bed CCU and SRU are subject to NSPS and related
Title I requirements. To minimize the burden of duplicative rule
requirements, the proposed MACT standard includes provisions allowing
compliance demonstrations for the NSPS requirements (which govern
criteria pollutants) to serve as compliance demonstrations for the HAP
emission control requirements. The intent of these provisions is to
minimize duplication without reducing or changing the Title I
requirements. The EPA requests comments on the adequacy of this
approach, together with suggestions for other approaches that would
achieve this goal.
I. Status of an Exceedance or Excursion
Section 63.1565(p) of the proposed standard provides that more that
one exceedance or excursion by the same control device during a semi-
annual reporting period is a violation. This provision is included in
the proposed standard to maintain consistency with the earlier MACT
standard for petroleum refineries in 40 CFR part 63, subpart CC. The
EPA is further considering this proposed provision and its impacts.
However, EPA currently does not have adequate information on the long-
term performance of the MACT emission control technologies for the
affected processes and their ability to continuously achieve
compliance. For this reason, EPA requests additional information and
data relative to control device performance. Based on the information
received, EPA will decide whether to permit facilities to have an
exceedance or excursion once per semi-annual reporting period.
VII. Administrative Requirements
A. Docket
The docket is an organized and complete file of all the information
considered by the EPA in the development of this rulemaking. The docket
is a dynamic file, because material is added throughout the rulemaking
development. The docketing system is intended to allow members of the
public and industries involved to readily identify and locate documents
so that they can effectively participate in the rulemaking process.
Along with the proposed and promulgated standards and their preambles,
the contents of the docket will serve as the record in the case of
judicial review. (See CAA section 307(d)(7)(A).)
B. Public Hearing
A public hearing will be held, if requested, to discuss the
proposed standards in accordance with section 307(d)(5) of the Act. If
a public hearing is requested and held, the EPA will ask clarifying
questions during the oral presentation but will not respond to the
presentations or comments. Written statements and supporting
information will be considered with equivalent weight as any oral
statement and supporting information subsequently presented at a public
hearing. Persons wishing to attend or to make oral presentations or to
inquire as to whether
[[Page 48908]]
a hearing is to be held should contact the EPA (see FOR FURTHER
INFORMATION CONTACT). To provide an opportunity for all who may wish to
speak, oral presentations will be limited to 15 minutes each.
Any member of the public may file a written statement on or before
November 10, 1998. Written statements should be addressed to the Air
and Radiation Docket and Information Center (see ADDRESSES), and refer
to Docket A-97-36. A verbatim transcript of the hearing and written
statements will be placed in the docket and be available for public
inspection and copying, or be mailed upon request, at the Air and
Radiation Docket and Information Center.
C. Executive Order 12866
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the EPA
must determine whether the regulatory action is ``significant'' and
therefore subject to review by the Office of Management and Budget
(OMB), and the requirements of the Executive Order. The Executive Order
defines ``significant regulatory action'' as one that is likely to
result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, it has been
determined that this regulatory action is not ``significant'' because
none of the listed criteria apply to this action. However, OMB has
classified this rule as potentially significant and has requested
review. Consequently, this action will be submitted to OMB for review
under Executive Order 12866.
D. Enhancing the Intergovernmental Partnership Under Executive Order
12875
In compliance with Executive Orders 12875, the EPA involved State
regulatory experts in the development of this proposed rule. No tribal
governments are believed to be affected by this proposed rule. State
and local governments are not directly impacted by the rule, i.e., they
are not required to purchase control systems to meet the requirements
of the rule. However, they will be required to implement the rule;
e.g., incorporate the rule into permits and enforce the rule. They will
collect permit fees that will be used to offset the resources burden of
implementing the rule. Comments have been solicited from States and
have been carefully considered in the rule development process. In
addition, all States and tribal governments are encouraged to comment
on this proposed rule during the public comment period, and the EPA
intends to fully consider these comments in the development of the
final rule.
E. Unfunded Mandates Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.
L. 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, the
EPA generally must prepare a written statement, including a cost-
benefit analysis, for proposed and final rules with ``Federal
mandates'' that may result in expenditures to State, local, and tribal
governments, in the aggregate, or to the private sector, of $100
million or more in any one year. Before promulgating an EPA rule for
which a written statement is needed, section 205 of the UMRA generally
requires the EPA to identify and consider a reasonable number of
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives
of the rule. The provisions of section 205 do not apply when they are
inconsistent with applicable law. Moreover, section 205 allows the EPA
to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator
publishes with the final rule an explanation why that alternative was
not adopted. Before the EPA establishes any regulatory requirements
that may significantly or uniquely affect small governments, including
tribal governments, it must have developed pursuant to section 203 of
the UMRA a small government agency plan. The plan must provide for
notifying potentially affected small governments, enabling officials of
affected small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
The EPA has determined that this rule does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, or tribal governments, in the aggregate, or the private
sector in any one year. Thus, today's rule is not subject to the
requirements of sections 202 and 205 of UMRA. In addition, the EPA has
determined that this rule contains no regulatory requirements that
might significantly or uniquely affect small governments because it
contains no requirements that apply to such governments or impose
obligations upon them. Therefore, today's rule is not subject to the
requirements of section 203 of the UMRA.
F. Executive Order 13045
Executive Order 13045, ``Protection of Children from Environmental
Health and Safety Risks'' (62 FR 19885, April 23, 1997) applies to any
rule that EPA determines: (1) ``Economically significant'' as defined
under E.O. 12866, and (2) the environmental health or safety risk
addressed by the rule has a disproportionate effect on children. If the
regulatory action meets both criteria, the Agency must evaluate the
environmental health or safety effects of the planned rule on children,
and explain why the planned regulation is preferrable to other
potentially effective and reasonable feasible alternatives considered
by the Agency. This proposed rule is not subject to E.O. 13045 because
it does not involve decisions on environmental health risks or safety
risks that may disportionately affect children.
G. Regulatory Flexibility
The Regulatory Flexibility Act (RFA) generally requires an agency
to conduct a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements unless the agency certifies
that the rule will not have a significant economic impact on a
substantial number of small entities. Small entities include small
business, small not-for-profit enterprises, and small governmental
jurisdictions.
In developing these proposed standards, the EPA has worked with
industry trade groups to identify the special concerns of small
refineries. Site visits also were conducted to five small refineries
where the EPA met with facility representatives and listened to their
concerns. In response, the EPA has exercised the maximum degree of
flexibility in minimizing impacts on small business through the
alternative Ni standard and subcategorization of the
[[Page 48909]]
source category for CRU vents. Also, these proposed standards, which
are based on MACT-floor level control technology, reflect the minimum
level of control allowed under the Act.
The EPA economic analysis identified 16 small businesses that
operate a total of 19 refineries. Two of these refineries operated by
two different firms are expected to incur compliance costs and the
remaining 17 refineries are not expected to incur any compliance costs
as a result of the proposed NESHAP. Annual compliance costs for the two
affected refineries would be less than one percent of estimated sales
revenues. Additional information is included in chapter 6 of the
economic impact analysis for the proposed standards. (See Docket Item
II-A-5.)
Based on this information, the EPA has concluded that this proposed
rule would not have a significant economic impact on a substantial
number of small entities. Therefore, I certify that this action will
not have a significant economic impact on a substantial number of small
entities.
H. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to OMB under the requirements of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information
Collection Request (ICR) document has been prepared by EPA (ICR No.
1844.01), and a copy may be obtained from Sandy Farmer, OPPE Regulatory
Division, U.S. Environmental Protection Agency (2137), 401 M Street SW,
Washington, DC 20460, or by calling (202) 260-2740.
The proposed information requirements include mandatory
notifications, records, and reports required by the NESHAP general
provisions (40 CFR part 63, subpart A). These information requirements
are needed to confirm the compliance status of major sources, to
identify any nonmajor sources not subject to the standards and any new
or reconstructed sources subject to the standards, to confirm that
emission control devices are being properly operated and maintained,
and to ensure that the standards are being achieved. Based on the
recorded and reported information, the EPA can decide which plants,
records, or processes should be inspected. These recordkeeping and
reporting requirements are specifically authorized under section 114 of
the Act (42 U.S.C. 7414). All information submitted to the EPA for
which a claim of confidentiality is made will be safeguarded according
to Agency policies in 40 CFR part 2, subpart B. (See 41 FR 36902,
September 1, 1976; 43 FR 39999, September 28, 1978; 43 FR 42251,
September 28, 1978; and 44 FR 17674, March 23, 1979.)
The annual public reporting and recordkeeping burden for this
collection of information (averaged over the first 3 years after the
effective date of the rule) is estimated to total 18,581 labor hours
per year at a total annual cost of $597,007/yr. This estimate includes
certain notifications which are streamlined to incorporate
notifications of applicability for existing sources, results of initial
performance tests (including repeat performance tests where needed),
and monitoring information. The estimates also include one-time
preparation of a startup, shutdown, and malfunction plan; semi-annual
reports of any period of excess emissions; and recordkeeping. Reporting
requirements have been streamlined to allow the owner or operator to
report only those events where the procedures in the startup, shutdown,
and malfunction plan were not followed in the semi-annual excess
emissions report. Total capital costs associated with monitoring
requirements over the 3-year period of the ICR is estimated at
$463,000/yr; this estimate includes the capital and startup costs
associated with installation of monitoring equipment. The total
operation and maintenance cost is estimated at $4,418,500/yr.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purpose of collecting, validating, and
verifying information; process and maintain information and disclose
and provide information; adjust the existing ways to comply with any
previously applicable instructions and requirements; train personnel to
respond to a collection of information; search existing data sources;
complete and review the collection of information; and transmit or
otherwise disclose the information.
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 OMB control numbers for the
EPA's regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15.
Comments are requested on the Agency's need for this information,
the accuracy of the burden estimates, and any suggested methods for
minimizing respondent burden, including through the use of automated
collection techniques. Send comments on the ICR to the Director, OPPE
Regulatory Information Division; U.S. Environmental Protection Agency
(2136), 401 M Street SW., Washington, DC 20460; and to the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, marked ``Attention: Desk
Officer for EPA.'' Include the ICR number in any correspondence.
Because OMB is required to make a decision concerning the ICR between
30 and 60 days after September 11, 1998, a comment to OMB is best
assured of having its full effect if OMB receives it by October 13,
1998. The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
I. Pollution Prevention Act
During the development of the proposed NESHAP, the EPA explored
opportunities to eliminate or reduce emissions by substitution of non-
HAP for HAP-generating materials. One potential approach is the use of
a non-chlorinated catalyst material for CRUs. However, available
information are insufficient to evaluate the feasibility or research
status of this potential approach. The EPA will continue to work with
the industry to collect information on the potential use of different
CRU catalyst materials and encourage new research on this approach. The
pollution prevention concept is incorporated in the proposed
alternative Ni emission standard which encourages the use of feed with
lower metallic HAP content. Also, facilities which hydrotreat to remove
metals from the feed can meet the proposed standard with a less
effective PM control device.
J. National Technology Transfer and Advancement Act
Under section 12(d) of the National Technology Transfer and
Advancement Act (NTTA), Pub. L. 104-113 (March 7, 1996), the Agency is
required to use voluntary consensus standards in its regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices, etc.) which are adopted by
voluntary consensus standard bodies. Where available and potentially
applicable voluntary consensus standards are not used by the Agency,
the Act requires the Agency to provide Congress, through OMB, an
explanation
[[Page 48910]]
of the reasons for not using such standards. This section summarizes
the Agency's response to the requirements of the NTTA for the
analytical test methods proposed as part of today's standards.
