National Emission Standards for Hazardous Air Pollutants for Source Categories; National Emission Standards for Hazardous Air Pollutants from Petroleum RefineriesCatalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant Units

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

------------------------------------------------------------------------

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

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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

[[Page 48892]]

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.

[[Page 48893]]

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

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