The proposed standard includes test methods and procedures for the
purpose of emission tests needed to demonstrate initial compliance.
Although a vast array of test methods and procedures applicable to
petroleum content and material specifications are published by the
American Society of Testing and Materials, these methods are not
applicable to determining the volume and type of air emissions from the
affected sources. To facilitate the emission testing process and
associated costs, the proposed standards uses surrogates for the HAPs
included in emissions from the affected sources. This approach allows
use of the conventional test methods required by the existing NSPS
which have been in use by EPA, States, and three-quarters of the
industry for over 20 years. Alternative test methods also may be used
subject to EPA approval. In addition, the EPA worked with industry
experts to revise the NSPS procedure for determining the coke burn-off
rate. The amended procedure utilizes common industry practice for
determining the rate, corrects a technical equation error in the older
NSPS, and reduces costs by allowing the use of existing data rather
than daily stack tests to obtain needed data.
K. Clean Air Act
In accordance with section 117 of the Act, publication of this
proposal was preceded by consultation with appropriate advisory
committees, independent experts, and Federal departments and agencies.
This regulation will be reviewed 8 years from the date of promulgation.
This review will include an assessment of such factors as evaluation of
the residual health risks, any overlap with other programs, the
existence of alternative methods, enforceability, improvements in
emission control technology and health data, and the recordkeeping and
reporting requirements.
L. Executive Order 13084
Under Executive Order 13084, EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by the tribal governments. If the mandate is unfunded,
EPA must provide to the Office of Management and Budget, in a
separately identified section of the preamble to the rule, a
description of the extent of EPA's prior consultation with
representatives of affected tribal governments, a summary of the nature
of their concerns, and a statement supporting the need to issue the
regulation. In addition, Executive Order 13084 requires EPA to develop
an effective process permitting elected and other representatives of
Indian tribal governments to provide meaningful and timely input in the
development of regulatory policies on matters that significantly or
uniquely affect their communities. Today's rule does not significantly
or uniquely affect the communities of Indian tribal governments.
Accordingly, the requirements of section 3(b) of Executive Order 13084
do not apply to this rule.
List of Subjects in 40 CFR Part 63
Environmental protection, Air pollution control, Hazardous
substances, Petroleum refineries, Reporting and recordkeeping
requirements.
Dated: August 25, 1998.
Carol M. Browner,
Administrator.
For the reasons set out in the preamble, part 63 of title 40,
chapter I, of the Code of Federal Regulations is proposed to be amended
as follows:
PART 63--[AMENDED]
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
* * * * *
2. Part 63 is amended by adding subpart UUU to read as follows:
Subpart UUU--National Emission Standards for Hazardous Air Pollutants
From Petroleum Refineries--Catalytic Cracking (Fluid and Other) Units,
Catalytic Reforming Units, and Sulfur Plants
Sec.
63.1560 Applicability and designation of affected sources.
63.1561 Definitions.
63.1562 Emission standards for existing sources.
63.1563 Emission standards for new or reconstructed sources.
63.1564 Compliance dates and performance tests.
63.1565 Monitoring requirements.
63.1566 Test methods and procedures.
63.1567 Notification, reporting and recordkeeping requirements.
63.1568 Applicability of general provisions.
63.1569 Delegation of authority.
63.1570-63.1579 [Reserved]
Appendix A to Subpart UUU to Part 63--Applicability of General
Provisions (40 CFR Part 63, Subpart A) to Subpart UUU
Subpart UUU--National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries--Catalytic Cracking (Fluid and
Other) Units, Catalytic Reforming Units, and Sulfur Plants
Sec. 63.1560 Applicability and designation of affected sources.
(a) The provisions of this subpart apply to the owner or operator
of each new and existing catalytic cracking unit, catalytic reforming
unit, and sulfur recovery plant unit associated with a petroleum
refinery and located at a major source of hazardous air pollutants
(HAP) as defined in Sec. 63.2 of this part.
(b) Affected sources at a facility subject to this subpart are:
(1) The process vent or group of process vents on each fluidized
and other (i.e., non-fluidized) catalytic cracking unit, that is
associated with regeneration of the catalyst used in the unit (i.e.,
the catalyst regeneration flue gas vent);
(2) The process vent or group of process vents, on each catalytic
reforming unit (including but not limited to semi-regenerative, cyclic,
or continuous processes), that is associated with regeneration of the
catalyst used in the unit. This affected source includes vents that are
used during the unit depressurization, purging, coke burn, catalyst
rejuvenation, and reduction or activation purge; and
(3) The process vent or group of process vents, that vents from a
Claus or other sulfur recovery plant unit or the tail gas treatment
unit serving the sulfur recovery plant, that is associated with sulfur
recovery.
(c) This subpart does not apply to gaseous streams routed to a fuel
gas system.
(d) An owner or operator of a fluidized-bed catalytic cracking unit
catalyst regenerator subject to and in compliance with the standard for
particulate matter emissions in Sec. 60.102 of this chapter and all
associated requirements (including but not limited to testing,
monitoring, recordkeeping, and reporting provisions) is considered to
be in compliance with the standard in Sec. 63.1562(a)(1) of this
subpart and all associated requirements. An owner or operator of a
fluidized-bed catalytic cracking unit catalyst regenerator subject to
and in compliance with the standard for carbon monoxide in Sec. 60.103
of this chapter and all associated requirements (including but not
limited to testing, monitoring,
[[Page 48911]]
recordkeeping, and reporting provisions) is considered to be in
compliance with the standard in Sec. 63.1562(a)(2) of this subpart and
all associated requirements. An owner or operator of a sulfur recovery
unit subject to and in compliance with the standard for sulfur oxides
in Sec. 60.104 of this chapter and all associated requirements
(including but not limited to testing, monitoring, recordkeeping, and
reporting provisions) is considered to be in compliance with the
standard in Sec. 63.1562(c) of this subpart and all associated
requirements.
Sec. 63.1561 Definitions.
All terms used in this subpart shall have the meaning given them in
the Clean Air Act, in subpart A of this part, and in this section. 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.
Catalytic cracking unit means a refinery process unit in which
petroleum derivatives are charged; hydrocarbon molecules in the
presence of a catalyst are fractured into smaller molecules, or react
with a contact material to improve feedstock quality for additional
processing; and the catalyst or contact material is regenerated by
burning off coke and other deposits. The unit includes, but is not
limited to the riser, reactor, regenerator, air blowers, spent catalyst
or contact material stripper, catalyst or contact material recovery
equipment, and regenerator equipment for controlling air pollutant
emissions and for heat recovery.
Catalytic cracking unit regenerator means one or more regenerators
(multiple regenerators) which comprise that portion of the catalytic
cracking unit in which coke burn-off and catalyst or contact material
regeneration occurs, and includes the regenerator combustion air
blower(s).
Catalytic reforming unit means a refinery process unit that reforms
or changes the chemical structure of naphtha into higher octane
aromatics through the use of a metal catalyst and chemical reactions
that include dehydrogenation, isomerization, and hydrogenolysis. The
catalytic reforming unit includes the reactor, regenerator (if
separate), separators, catalyst isolation and transport vessels (e.g.,
lock and lift hoppers), recirculation equipment, scrubbers, and other
ancillary equipment.
Catalytic reforming unit regenerator means one or more regenerators
which comprise that portion of the catalytic reforming unit in which
the following regeneration steps typically are performed:
Depressurization, purge, coke burn-off, catalyst rejuvenation with a
chloride (or other halogenated) compound(s), and a final purge. The
catalytic reforming unit catalyst regeneration process can be conducted
either as a semi-regenerative, cyclic, or continuous regeneration
process.
Coke burn-off means the coke removed from the surface of the
catalytic cracking unit catalyst or the catalytic reforming unit
catalyst by combustion in the catalyst regenerator. The rate of coke
burn-off is calculated by the formula specified in Sec. 63.1566 (Test
methods and procedures) of this subpart.
Combustion device means an individual unit of equipment such as a
flare, incinerator, process heater, or boiler used for the destruction
of organic hazardous air pollutants or volatile organic compounds.
Combustion zone means the space in an enclosed combustion device
(e.g., vapor incinerator, boiler, furnace, or process heater) occupied
by the organic HAP and any supplemental fuel while burning. The
combustion zone includes any flame that is visible or luminous as well
as that space outside the flame envelope in which the organic HAP
continues to be oxidized to form the combustion products.
Contact material means any substance formulated to remove metals,
sulfur, nitrogen, or any other contaminants from petroleum derivatives.
Continuous regeneration reforming means a catalytic reforming
process characterized by continuous flow of catalyst material through a
reactor where it mixes with feedstock in a counter-current direction,
and a portion of the catalyst is continuously removed and sent to a
special regenerator where it is regenerated and continuously recycled
back to the reactor.
Control device means any equipment used for recovering, removing,
or oxidizing HAP in either gaseous or solid form. Such equipment
includes, but is not limited to, condensers, scrubbers, electrostatic
precipitators, incinerators, flares, boilers, and process heaters.
Cyclic regeneration reforming means a catalytic reforming process
characterized by continual batch regeneration of catalyst in situ in
any one of several reactors (e.g., four or five separate reactors) that
can be isolated from and returned to the reforming operation, while
maintaining continuous reforming process operations (i.e., feedstock
continues flowing through the remaining reactors without change in feed
rate or product octane).
Flame zone means the portion of a combustion chamber of a boiler or
process heater occupied by the flame envelope created by the primary
fuel.
Flow indicator means a device that indicates whether gas is
flowing, or whether the valve position would allow gas to flow, in a
line.
HCl means, for the purposes of this subpart, gaseous emissions of
hydrogen chloride that serve as a surrogate measure for total emissions
of hydrogen chloride and chlorine as measured by Method 26A in appendix
A to part 60 of this chapter or an approved alternative method.
Incinerator means an enclosed combustion device that is used for
destroying organic compounds, with or without heat recovery. Auxiliary
fuel may be used to heat waste gas to combustion temperatures.
Ni means, for the purposes of this subpart, particulate emissions
of nickel that serve as a surrogate measure for total emissions of
metal HAPs, including but not limited to: Antimony, arsenic, beryllium,
cadmium, chromium, cobalt, lead, manganese, nickel, and selenium as
measured by Method 29 in appendix A to part 60 of this chapter or by an
approved alternative method.
Petroleum refinery means an establishment/installation primarily
engaged in petroleum refining as defined in the Standard Industrial
Classification (SIC) code for petroleum refining (SIC 2911), and used
primarily for:
(1) Producing transportation fuels (such as gasoline, diesel fuels,
and jet fuels), heating fuels (such as kerosene, fuel gas distillate,
and fuel oils), or lubricants;
(2) Separating petroleum; or
(3) Separating, cracking, reacting, or reforming an intermediate
petroleum stream, or recovering a by-product(s) from the intermediate
petroleum stream (e.g., sulfur recovery).
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 HAPs contained in the
particulate matter, including but not limited to: Antimony, arsenic,
beryllium, cadmium, chromium, cobalt, lead, maganese, nickel, and
selenium as measured by Methods 5B or 5F in appendix A to part 60 of
this chapter or by an approved alternative method.
Process heater means an enclosed combustion device that primarily
transfers heat liberated by burning fuel directly to process streams or
to heat transfer liquids other than water.
[[Page 48912]]
Semi-regenerative reforming means a catalytic reforming process
characterized by shutdown of the entire reforming unit (e.g., which may
employ three to four separate reactors) at specified intervals or at
the owner's or operator's convenience for in situ catalyst
regeneration.
Sulfur recovery unit means 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. This definition does not include a unit
where the modified reaction is carried out in a water solution which
contains a metal ion capable of oxidizing the sulfide ion to sulfur,
e.g., the LO-CAT II process.
TRS means, for the purposes of this subpart, emissions of total
reduced sulfur compounds, expressed as an equivalent sulfur dioxide
concentration, that serve as a surrogate measure of the total emissions
of sulfide HAPs carbonyl sulfide and carbon disulfide as measured by
Method 15 in appendix A to part 60 of this chapter or by an approved
alternative method.
TOC means, for the purposes of this subpart, emissions of total
organic compounds excluding methane and ethane that serve as a
surrogate measure of the total emissions of organic HAP compounds,
including but not limited to acetaldehyde, benzene, hexane, phenol,
toluene, and xylenes and non-HAP volatile organic compounds as measured
by Method 18 or Method 25A in appendix A to part 60 of this chapter or
an approved alternative method.
Sec. 63.1562 Emission standards for existing sources.
(a) Catalytic cracking unit regeneration. The owner or operator of
a catalytic cracking unit shall comply with the standards in paragraphs
(a)(1)(i) or (a)(1)(ii) of this section and the standard in paragraph
(a)(2) of this section.
(1) The owner or operator shall identify the standard selected in
the notification of compliance status report as required by
Sec. 63.1567(a)(6) of this subpart. Following any 6-month reporting
period, the owner or operator may change the standard selected for
compliance by submitting a request to the applicable permitting
authority containing the information specified in Sec. 63.1567(b)(7) of
this subpart.
(i) Emissions of PM shall not exceed 1.0 kilogram (kg)/1,000 kg
[1.0 pound (lb)/1,000 lb] of coke burn-off in the catalyst regenerator;
or
(ii) Emissions of nickel (Ni) from the catalyst regenerator vent on
each catalytic cracking unit shall not exceed 13,000 milligrams/hour
(mg/hr) [0.029 pound per hour (lb/hr)].
(2) The concentration of carbon monoxide (CO) exiting the catalyst
regenerator vent or CO boiler (if a CO boiler is used as the combustion
device) shall not exceed 500 parts per million (ppm) by volume (dry
basis).
(b) Catalytic reforming unit regeneration. The owner or operator of
a catalytic reforming unit shall comply with paragraphs (b)(1) through
(b)(3) of this section.
(1) During depressurization and purging, comply with the
requirements in paragraphs (b)(1)(i) or (b)(1)(ii) of this section.
(i) The owner or operator shall vent TOC emissions from the
regenerator to a flare that meets the requirements for control devices
in Sec. 63.11(b) of this part; or
(ii) The owner or operator shall reduce uncontrolled emissions of
TOC using a control device, by 98 percent by weight or to a
concentration of 20 ppm by volume, on a dry basis, corrected to 3
percent oxygen, whichever is less stringent. If a boiler or process
heater is used to comply with the percent reduction requirement or
concentration limit, the vent stream shall be introduced into the flame
zone, or any other location that will achieve the required percent
reduction or concentration.
(iii) The control device requirements of paragraphs (b)(1)(i) and
(b)(1)(ii) of this section do not apply to depressuring and purging
operations at a differential pressure between the reactor vent and the
gas transfer system to the control device of less than 1 pound per
square inch gauge (psig) or if the reactor vent pressure is 1 psig or
less.
(2) During coke burn-off and catalyst regeneration, the owner or
operator of a semi-regenerative catalytic reforming unit shall reduce
uncontrolled emissions of HCl by 92 percent by weight using a control
device, or to a concentration of 30 ppm by volume, on a dry basis,
corrected to 3 percent oxygen; and
(3) During coke burn-off and catalyst regeneration, the owner or
operator of a cyclic or continuous catalytic reforming unit shall
reduce uncontrolled emissions of HCl by 97 percent by weight using a
control device, or to a concentration of 10 ppm by volume, on a dry
basis, corrected to 3 percent oxygen.
(c) Sulfur recovery units. The owner or operator of a sulfur
recovery unit shall not discharge or cause to be discharged into the
atmosphere any emissions of total reduced sulfur (TRS) compounds,
expressed as an equivalent sulfur dioxide (SO2)
concentration, in excess of 300 ppm by volume, on a dry basis, at zero
percent oxygen.
Sec. 63.1563 Emission standards for new or reconstructed sources.
(a) Catalytic cracking unit regeneration. The owner or operator of
a catalytic cracking unit shall comply with the standards for existing
affected sources in Sec. 63.1562(a) of this subpart.
(b) Catalytic reforming unit regeneration. The owner or operator a
catalytic reforming unit shall comply with the standards in paragraphs
(b)(1) and (b)(2) of this section.
(1) During depressurization and purging from semi-regenerative
processes, comply with the standards for existing affected sources in
Secs. 63.1562(b)(1)(i) or (b)(1)(ii) of this subpart; and
(2) During coke burn-off and catalyst regeneration, reduce
uncontrolled emissions of HCl from semi-regenerative, cyclic, or
continuous processes by 97 percent by weight using a control device, or
to a concentration of 10 ppm by volume, on a dry basis, corrected to 3
percent oxygen.
(c) Sulfur recovery units. The owner or operator shall comply with
the standard for existing affected sources in Sec. 63.1562(c) of this
subpart.
Sec. 63.1564 Compliance dates and performance tests.
(a) Compliance dates. The owner or operator of a catalytic cracking
unit, catalytic reforming unit, or sulfur recovery unit shall
demonstrate initial compliance with the requirements of this subpart by
the following dates:
(1) [Insert date 3 years following the date of publication date of
the final rule in the Federal Register] for an existing source unless
an extension has been granted by the Administrator as provided in
Sec. 63.6(i) of this part.
(2) [Insert date of publication of final rule in the Federal
Register] or upon initial startup, whichever is later, for a new source
that commences construction or reconstruction after September 11, 1998.
(b) Performance tests--catalytic cracking units. (1) During the
first 150 days following the compliance date, the owner or operator
shall conduct a performance test for each new or existing catalytic
cracking unit to determine and demonstrate compliance with the PM or Ni
emission standard using the test methods and procedures in Sec. 63.1566
of this subpart.
(2) During the first 150 days following the compliance date, the
owner or
[[Page 48913]]
operator of a new or existing catalytic cracking unit that does not use
a combustion device to comply with the CO emission standard and elects
to comply with the continuous emission monitoring requirements of
Sec. 63.1565(d)(1) of this subpart shall determine and demonstrate
compliance according to the following procedures:
(i) The owner or operator shall conduct a performance evaluation of
the CO continuous emission monitoring system to determine and
demonstrate compliance with the requirements of Performance
Specification 4A in appendix B to part 60 of this chapter. The span
value shall be 1,000 ppm CO. The performance evaluation shall be
conducted according to the procedures in Sec. 63.8(e) of this part.
(ii) Using the continuous emission monitoring system, the owner or
operator shall measure and record the average hourly concentration of
CO emissions from each catalytic cracking unit during 7 consecutive
operating days. The data shall be reduced to 1-hour averages computed
from four or more data points equally spaced over each 1-hour period.
Compliance is demonstrated where the average hourly concentration is
less than or equal to 500 ppm by volume (dry basis).
(3) During the first 150 days following the compliance date, the
owner or operator of a catalytic cracking unit that does not use a
combustion control device and elects to comply with the operating
parameter monitoring requirements of Sec. 63.1565(d)(2) of this
subpart, shall conduct a performance test for each unit to determine
and demonstrate compliance with the CO emission standard using the test
methods and procedures in Sec. 63.1566 of this subpart.
(4) During the first 150 days following the compliance date, the
owner or operator of a new or existing catalytic cracking unit that
uses a boiler or process heater with a design heat capacity less than
44 megawatts (MW) where the vent stream is not introduced into the
flame zone shall conduct a performance test for each unit to determine
and demonstrate compliance with the TOC emission standard using the
test methods and procedures in Sec. 63.1566 of this subpart.
(c) Performance tests--catalytic reforming units. (1) During the
first 150 days following the compliance date, the owner or operator of
a new or existing cyclic or continuous catalytic reforming unit shall
conduct a performance test for each unit to determine and demonstrate
compliance with applicable TOC and HCl emission standards using the
test methods and procedures in Sec. 63.1566 of this subpart.
(2) At the first regeneration cycle following the compliance date,
the owner or operator of a new or existing semi-regenerative catalytic
reforming unit shall conduct an initial performance test for each unit
to determine and demonstrate compliance with applicable TOC and HCl
emission standards using the test methods and procedures in
Sec. 63.1566 of this subpart.
(3) The owner or operator of a new or existing catalytic reforming
unit is not required to conduct a performance test to demonstrate
compliance with the TOC percent reduction or concentration emission
standards in Sec. 63.1562(b)(1)(ii) of this subpart when any of the
following control devices are used:
(i) Any boiler or process heater with a design heat input capacity
of 44 MW or greater;
(ii) Any boiler or process heater in which all vent streams are
introduced into the flame zone; or
(iii) Any flare that complies with the control device requirements
in Sec. 63.11(b) of this part.
(d) Performance tests--sulfur recovery units. During the first 150
days following the compliance date, the owner or operator of a new or
existing sulfur recovery unit shall conduct a performance test for each
unit to determine and demonstrate compliance with the applicable
emission standard for TRS compounds using the test methods and
procedures in Sec. 63.1566 of this subpart.
(e) Test conditions. Each performance test shall be conducted
according to the requirements of Sec. 63.7(e) of this part except that
performance tests shall be conducted at maximum representative
operating capacity for the process. The owner or operator shall conduct
the test while operating the control device at conditions which result
in lowest emission reduction.
(1) Each performance test shall consist of three separate runs.
Compliance is demonstrated when the average of three runs is less than
or equal to the applicable standard.
(2) Data shall be reduced in accordance with the EPA-approved
methods specified in Sec. 63.1566 of this subpart or, if other test
methods are used, the data and methods shall be validated in accordance
with the protocol in Method 301 of appendix A to this part.
(f) Process/operating parameter range. The owner or operator of a
new or existing catalytic cracking unit, catalytic reforming unit, or
sulfur recovery unit shall establish a minimum and/or maximum operating
value or procedure for each parameter to be monitored as required by
Sec. 63.1565 of this subpart that ensures compliance with the
applicable emission standard. To establish the minimum and/or maximum
value, the owner or operator shall use the procedures in paragraphs
(f)(1) through (f)(9) of this section, as applicable to the control
device, and submit the information required by Sec. 63.1567(a)(6) in
the notification of compliance status report.
(1) For a thermal incinerator, the owner or operator shall measure
and record the combustion zone temperature over the full period of the
performance test, record each hourly or 1-hour block average value, and
determine the minimum and average combustion zone temperature.
(2) For a catalytic incinerator, the owner or operator shall
measure the upstream and downstream temperatures and temperature
difference across the catalyst bed over the full period of the
performance test, record each hourly or 1-hour block average value, and
determine the minimum and average upstream temperature and temperature
difference across the catalyst bed.
(3) For a boiler or process heater with a design heat capacity less
than 44 MW where the vent stream is not introduced into the flame zone,
the owner or operator shall measure the combustion zone temperature
over the full period of the performance test, record each hourly or 1-
hour block average value, and determine the minimum and average
combustion zone temperature.
(4) For a flare, the owner or operator shall record the presence of
a flame at the pilot light over the full period of the compliance
determination.
(5) For an electrostatic precipitator, the owner or operator shall
measure the voltage and secondary current or the total power input over
the full period of the performance test, record each hourly or 1-hour
block average value, and determine the minimum and average hourly
voltage and secondary current or total power input.
(6) For a wet scrubber, the owner or operator shall measure the
pressure drop across the scrubber, the gas flow rate, and the total
water (or scrubbing liquid) flow rate to the scrubber over the full
period of the performance test, record each hourly or 1-hour block
average value, and determine the minimum and average pressure drop, the
maximum and average gas flow rate, the minimum and average total water
(or scrubbing liquid) flow rate, and the minimum and average liquid-to-
gas ratio.
(7) For a catalytic cracking unit that does not use a combustion
device where
[[Page 48914]]
the owner or operator elects to monitor operating parameters under
Sec. 63.1565(d)(2) of this subpart, the owner or operator shall measure
the temperature of the catalytic cracking unit and the oxygen content
of the regenerator exhaust gas over the full period of the performance
test, record each hourly or 1-hour block average value, and determine
the minimum and average hourly temperature and oxygen content.
(8) The owner or operator of a catalytic cracking unit catalyst
regenerator subject to the PM emission standard in
Sec. 63.1562(a)(1)(i) of this subpart shall determine and record the
average coke burn-off rate (thousands of kg/hr) and the hours of
operation for the unit.
(9) For all control devices, the owner or operator shall record
whether the flow indicator, if required, was operating and whether flow
was detected at any time during each hour of the full period of the
performance test.
Sec. 63.1565 Monitoring requirements.
(a) Combustion control device. Except as provided in paragraph
(a)(4) of this section, the owner or operator of a new or existing
catalytic cracking unit, catalytic reforming unit, or sulfur recovery
unit that uses a combustion control device to comply with the emission
standards of this subpart shall install, operate, and maintain the
monitoring equipment specified in paragraph (a)(1), (a)(2), or (a)(3)
of this section, depending on the type of combustion control device
used.
(1) Where an incinerator is used:
(i) For each thermal incinerator, a measurement device equipped
with a continuous recorder to measure and record the daily average
combustion zone temperature. The measurement device shall be installed
in the combustion zone or in the ductwork immediately downstream of the
combustion zone in a position before any substantial heat exchange
occurs; or
(ii) For each catalytic incinerator, a measurement device equipped
with a continuous recorder to measure and record the daily average
upstream temperature and temperature difference across the catalyst
bed. The measurement devices shall be installed in the gas stream
immediately before and after the catalyst bed.
(iii) The accuracy of the temperature measurement device shall be
1 percent of the temperature being measured, expressed in
degrees Celsius (C) or 0.5 deg.C, whichever is greater.
(iv) The owner or operator shall verify the calibration of the
temperature measurement device every 3 months.
(2) Where a flare is used, a device (including but not limited to a
thermocouple, an ultraviolet beam sensor, or an infrared sensor) that
continuously detects the presence of a pilot flame. The owner or
operator shall record, for each 1-hour period, whether the monitor was
continuously operating and whether a pilot flame was continuously
present during each hour.
(3) Where a boiler or process heater with a design heat capacity
less than 44 MW where the vent stream is not introduced into the flame
zone is used, a measurement device equipped with a continuous recorder
to measure and record the daily average combustion zone temperature.
(i) The accuracy of the temperature measurement device shall be
1 percent of the temperature being measured, expressed in
degrees C or 0.5 deg.C, whichever is greater.
(ii) The owner or operator shall verify the calibration of the
temperature measurement device every 3 months.
(4) Any boiler or process heater with a design heat capacity
greater than or equal to 44 MW or any boiler or process heater in which
all vent streams are introduced into the flame zone is exempt from the
monitoring requirements in this paragraph.
(b) Catalytic cracking unit--electrostatic precipitator. The owner
or operator of a new or existing catalytic cracking unit that uses an
electrostatic precipitator to comply with the emission standards of
this subpart shall install, operate, and maintain a measurement device
equipped with a continuous recorder to measure and record the average
hourly voltage and secondary current or the average hourly total power
input.
(c) Catalytic cracking unit/catalytic reforming unit--scrubber. The
owner or operator of a new or existing catalytic cracking unit or
catalytic reforming unit that uses a wet scrubber to comply with the
emission standards of this subpart shall install, calibrate, operate,
and maintain:
(1) A measurement device equipped with a continous recorder to
measure and record the average daily pressure drop across the scrubber,
the average daily gas flow rate to the scrubber, and the average daily
total water (or scrubbing liquid) flow rate to the scrubber.
(i) The pressure drop monitor is to be certified by the
manufacturer to be accurate within 250 pascals
(1 inch water gauge) over its operating range. The flow
rate monitors are to be certified by their manufacturers to be accurate
within 5 percent over their operating ranges.
(ii) The owner or operator shall verify the calibration of the
pressure drop and flow rate monitors every 3 months.
(2) The owner or operator shall calculate and record the daily
average liquid-to-gas ratio.
(d) Catalytic cracking unit--no combustion device. Each owner or
operator of a new or existing catalytic cracking unit regenerator that
does not use a combustion device to comply with the CO emission
standard in Sec. 63.1562(a)(2) of this subpart shall install,
calibrate, operate, and maintain a continuous emission monitoring
system as described in paragraph (d)(1) of this section or a continous
parameter monitoring system as described in paragraph (d)(2) of this
section.
(1) The owner or operator shall install, operate, calibrate, and
maintain a continuous emission monitoring system to measure and record
the concentration of CO in the exhaust gases of each catalytic cracking
unit regenerator vent and determine the hourly average concentration in
ppm by volume (dry basis) of CO emissions into the atmosphere.
(i) The continuous emission monitoring system shall meet the
requirements of Performance Specification 4A in part 60 of this
chapter. The span value for this system is 1,000 ppm CO.
(ii) Each continuous emission monitoring system shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(iii) The owner or operator shall operate and maintain each
continuous emission monitoring system in accordance with the
requirements of Sec. 63.8 of this part and the quality assurance
procedures in appendix F to part 60 of this chapter.
(2) The owner or operator shall install, calibrate, operate, and
maintain:
(i) A measurement device equipped with a continuous recorder to
measure and record the average hourly temperature of the catalytic
cracking unit regeneration unit exhaust gas; and
(ii) A measurement device equipped with a continuous recorder to
measure and record the average hourly oxygen content of the regenerator
exhaust gas.
(iii) The accuracy of the temperature measurement device shall be
1 percent of the temperature being measured, expressed in
degrees C or 0.5 deg.C, whichever is greater. The accuracy
of the oxygen sensor shall be 1 percent over its operating
range.
[[Page 48915]]
(iv) The owner or operator shall verify the calibration of the
temperature and oxygen measurement devices every 3 months.
(3) The monitoring requirements in paragraphs (d)(1) and (d)(2) of
this section do not apply if the owner or operator demonstrates that
the average CO emissions are less than 50 ppm by volume (dry basis) and
also files a written request for exemption with the applicable
permitting authority and receives such an exemption. The demonstration
shall consist of continuously monitoring CO emissions for 30 days using
an instrument that meets the requirements of Performance Specification
4A of appendix B to part 60 of this chapter. The span value shall be
100 ppm CO instead of 1,000 ppm, and the relative accuracy limit shall
be 10 percent of the average CO emissions or 5 ppm CO, whichever is
greater. For instruments that are identical to Method 10 in appendix A
to part 60 of this chapter and employ the sample conditioning system of
Method 10A in appendix A to part 60 of this chapter, the alternative
relative accuracy test procedure in section 10.1 of Performance
Specification 2 of appendix B to part 60 of this chapter may be used in
place of the relative accuracy test.
(e) Catalytic cracking unit catalyst regenerator. The owner or
operator of a catalytic cracking unit catalyst regenerator subject to
the PM emission standard in Sec. 63.1562(a)(1)(i) of this subpart shall
calculate the daily average coke burn-off rate (thousands of kg/hr)
using the calculation procedure in Sec. 63.1566(a)(3) of this subpart
(Test methods and procedures) and record the information specified in
Sec. 63.1567(e)(4)(xii) of this subpart (Notification, reporting, and
recordkeeping requirements). For purposes of daily average coke burn-
off calculations, the exhaust gas flow can be calculated from process
data.
(f) Catalytic cracking unit--no electrostatic precipitator or
scrubber. An owner or operator of a new or existing catalytic cracking
unit that does not use an electrostatic precipitator or scrubber to
comply with the PM or Ni emission standards in Sec. 63.1562(a)(1) of
this subpart shall include, subject to approval of the applicable
permitting authority, a recommended continuous parameter monitoring
system for each affected source in the part 70 or part 71 permit
application. Each application shall include the information required in
Sec. 63.1567(a)(6)(v)(B) of this subpart (Notification, reporting, and
recordkeeping requirements).
(g) Sulfur recovery unit--no combustion device. The owner or
operator of a new or existing sulfur recovery unit that does not use a
combustion device to comply with the TRS emission standard in
Sec. 63.1562(c) of this subpart shall include, subject to approval by
the applicable permitting authority, a recommended continuous parameter
monitoring system for each affected source in the part 70 or part 71
permit application. Each application shall include the information
required in Sec. 63.1567(a)(6)(v)(B) of this subpart (Notification,
reporting, and recordkeeping requirements).
(h) Bypass line. The owner or operator of a new or existing
catalytic cracking unit, catalytic reforming unit, or sulfur recovery
unit using a vent system that contains a bypass line that could divert
a vent stream away from the control device used to comply with the
emission limits in this subpart shall comply with the requirements of
either paragraph (h)(1) or (h)(2) of this section. Equipment such as
low leg drains, high point bleed, analyzer vents, open-ended valves or
lines, or pressure relief valves needed for safety reasons are not
subject to the requirements of this paragraph.
(1) Install, calibrate, operate, and maintain a flow indicator. The
device shall be installed at the entrance to any bypass line that could
divert the vent stream away from the control device to the atmosphere.
The owner or operator shall visually inspect the flow indicator at
least once every hour to determine that the flow indicator is operating
properly and whether gas or vapor are present in the bypass line and
record the information specified in Sec. 63.1567(e)(4)(x) of this
subpart (Notification, reporting, and recordkeeping requirements); or
(2) Secure the bypass line valve in the closed position with a car-
seal or a lock-and-key type configuration. The device shall be placed
on the mechanism by which the bypass device position is controlled
(e.g., valve handle, damper level) when the bypass device is in the
closed position such that the bypass line valve cannot be opened
without breaking the seal or removing the device. The owner or operator
shall visually inspect the seal or closure mechanism at least once
every month to ensure that the valve is maintained in the closed
position and the vent stream is not diverted through the bypass line,
and record the information specified in Sec. 63.1567(e)(4)(x) of this
subpart (Notification, reporting, and recordkeeping requirements).
(i) Installation, calibration, operation, and maintenance of
monitoring systems and devices. All continuous parameter monitoring
systems and devices required or allowed by this section shall be
installed, calibrated, maintained, and operated according to
manufacturer's specifications or according to other written procedures
that provide adequate assurance that the equipment will monitor
accurately.
(j) Averaging times for continuous parameter monitoring systems.
Each continuous parameter monitoring system shall measure data values
at least once every hour and record either:
(1) Each measured data value; or
(2) Block average values for each 1-hour period or shorter periods
calculated from all measured data values during each period. If values
are measured more frequently than once per minute, a single value for
each minute may be used to calculate the hourly (or shorter period)
block average instead of all measured values.
(3) Daily averages shall be calculated as the average of all values
for a monitored parameter recorded during the operating day. The
average shall cover a 24-hour period if operation is continuous or the
number of hours of operation per day if operation is not continuous.
(4) Monitoring data recorded during periods of unavoidable
monitoring system breakdowns, repairs, calibration checks, and zero
(low-level) and high-level adjustments; startup, shutdowns, and
malfunctions; and periods of nonoperation of the process unit resulting
in cessation of the emissions to which the monitoring applies shall not
be included in any average computed under this subpart.
(k) Operation of control device. The owner or operator of a new or
existing affected source equipped with a control device subject to the
monitoring provisions of this section shall operate the control device
above or below, as appropriate, the minimum or maximum value specified
in the notification of compliance status report.
(l) Parameter changes. (1) The owner or operator may change the
established level of control device or process operating parameters by
conducting additional performance tests to verify that, at the new
control device or process parameter level, the owner or operator is in
compliance with the applicable emission standard in Secs. 63.1562 or
63.1563 of this subpart.
(2) The owner or operator shall conduct a new performance test to
establish a revised minimum or maximum value for the monitored process
or operating parmeter to determine and demonstrate compliance under the
new operating conditions if any change to the process or operating
[[Page 48916]]
conditions (including but not limited to feedstock, capacity, control
device or capture system) that could result in a change in the control
system performance or designated conditions has been made since the
last performance or compliance tests were conducted.
(m) Alternative parameters. (1) The owner or operator of a
catalytic cracking unit, catalytic reforming unit, or sulfur recovery
unit may request approval to monitor parameters other than those listed
in paragraphs (a) through (d) of this section. The request shall be
submitted according to the procedures specified in paragraph (m)(2) of
this section. Approval shall be requested if the owner or operator:
(i) Uses a control device other than an incinerator, boiler,
process heater, flare, electrostatic precipitator, or scrubber;
(ii) Uses one of the control devices listed in paragraphs (a)
through (c) of this section, but seeks to monitor a parameter other
than those specified in paragraphs (a) through (d) of this section; or
(iii) Uses no control device or a control method, such as
pretreatment, rather than an add-on control device.
(2) To apply for use of alternative monitoring parameters, the
owner or operator shall submit a request for review and approval or
disapproval by the applicable permitting authority. The submittal shall
include:
(i) A description of each affected source and the parameter(s) to
be monitored to determine whether periods of excess emissions occur, as
defined in paragraph (o) of this section, and an explanation of the
criteria used to select the parameter(s);
(ii) A description of the methods and procedures that will be used
to demonstrate that the parameter can be used to determine excess
emissions and the schedule for this demonstration. The owner or
operator must certify that he/she will establish a minimum and/or
maximum value, as applicable, for the monitored parameter(s) that
represents the conditions in existence when the control device is being
properly operated and maintained; and
(iii) The frequency and content of monitoring, recording, and
reporting, if monitoring and recording are not continuous. The
rationale for the proposed monitoring, recording, and reporting system
shall be included.
(n) Automated data compression system. The owner or operator may
request approval to use an automated data compression system that 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.
(1) The requested system shall be designed to:
(i) Measure the operating parameter value at least once every hour;
(ii) Record at least 24 values each day during periods of
operation;
(iii) Record the date and time when monitors are turned off or on;
(iv) Recognize unchanging data that may indicate the monitor is not
functioning properly, alert the operator, and record the incident; and
(v) Compute daily average values of the monitored operating
parameter based on recorded data.
(2) The request shall 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 criteria of paragraph (j)(1) of this section.
(o) Excess emissions. (1) Period of excess emissions means any of
the following conditions:
(i) For a thermal incinerator, an operating day when the daily
average temperature falls below the minimum value specified in the
notification of compliance status report;
(ii) For a catalytic incinerator, an operating day when the daily
average upstream temperature or the daily average temperature
difference across the catalyst bed falls below the minimum value
specified in the notification of compliance status report;
(iii) For a boiler or process heater with a design heat capacity
less than 44 MW where the vent stream is not introduced into a flame
zone, an operating day when the daily average temperature falls below
the minimum value specified in the notification of compliance status
report;
(iv) For an electrostatic precipitator, any period when the average
hourly voltage or secondary current or the average hourly total power
input falls below the minimum value specified in the notification of
compliance status report;
(v) For a wet scrubber, an operating day when the daily average
pressure drop or daily average liquid-to-gas ratio falls below the
minimum value specified in the notification of compliance status
report;
(vi) For a catalytic cracking unit with no combustion device, any
period when the average hourly CO concentration measured by the CO
continuous emission monitoring system required by paragraph (d)(1) of
this section exceeds 500 ppmv or any period when the average hourly
temperature or oxygen content falls below the minimum value specified
in the notification of compliance status report;
(vii) For a catalytic cracking unit catalyst regenerator subject to
the PM emission standard in Sec. 63.1562(a)(1)(i) of this subpart, an
operating day when the daily average coke burn-off rate exceeds the
value specified in the notification of compliance status report;
(viii) An operating day when all pilot flames of a flare are
absent;
(ix) An operating day when monitoring data are available for less
than 75 percent of the operating hours;
(x) For data compression systems approved under paragraph (n) of
this section, an operating day when the monitor operated for less than
75 percent of the operating hours or a day when less than 18 monitoring
values were recorded; or
(xi) A period when flow to the control device is diverted or
otherwise by-passed.
(2) Multiple excursions from the same control device during the
applicable averaging period (e.g. 1-hour, 24-hours) constitutes a
single excursion.
(p) Violation. Monitoring data under this subpart are directly
enforceable to determine compliance with the required operating
conditions for the monitored control devices. For each period of excess
emissions, as defined in paragraph (o) of this section, the owner or
operator shall be deemed to have failed to have applied the control in
a manner that achieves the required operating conditions. More than one
exceedance or excursion by the same control device during a semi-annual
reporting period is a violation of this subpart.
Sec. 63.1566 Test methods and procedures.
(a) The owner or operator of a catalytic cracking unit shall
determine compliance with the PM emission standard in
Sec. 63.1562(a)(1)(i) of this subpart as follows:
(1) The emission rate (E) of PM shall be computed for each run
using Equation 1:
[GRAPHIC] [TIFF OMITTED] TP11SE98.022
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 effluent gas, 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)].
[[Page 48917]]
(2) Method 5B or 5F in appendix A to part 60 of this chapter is to
be used to determine PM emissions and associated moisture content from
affected facilities without wet flue gas desulfurization (FGD) systems;
only Method 5B in appendix A to part 60 of this chapter is to be used
after wet FGD systems. The sampling time for each run shall be at least
60 minutes and the sampling rate shall be at least 0.015 dscm/min (0.53
dscf/min), except that shorter sampling times may be approved by the
permitting authority when process variables or other factors preclude
sampling for at least 60 minutes.
(3) The coke burn-off rate (Rc) shall be computed for
each run using Equation 2:
[GRAPHIC] [TIFF OMITTED] TP11SE98.023
Where,
Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from catalyst
regenerator before additional air or gas streams are added (e.g.,
measurements may be made after an ESP, but must be made before a CO
boiler), dscm/min (dscf/min);
Qa = Volumetric flow rate of air to regenerator, as
determined from the catalytic cracking unit control room
instrumentation, 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 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-min)/
(hr-dscm-%) [0.1303 (lb-min)/(hr-dscf-%)];
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) [(0.0062 (lb-min)/(hr-dscf-%)];
Qoxy = Volumetric flow rate of oxygen-enriched air stream to
regenerator, as determined from the catalytic cracking unit control
room instrumentation, dscm/min (dscf/min); and
%Oxy = Oxygen concentration in oxygen-enriched air stream,
percent by volume (dry basis).
(i) Method 2 in appendix A to part 60 of this chapter shall be used
to determine the volumetric flow rate (Qr) for a performance
test; for daily calculations, the volumetric flow rate can be
determined using process data.
(ii) The emission correction factor, integrated sampling and
analysis procedure of Method 3 in appendix A to part 60 of this chapter
shall used to determine CO2, CO, and O2
concentrations.
(b) The owner or operator shall determine compliance with the Ni
standard in Sec. 63.1562(a)(1)(ii) of this subpart using the procedures
in paragraphs (b)(1) through (b)(3) of this section.
(1) Method 29 in appendix A to part 60 of this chapter shall be
used to determine the concentration of Ni in the catalytic cracking
unit catalyst regenerator flue gas. The sampling time for each run
shall be at least 60 minutes and the sampling rate shall be at least
0.014 dscm/min (0.5 dscf/min).
(2) Method 2 in appendix A to part 60 of this chapter shall be used
to determine volumetric flow rate (Qsd).
(3) The mass emission rate (ENi) shall be computed for
each run using Equation 3:
[GRAPHIC] [TIFF OMITTED] TP11SE98.024
Where,
ENi = Mass emission rate of Ni, mg/hr (lb/hr);
CNi = Ni concentration in the catalytic cracking unit
catalyst regenerator flue gas as measured by Method 29 in appendix A to
part 60 of this chapter, mg/dscm (lbs/dscf); and
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).
(c) The owner or operator shall determine compliance with the CO
emission standard in Sec. 63.1562(a)(2) of this subpart by using the
integrated sampling technique of Method 10 in appendix A to part 60 of
this chapter to determine the CO concentration (dry basis). The
sampling time for each run shall be 60 minutes.
(d) The owner or operator of a catalytic reforming unit using a
flare to comply with the TOC emission standard in Sec. 63.1562(b)(1) of
this subpart shall determine compliance with the visible emission
standard as required by Sec. 63.11(b)(4) of this part using Method 22
in appendix A to part 60 of this chapter.
(e) Except as provided in the performance test provisions for
catalytic reforming units in Sec. 63.1564(c)(3) of this subpart and in
paragraph (i) of this section, the owner or operator shall determine
compliance with the 98 percent reduction standard for TOC in
Sec. 63.1562(b)(1)(ii) of this subpart by measuring emissions at the
inlet and at the outlet of the control device to determine percent
reduction using the following test methods and procedures:
(1) Methods 1 or 1A in appendix A to part 60 of this chapter shall
be used for selection of the sampling site.
(2) No traverse site selection method is needed for vents smaller
than 0.10 meter in diameter.
(3) The gas volumetric flow rate shall be determined using Methods
2, 2A, 2C, or 2D in appendix A to part 60 of this chapter, as
appropriate.
(4) Method 18 or Method 25A in appendix A to part 60 of this
chapter shall be used to measure TOC concentration. Alternatively, any
other method or data that has been validated according to the protocol
in Method 301 of appendix A of this part may be used. The following
procedures shall be used to calculate ppm by volume concentration:
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or four grab samples shall be taken. If
grab sampling is used, then the samples shall be taken at approximately
equal intervals in time, such as 15-minute intervals during the run;
(ii) The TOC concentration (CTOC) is the sum of the
concentrations of the individual components and shall be computed for
each run using Equation 4 if Method 18 is used:
[GRAPHIC] [TIFF OMITTED] TP11SE98.025
Where,
CTOC = Concentration of TOC (minus methane and ethane), dry
basis, parts per million by volume;
Cji = Concentration of sample component j of the sample i,
dry basis, parts per million by volume;
n = Number of components in the sample; and
[[Page 48918]]
x = Number of samples in the sample run.
(5) The emission rate of TOC minus methane and ethane
(ETOC) shall be calculated using Equation 5 if Method 18 in
appendix A to part 60 of this chapter is used:
[GRAPHIC] [TIFF OMITTED] TP11SE98.026
Where,
E = Emission rate of TOC (minus methane and ethane) in the sample,
kilograms per hour;
K2 = Constant, 2.494 x 10-6 (parts per
million)-1 (gram-mole per standard cubic meter) (kilogram
per gram) (minutes per hour), where the standard temperature (standard
cubic meter) is at 20 deg.C;
Cj = Concentration on a dry basis of organic compound j in
ppm as measured by Method 18 in appendix A to part 60 of this chapter.
Cj includes all organic compounds measured minus methane and
ethane;
Mj = Molecular weight of organic compound j, gram per gram-
mole; and
Qs = Vent stream flow rate, dry standard cubic meters per
minute, at a temperature of 20 deg.C.
(6) If Method 25A in appendix A to part 60 of this chapter is used
the emission rate of TOC (ETOC ) shall be calculated using
Equation 6:
[GRAPHIC] [TIFF OMITTED] TP11SE98.027
Where,
E = Emission rate of TOC (minus methane and ethane) in the sample,
kilograms per hour;
K3 = Constant, 2.64 x 10-3 (parts per
million)-1 (gram-mole per standard cubic meter) (gram per
gram-mole) (kilogram per gram) (minutes per hour), where the standard
temperature (standard cubic meter) is at 20 deg.C;
CTOC = Concentration of TOC on a dry basis in ppm by volume
as propane as measured by Method 25A in appendix A to part 60 of this
chapter, as indicated in paragraph (f)(4) of this section; and
Qs = Vent stream flow rate, dry standard cubic meters per
minute, at a temperature of 20 deg.C.
(f) Except as provided in the performance test provisions for a
catalytic reforming unit in Sec. 63.1564(c)(3) of this subpart and
paragraph (i) of this section, the owner or operator shall determine
compliance with the requirements for a TOC limit of 20 ppm in
Sec. 63.1562(b)(1)(ii) of this subpart by sampling at the outlet of the
control device using Methods 18 or 25A in appendix A to part 60 of this
chapter and the procedures in paragraph (e)(4) of this section to
determine concentration.
(g) The owner or operator shall determine compliance with the TRS
standards in Secs. 63.1562(c) and 63.1563(c) of this subpart as
follows:
(1) Method 15 of appendix A to part 60 of this chapter shall be
used to determine the concentration of TRS. Each run shall consist of
16 samples taken over a minimum 3 hours. The sampling point in the duct
shall be the centroid of the cross section if the cross-sectional area
is less than 5 square meters (m2) or 54 square feet
(ft2) or at a point no closer to the walls than 1 meter (m)
or 39 inches (in) if the cross-sectional area is 5 m2 or
more and the centroid is more than 1 m from the wall. To ensure minimum
residence time for the sample inside the sample lines, the sampling
rate shall be at least 3 liters per minute (lpm) or 0.10 cubic feet per
minute (cfm). The SO2 equivalent for each run shall be
calculated after being corrected for moisture and oxygen as the
arithmetic average of the SO2 equivalent for each sample during the
run.
(2) Method 4 of appendix A to part 60 of this chapter shall be used
to determine the moisture content of the gases. The sampling time for
each sample shall be equal to the time it takes for four Method 15
samples.
(3) The oxygen concentration used to correct the emission rate for
excess air shall be obtained by the integrated sampling and analysis
procedure of Method 3 in appendix A to part 60 of this chapter. The
samples shall be taken simultaneously with reduced sulfur or moisture
samples. The reduced sulfur samples shall be corrected to zero percent
excess air using Equation 7:
[GRAPHIC] [TIFF OMITTED] TP11SE98.028
Where,
Cadj = pollutant concentration adjusted to zero percent
oxygen, ppm or g/dscm;
Cmeas = pollutant concentration measured on a dry basis, ppm
or g/dscm;
20.9c = 20.9 percent oxygen--0.0 percent oxygen (defined
oxygen correction basis), percent;
20.9 = oxygen concentration in air, percent; and
%O2 = oxygen concentration measured on a dry basis, percent.
(h) The owner or operator shall determine compliance with the HCl
emission standards in Secs. 63.1562(b)(2) and (b)(3) and
Sec. 63.1563(b)(2) of this subpart using Method 26A in appendix A to
part 60 of this chapter. To determine percent reduction, sampling shall
be performed at the inlet and at the outlet of the control device. The
sampling time for each run shall be at least 60 minutes and the
sampling rate shall be at least 0.021 dscm/min (0.74 dscf/min).
(i) Engineering assessment may be used to determine the emission
reduction or outlet concentration for the representative operating
condition expected to yield the highest daily emission rate.
Engineering assessment includes, but is not limited to, the following:
(1) Previous test results provided the tests are representative of
current operating practices at the process unit;
(2) Bench-scale or pilot-scale test data representative of the
process under representative operating conditions;
(3) TOC emission rate specified or implied within a permit limit
applicable to the process vent;
(4) Design analysis based on accepted chemical engineering
principles, measurable process parameters, or physical or chemical laws
or properties. Examples of analytical methods include, but are not
limited to:
(i) Use of material balances based on process stoichiometry to
estimate maximum TOC concentrations;
(ii) Estimation of maximum flow rate based on physical equipment
design such as pump or blower capacities; and
(iii) Estimation of TOC concentrations based on saturation
conditions.
(5) Engineering assessments based on approaches other than those
listed above shall be subject to review and approval by the applicable
permitting authority.
(6) All data, assumptions, and procedures used in the engineering
assessment shall be documented to the satisfaction of the applicable
permitting authority.
(j) The owner or operator may use an alternative test method
subject to approval by the Administrator.
Sec. 63.1567 Notification, reporting, and recordkeeping requirements.
(a) Notifications. The owner or operator shall submit written
initial notifications to the applicable permitting authority as
described in paragraphs (a)(1) through (a)(7) of this paragraph:
(1) As required by Sec. 63.9(b)(1) of this part, the owner or
operator shall provide notification for an area source that
subsequently increases its emissions such that the source is a major
source subject to the standard.
[[Page 48919]]
(2) As required by Sec. 63.9(b)(3) of this part, the owner or
operator of a new or reconstructed affected source, or a source that
has been reconstructed such that it is an affected source, that has an
initial startup after the effective date of this subpart and for which
an application for approval or construction or reconstruction is not
required under Sec. 63.5(d) of this part, shall provide notification
that the source is subject to the standard. The notification shall
contain the general information required for the notification of
compliance status in paragraph (a)(6)(i) of this section.
(3) As required by Sec. 63.9(b)(4) of this part, the owner or
operator of a new or reconstructed major affected source that has an
initial startup after the effective date of this subpart and for which
an application for approval of construction or reconstruction is
required by Sec. 63.5(d) of this part shall provide the following
notifications:
(i) Notification of intention to construct a new major affected
source, reconstruct a major source, or reconstruct a major source such
that the source becomes a major affected source;
(ii) Notification of the date when construction or reconstruction
was commenced (submitted simultaneously with the application for
approval of construction or reconstruction if construction or
reconstruction was commenced before the effective date of this subpart
or no later than 30 days of the date construction or reconstruction
commenced if construction or reconstruction commenced after the
effective date of this subpart);
(iii) Notification of the anticipated date of startup; and
(iv) Notification of the actual date of startup.
(4) As required by Sec. 63.9(b)(5) of this part, after the
effective date of this subpart, an owner or operator who intends to
construct a new affected source or reconstruct an affected source
subject to this subpart, or reconstruct a source such that it becomes
an affected source subject to this subpart shall provide notification
of the intended construction or reconstruction. The notification shall
include all the information required for an application for approval of
construction or reconstruction as required by Sec. 63.5(d) of this
part. For major sources, the application for approval of construction
or reconstruction may be used to fulfill these requirements.
(i) The application shall be submitted as soon as practicable
before the construction or reconstruction is planned to commence (but
no sooner than the effective date) if the construction or
reconstruction commences after the effective date of this subpart; or
(ii) The application shall be submitted as soon as practicable
before startup but no later than 90 days after the effective date of
this subpart if the construction or reconstruction had commenced and
initial startup had not occurred before the effective date.
(5) As required by Secs. 63.9(e) and 63.9(f) of this part, the
owner or operator shall provide notification of the anticipated date
for conducting performance tests and visible emission observations for
flares. The owner or operator shall notify the Administrator of the
intent to conduct a performance test or perform visible emission
observations to determine compliance with flare requirements at least
30 days before the test is scheduled.
(6) 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 Sec. 63.1564(a) of this
subpart. The notification shall be signed by the responsible official
who shall certify its accuracy. A complete notification compliance
status report shall include the information in paragraphs (a)(6)(i)
through (a)(6)(vii) 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. In
a State with an approved operating permit program where delegation of
authority under section 112(l) of the Act has not been requested or
approved, the owner or operator shall provide a duplicate notification
to the applicable Regional Administrator. If the required information
has been submitted before the date 150 days after the compliance date
specified in Sec. 63.1564(a) of this subpart, a separate notification
of compliance status report is not required. If an owner or operator
submits the information specified in paragraphs (a)(6)(i) through
(a)(6)(vii) of this section at different times or in different
submittals, later submittals may refer to earlier submittals instead of
duplicating and resubmitting the previously submitted information.
(i) General information:
(A) The name and address of the owner or operator;
(B) The address (i.e., physical location) of the affected source;
(C) An identification of the relevant standard, or other
requirement, that is the basis of the notification and the source's
compliance date; and
(D) A statement of whether the source is a major source or an area
source. If the facility is an area source, the remaining informational
requirements in this paragraph are not applicable.
(ii) A brief description of each affected source, including:
(A) The nature, size, design, and method of operation;
(B) Operating design capacity; and
(C) Identification of each point of emission for each HAP, or if a
definitive identification is not yet possible, a preliminary
identification of each point of emission for each HAP.
(iii) A brief description of each affected source not subject to
the monitoring requirements of this subpart, including:
(A) Identification of any boiler or process heater with a design
heat input capacity greater than or equal to 44 MW or any boiler or
process heater in which all vent streams are introduced into the flame
zone for which monitoring is not required;
(B) Identification of any catalytic cracking unit regenerator that
does not use a combustion device to comply with CO emission standard in
Sec. 63.1562(a)(2) of this subpart for which monitoring is not
required, including CO emission monitoring data and quality assurance
test results as described in Sec. 63.1564(b)(2) of this subpart, a copy
of the exemption approved by the applicable permitting authority, and
information and data demonstrating that the average CO emissions are
less than 50 ppm by volume as required by Sec. 63.1565(d)(3) of this
subpart; and
(C) Identification of each catalytic reforming unit for which
control device requirements do not apply due to depressuring and
purging operations at a differential pressure between the reactor vent
and the gas transfer system to the control device of less than 1 psig
or when the reactor vent pressure is 1 psig or less.
(iv) A description of the air pollution control equipment or method
of compliance for each affected source, including the PM or Ni emission
standard selected under Sec. 63.1562(a) and the catalytic cracking unit
and sulfur recovery unit emission standards and requirements selected
under Sec. 63.1560(d) of this subpart (Applicability and designation of
sources).
(v) The methods used to determine compliance for each affected
source, including:
(A) The engineering assessment specified in Sec. 63.1566(i) of this
subpart or the results of the performance test specified in
Sec. 63.1564 of this subpart. Performance test results shall include
operating ranges of key process and control parameters during the
[[Page 48920]]
performance test; the value, averaged over the period of the
performance test, of each parameter identified in the operating permit
as being monitored in accordance with Sec. 63.1565 of this subpart; and
applicable supporting calculations;
(B) The minimum and/or maximum parameter value, as applicable for
each monitored parameter for each emission point and the data and
rationale used to develop the range, including any data and
calculations used to develop the value and a description of why the
value indicates proper operation of the control device. For any
recommended continuous parameter monitoring system for a catalytic
cracking unit that does not use an electrostatic precipitator or
scrubber to comply with the PM or Ni emission standard in
Sec. 63.1562(a)(1) of this subpart or a sulfur recovery unit that does
not use a combustion device to comply with the TRS emission standard in
Sec. 63.1562(c) of this subpart, the owner or operator shall provide
data and rationale for the recommended system. Following approval of
the recommended system by the permitting authority, the owner or
operator shall provide the information described in this paragraph for
each monitored parameter;
(C) The definition of ``operating day'' for each incinerator,
flare, boiler or process heater with a design input capacity less than
44 MW where the vent stream is not introduced into the flame zone, and
catalytic cracking unit or catalytic reforming unit using a scrubber
for the purpose of determining daily average values of monitored
parameters. The definition, subject to approval by the applicable
permitting authority, shall specify the times at which an operating day
begins and ends; it may be from midnight to midnight or another daily
period; and
(D) If a flare is used to comply with the TOC standards in
Sec. 63.1562(b)(1) of this subpart, the flare design (e.g., steam-
assisted, air-assisted, or non-assisted), all visible emission
readings, heat content determinations, flow rate measurements, and exit
velocity determinations made during the compliance determination and
all periods when the pilot flame is absent.
(vi) Operation, maintenance, and monitoring information, including:
(A) A description of the method that will be used for determining
continuing compliance for each affected source, including a description
of the monitoring and reporting requirements and test methods;
(B) A monitoring schedule, including identification of those time
periods when control device or process parameter monitoring would be
conducted and when monitoring would not be conducted (e.g., monitoring
of emissions from catalytic reforming unit regeneration vents is
required only when the regeneration process is performed);
(C) A maintenance schedule for each process and control device
consistent with the manufacturer's instructions and recommendations for
routine and long-term maintenance; and
(D) Quality control program for continuous parameter monitoring
systems and continuous emission monitoring systems, including
procedures (as applicable) for initial and subsequent calibrations,
preventative maintenance, accuracy audit procedures; corrective action;
and data recording, calculation, reporting, and recordkeeping
procedures to document conformance.
(vii) A statement by the owner or operator as to whether the
existing, new, or reconstructed source is in compliance with the
requirements of this subpart.
(b) Reports--periodic. The owner or operator of a source subject to
this subpart shall submit semi-annual reports no later than 60 calendar
days after the end of each 6-month period if any period of excess
emissions, as defined in Sec. 63.1565(o) of this subpart, occurs during
the reporting period. The first 6-month period shall begin on the date
the notification of compliance status report is required to be
submitted. 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 (b)(1) through (b)(7) of this section. A periodic report is
not required if none of the exceptions specified in paragraphs (b)(1)
through (b)(5) of this section occur during a 6-month period:
(1) Monitoring results for an operating day when:
(i) For a thermal incinerator, the daily average temperature falls
below the minimum value specified in the notification of compliance
status report;
(ii) For a catalytic incinerator, the daily average upstream
temperature or the daily average temperature difference across the
catalyst bed falls below the minimum value specified in the
notification of compliance status report;
(iii) For a boiler or process heater with a design heat capacity
less than 44 MW where the vent stream is not introduced into a flame
zone, the daily average temperature falls below the minimum value
specified in the notification of compliance status report;
(iv) For an electrostatic precipitator, the average hourly voltage
or secondary current or average hourly total power input falls below
the minimum value specified in the notification of compliance status
report;
(v) For a wet scrubber, the daily average pressure drop or daily
average liquid-to-gas ratio falls below the minimum value specified in
the notification of compliance status report;
(vi) For a catalytic cracking unit with no combustion device, the
average hourly CO concentration measured by the CO continuous emission
monitoring system required by Sec. 63.1565(d)(1) of this subpart
exceeds 500 ppmv or any period when the average hourly temperature or
oxygen content falls below the minimum value specified in the
notification of compliance status report; or
(vii) For a catalytic cracking unit catalyst regenerator subject to
the PM emission standard in Sec. 63.1562(a)(1)(i) of this subpart, the
daily average coke burn-off rate (thousands kg/hr) exceeds the maximum
value specified in the notification of compliance status report.
(2) The duration of a period during an operating day when
monitoring data were not available for 75 percent of the operating
hours;
(3) The duration of a period during an operating day when all pilot
flames of a flare are absent;
(4) The time and duration of any period a vent stream is diverted
through a bypass line; or
(5) For data compression systems approved under Sec. 63.1565(n) of
this subpart, an operating day when the monitor operated for less than
75 percent of the operating hours or a day when less than 18 monitoring
values were recorded.
(6) The owner or operator shall submit the results of any
performance test conducted during the reporting period including one
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, results and any other information
required shall be submitted, but a complete test report is not
required. A complete test report shall contain a brief process
description, 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
[[Page 48921]]
calculations, and any other information required by the test method.
(7) A request for changing applicability of the PM or Ni emission
standard in Sec. 63.1562(a) of this subpart or for changing the
applicability of emission standards in this subpart to/from the new
source performance standard in subpart J to part 60 of this chapter as
allowed under Sec. 63.1560(d) of this subpart (Applicability and
designation of affected sources) shall be included in a periodic
report. The request must be accompanied by all information and data
necessary to demonstrate compliance with the emission standard and
associated requirements of this subpart.
(c) Reports--startup, shutdown, and malfunctions. The owner or
operator shall develop and implement a written plan containing specific
procedures to be followed for operating the source and maintaining the
source during periods of startup, shutdown, and malfunction and a
program of corrective action for malfunctioning process and control
systems used to comply with the standard in accordance with the
operation and maintenance requirements in Sec. 63.6(e)(3) of this part.
The duty to develop and implement the plan shall be incorporated in the
facility's part 70 or part 71 operating permit. Each plan shall contain
corrective action procedures to be followed if any of the events in
paragraphs (b)(1) through (b)(3) of this section occur during the 6-
month reporting period, including procedures to determine the cause of
the exceedance or deviation, the time the exceedance or deviation began
and ended, and for recording the actions taken to correct the cause of
the exceedance or deviation. The following reporting and recordkeeping
requirements apply to startups, shutdowns, and malfunctions:
(1) When the actions taken to respond are consistent with the plan,
keep records to document the event and the response as required in
Sec. 63.6(e)(3)(iii) of this part. The owner or operator is not
required to report these events in the semi-annual startup, shutdown,
and malfunction report required under Sec. 63.10(d)(1) of this part
when the actions are consistent with the plan, and the reporting
requirements in Sec. 63.6(e)(3)(iii) and Sec. 63.10(d)(5) of this part
do not apply.
(2) When the actions taken to respond are not consistent with the
plan, keep records to document the event and the response as required
in Sec. 63.6(e)(3)(iv) of this part. The owner or operator shall report
these events and the response taken in the semi-annual startup,
shutdown, and malfunction report required under Sec. 63.10(d)(1) of
this part. In this case, the reporting requirements in
Sec. 63.6(e)(3)(iv) and Sec. 63.10(d)(5) of this part do not apply.
(3) The owner or operator may include the semi-annual startup,
shutdown, and malfunction report required under Sec. 63.10(d)(1) of
this part in the periodic report required by paragraph (b) of this
section.
(d) Annual compliance certification. For the purpose of annual
certifications of compliance required by the permitting regulations in
parts 70 or 71 of this chapter, the owner or operator shall certify
continuing compliance based upon the following conditions:
(1) All periods of excess emissions, including exceedances or
excursions, that occurred during the year have been reported as
required by this subpart; and
(2) All monitoring, recordkeeping, and reporting requirements were
met during the year.
(e) Recordkeeping. (1) The owner or operator must retain each
record required by this subpart for at least 5 years following the date
of each occurrence, measurement, maintenance activity, corrective
action, report, or record. The most recent 2 years of records must be
retained at the facility. The remaining 3 years of records may be
retained off site;
(2) The owner or operator may retain records on microfilm, on a
computer, on computer disks, on magnetic tape, or on microfiche;
(3) The owner or operator may report required information on paper
or on a labeled computer disc using commonly available and compatible
computer software; and
(4) The owner or operator shall maintain records of the following
information:
(i) A copy of the startup, shutdown, and malfunction plan;
(ii) Records documenting the actions taken when a startup,
shutdown, or malfunction occurred and information to demonstrate that
such actions were consistent with the plan;
(iii) All maintenance performed on air pollution control equipment;
(iv) Each period when a continuous monitoring system or continuous
emission monitor was inoperative or malfunctioning;
(v) All measurements, test results (including a complete
performance test report for each affected source), and any other
information needed to demonstrate compliance with the standards in this
subpart;
(vi) All documentation supporting notifications of compliance
status;
(vii) All documentation supporting conformance with appendix F of
part 60 of this chapter for each continuous emission monitoring system,
including calibration checks and relative accuracy test audits;
(viii) For owners or operators using continuous monitoring systems
or continuous emission monitoring systems to demonstrate compliance,
records for such systems as required by Sec. 63.10(c) of this part;
(ix) Records of any changes to a regulated process, including a
record of any changes in the location at which the vent stream is
introduced into the flame zone for a boiler or process heater;
(x) Where a bypass line is equipped with a flow indicator, records
of each hourly inspection demonstrating whether the flow indicator was
operating properly and whether gas or vapor flow was detected or where
a bypass line is secured with a car-seal or a lock-and-key type device,
records of each monthly inspection demonstrating that the bypass line
valve is maintained in the closed position and whether gas or vapor
flow was detected; and for all bypass line valves, records of the times
and durations of all periods when the vent stream is diverted through a
bypass line;
(xi) Records of hourly inspections of flare pilot flame; and
(xii) For each catalytic cracking unit catalytic regenerator
subject to the PM emission standard in Sec. 63.1562(a)(1)(i) of this
subpart, records of the daily average coke burn-off rate, the hours of
operation for each unit, and process data used to determine the
volumetric flow rate of exhaust gas.
Sec. 63.1568 Applicability of general provisions.
The requirements of the general provisions in subpart A of this
part that are applicable to the owner or operator subject to the
requirements of this subpart are shown in appendix A to this subpart.
Sec. 63.1569 Delegation of authority.
In delegating implementation and enforcement authority to a State
under section 112(l) of the Act, all authorities are transferred to the
State.
Sec. 63.1570-63.1579 [Reserved]
Appendix A to Subpart UUU to Part 63--Applicability of General
Provisions (40 CFR Part 63, Subpart A) to Subpart UUU
[[Page 48922]]
----------------------------------------------------------------------------------------------------------------
Citation Applies to subpart UUU Comment
----------------------------------------------------------------------------------------------------------------
63.1(a)(1)-63.1(a)(3)............... Yes..................... General Applicability.
63.1(a)(4).......................... No...................... This table specifies applicability of General
Provisions to Subpart UUU.
63.1(a)(5).......................... No...................... [Reserved].
63.1(a)(6)-63.1(a)(8)............... No.
63.1(a)(9).......................... No...................... [Reserved].
63.1(a)(10)......................... No...................... Subpart UUU specifies calendar or operating day.
63.1(a)(11)-63.1(a)(14)............. Yes.
63.1(b)(1).......................... No...................... Initial Applicability Determination Subpart UUU
specifies applicability.
63.1(b)(2).......................... Yes.
63.1(b)(3).......................... No.
63.1(c)(1).......................... No...................... Subpart UUU specifies requirements.
63.1(c)(2).......................... No...................... Area sources are not subject to subpart UU.
63.1(c)(3).......................... No...................... [Reserved].
63.1(c)(4).......................... Yes.
63.1(c)(5).......................... Yes..................... Except that notification requirements in subpart
UUU apply.
63.1(d)............................. No...................... [Reserved].
63.1(e)............................. Yes..................... Applicability of Permit Program.
63.2................................ Yes..................... Definitions Sec. 63.1561 specifies that if the
same term is defined in Subparts A and UUU, it
shall have the meaning given in Subpart UUU.
63.3................................ Yes..................... Units and Abbreviations.
63.4(a)(1)-63.4(a)(4)............... Yes..................... [Reserved].
63.4(a)(5).......................... Yes.
63.4(b)-63.4(c)..................... Yes..................... Circumvention/Severability.
63.5(a)(1).......................... Yes..................... Construction and Reconstruction--Applicability
Replace term ``source'' and ``stationary
source'' in Sec. 63.5(a)(1) with ``affected
source''.
63.5(a)(2).......................... Yes.
63.5(b)(1).......................... Yes..................... Existing, New, Reconstructed Sources--
Requirements.
63.5(b)(2).......................... No...................... [Reserved].
63.5(b)(3).......................... Yes.
63.5(b)(4).......................... Yes..................... Replace the reference to Sec. 63.9 with Sec.
63.9(b)(4) and (b)(5).
63.5(b)(5)-(6)...................... Yes.
63.5(c)............................. No...................... [Reserved].
63.5(d)(1)(i)....................... Yes..................... Application for Approval of Construction or
Reconstruction Except Subpart UUU specifies the
application is submitted as soon as practicable
before startup but no later than 90 days
(rather than 60) after the promulgation date
where 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 Sec.
63.5(d)(1)(ii)(H) are not required.
63.5(d)(1)(iii)..................... No...................... Sec. 63.1567(b) specifies submission of
notification of compliance status report.
63.5(d)(2).......................... No.
63.5(d)(3).......................... Yes..................... Except Sec. 63.5(d)(3)(ii) does not apply.
63.5(d)(4).......................... Yes.
63.5(e)............................. Yes..................... Approval of Construction or Reconstruction.
63.5(f)(1).......................... Yes..................... Approval of Construction or Reconstruction Based
on State Review.
63.5(f)(2).......................... Yes..................... Except that 60 days is changed to 90 days and
cross-reference to (b)(2) does not apply.
63.6(a)............................. Yes..................... Compliance with Standards and Maintenance--
Applicability.
63.6(b)(1).......................... No...................... New and Reconstructed Sources--Dates Subpart UUU
specifies compliance dates.
63.6(b)(2).......................... No.
63.6(b)(3).......................... Yes.
63.6(b)(4).......................... No...................... May apply to standards under section 112(f).
63.6(b)(5).......................... No...................... Subpart UUU specifies notification requirements.
63.6(b)(6).......................... No...................... [Reserved].
63.6(b)(7).......................... No.
63.6(c)(1).......................... No...................... Existing Sources--Dates Subpart UUU specifies
compliance dates.
63.6(c)(2)-63.6(c)(3)............... No.
63.6(c)(4).......................... No...................... [Reserved].
63.6(c)(5).......................... Yes.
63.6(d)............................. No...................... [Reserved].
63.6(e)(1)-(2)...................... Yes..................... Operation and Maintenance Requirements.
63.6(e)(3)(i)-(ii).................. Yes..................... Startup, Shutdown, and Malfunction Plan.
63.6(e)(3)(iii)..................... Yes.
63.6(e)(3)(iv)...................... Yes..................... Except that reports of actions not consistent
with plan are not required within 2 and 7 days
of action but rather must be included in next
periodic report.
63.6(e)(3)(v)-(viii)................ Yes.
63.6(f)(1).......................... Yes..................... Compliance with Emission Standards.
63.6(f)(2)(i)....................... Yes.
63.6(f)(2)(ii)...................... Yes..................... Subpart UUU specifies use of monitoring data in
determining compliance.
63.6(f)(2)(iii)(A)-63.6(f)(2)(iii)(C Yes.
).
63.6(f)(2)(iii)(D).................. No.
63.6(f)(2)(iv)-(v).................. Yes.
63.6(f)(3).......................... Yes.
63.6(g)............................. Yes..................... Alternative Standard.
[[Page 48923]]
63.6(h)............................. No...................... Compliance with Opacity/VE Standards Subpart UUU
does not include opacity/VE standards.
63.6(i)(1)-63.6(i)(14).............. Yes..................... Extension of Compliance.
63.6(i)(15)......................... No...................... [Reserved].
63.6(i)(16)......................... Yes.
63.6(j)............................. Yes..................... Exemption from Compliance.
63.7(a)(1).......................... No...................... Performance Test Requirements--Applicability and
Dates Subpart UUU specifies the applicable test
and demonstration procedures.
63.7(a)(2).......................... No...................... Test results must be submitted in the
notification of compliance status report due
150 days after the compliance date.
63.7(a)(3).......................... Yes.
63.7(b)............................. Yes..................... Notifications Except Subpart UUU specifies
notification at least 30 days prior to the
scheduled test date rather than 60 days.
63.7(c)............................. Yes..................... Quality Assurance/Test Plan Sec. 63.1564(b)(2)
requires a Q/A plan for CO continuous emission
monitoring systems.
63.7(d)............................. Yes..................... Testing Facilities.
63.7(e)(1).......................... Yes..................... Conduct of Tests.
63.7(e)(2)-63.7(e)(3)............... No...................... Subpart UUU specifies the applicable methods and
procedures.
63.7(e)(4).......................... Yes.
63.7(f)............................. No...................... Alternative Test Method Subpart UUU specifies
the applicable methods and provides
alternatives.
63.7(g)............................. No...................... Data Analysis, Recordkeeping, Reporting Subpart
UUU specifies performance test reports and
requires additional records for continuous
emission monitoring systems.
63.7(h)(1).......................... Yes..................... Waiver of Tests.
63.7(h)(3)-63.7(h)(4)............... No.
63.7(h)(5).......................... Yes.
63.8(a)............................. No...................... Monitoring Requirements Applicability.
63.8(b)(1).......................... Yes..................... Conduct of Monitoring.
63.8(b)(2).......................... No...................... Subpart UUU specifies the required monitoring
locations.
63.8(b)(3).......................... Yes.
63.8(c)(1)(i)....................... Yes..................... CMS Operation and Maintenance.
63.8(c)(1)(ii)...................... No...................... Addressed by periodic reports in Sec.
63.1567(b) of Subpart UUU.
63.8(c)(1)(iii)..................... Yes.
63.8(c)(2).......................... Yes.
63.8(c)(3).......................... Yes..................... Except that 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).......................... No...................... Monitoring frequency is specified in Sec.
63.1565 of Subpart UUU.
63.8(c)(5).......................... No.
63.8(c)(8)-63.8(d).................. Yes..................... Quality Control.
63.8(e)............................. Yes..................... CMS Performance Evaluation May be required by
Administrator.
63.8(f)(1).......................... Yes..................... Alternative Monitoring Method.
63.8(f)(2).......................... Yes.
63.8(f)(3).......................... Yes.
63.8(f)(4)(i)....................... No...................... Sec. 63.1565(f) specifies procedure.
63.8(f)(4)(ii)...................... Yes.
63.8(f)(4)(iii)..................... No.
63.8(f)(5)(i)....................... Yes.
63.8(f)(5)(ii)...................... No.
63.8(f)(5)(iii)..................... Yes.
63.8(f)(6).......................... Yes..................... Applicable to CO continuous emission monitoring
system.
63.8(g)............................. Yes..................... Data Reduction Applicable to CO continuous
emission monitoring system; Subpart UUU
specifies data reduction for CMS.
63.9(a)............................. Yes..................... Notification Requirements--Applicability
Duplicate notification of compliance status
report to RA may be required.
63.9(b)(1)(i)....................... Yes..................... Initial Notifications.
63.9(b)(1)(ii)...................... Yes.
63.9(b)(1)(iii)..................... Yes.
63.9(b)(2).......................... Yes.
63.9(b)(3).......................... Yes.
63.9(b)(4).......................... Yes..................... Except that notification is to be submitted
within 150 days as part of the compliance
status report.
63.9(b)(5).......................... Yes..................... Except that notification is to be submitted
within 150 days as part of the compliance
status report.
63.9(c)............................. Yes..................... Request for Compliance Extension.
63.9(d)............................. Yes..................... New Source Notification for Special Compliance
Requirements.
63.9(e)............................. Yes..................... Except notification is required at least 30 days
before test.
63.9(f)............................. Yes..................... Notification of VE/Opacity Test.
63.9(g)............................. No.
63.9(h)............................. No...................... Notification of Compliance Status Sec. 63.1567
specifies the applicable requirements.
63.9(i)............................. Yes..................... Adjustment of Deadlines.
[[Page 48924]]
63.9(j)............................. No...................... Change in Previous Information.
63.10(a)............................ Yes..................... Recordkeeping/Reporting--Applicability.
63.10(b)(1)......................... No...................... General Requirements Subpart UUU specifies
applicable record retention requirements.
63.10(b)(2)(i)-(xiv)................ Yes.
63.10(b)(3)......................... No.
63.10(c)............................ Yes..................... Additional CMS Recordkeeping.
63.10(d)(1)......................... No...................... General Reporting Requirements.
63.10(d)(2)......................... No...................... Performance Test Results Sec. 63.1567 specifies
performance test reporting requirements.
63.10(d)(3)......................... Yes..................... Opacity or VE Observations.
63.10(d)(4)......................... Yes..................... Progress Reports.
63.10(d)(5)(i)...................... Yes..................... Startup, Shutdown, and Malfunction Reports.
Except that reports are not required if actions
are consistent with SSM plan, unless requested
by permitting authority.
63.10(d)(5)(ii)..................... Yes..................... Except that reports of actions not consistent
with the plan are not required within 2 and 7
days of action but must be included in next
periodic report.
63.10(e)(1)......................... Yes..................... Additional CMS Reports.
63.10(e)(2)......................... No.
63.10(e)(3)......................... No...................... Excess Emissions/CMS Performance Reports Subpart
UUU specifies the applicable requirements.
63.10(e)(4)......................... No...................... COMS Data Reports.
63.10(f)............................ Yes..................... Recordkeeping/Reporting Waiver.
63.11............................... Yes..................... Control Device Requirements Applicable to
flares.
63.12............................... Yes..................... State Authority and Delegations.
63.13............................... Yes..................... Addresses.
63.14............................... No...................... Incorporation by Reference.
63.15............................... Yes..................... Availability of Information/Confidentiality.
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[FR Doc. 98-23508 Filed 9-10-98; 8:45 am]
BILLING CODE 6560-50-P