**Bay Area Air Quality Management District**

939 Ellis Street

San Francisco, CA 94109

\(415\) 771-6000

**Draft**

**Permit Evaluation**

**and**

**Statement of Basis**

**for**

**Major Facility Review Permit**

**Reopening -- Revision 1**

**for**

**Valero Refining Co. - California**

**Facility #B2626**

**Facility Address:**

3400 East Second Street

Benicia, CA 94510-1097

**Mailing Address:**

3400 East Second Street

Benicia, CA 94510-1097

February, 2004

TABLE OF CONTENTS

[A. Background 3](#background)

[B. Facility Description 4](#facility-description)

[C. Permit Content 6](#permit-content)

[I. Standard Conditions 6](#i.-standard-conditions)

[II. Equipment 6](#ii.-equipment)

[III. Generally Applicable Requirements
7](#iii.-generally-applicable-requirements)

[IV. Source-Specific Applicable Requirements
8](#iv.-source-specific-applicable-requirements)

[V. Schedule of Compliance 20](#v.-schedule-of-compliance)

[VI. Permit Conditions 21](#vi.-permit-conditions)

[[VII.]{.smallcaps} Applicable Limits and Compliance Monitoring
Requirements
22](#vii.-applicable-limits-and-compliance-monitoring-requirements)

[VIII. Test Methods 23](#viii.-test-methods)

[IX. Permit Shield 23](#ix.-permit-shield)

[D. Alternate Operating Scenarios:
24](#d.-alternate-operating-scenarios)

[E. Compliance Status: 24](#e.-compliance-status)

[F. Permit Updates and Changes since the Final December 1, 2003 Permit
25](#f.-permit-updates-and-changes-since-the-final-december-1-2003-permit)

Title V Statement of Basis

# Background

This facility is subject to the Operating Permit requirements of Title V
of the federal Clean Air Act, Part 70 of Volume 40 of the Code of
Federal Regulations (CFR), and BAAQMD Regulation 2, Rule 6, Major
Facility Review because it is a major facility as defined by BAAQMD
Regulation 2-6-212. It is a major facility because it has the "potential
to emit," as defined by BAAQMD Regulation 2-6-218, of more than 100 tons
per year of a regulated air pollutant.

Major Facility Operating permits (Title V permits) must meet
specifications contained in 40 CFR Part 70 as contained in BAAQMD
Regulation 2, Rule 6. The permits must contain all applicable
requirements (as defined in BAAQMD Regulation 2-6-202), monitoring
requirements, recordkeeping requirements, and reporting requirements.
The permit holders must submit reports of all monitoring at least every
six months and compliance certifications at least every year.

In the Bay Area, state and District requirements are also applicable
requirements and are included in the permit. These requirements can be
federally enforceable or non-federally enforceable. All applicable
requirements are contained in Sections I through VI of the permit.

The District issued the initial Title V permit to this facility on
December 1, 2003. The District has reopened the permit to amend flare
and Regulation 9-10 requirements, to correct errors, and to incorporate
some new conditions contained in recently issued Authorities to
Construct. All changes to the permit will be clearly shown in
\"strikeout/underline\" format. When the permit is finalized, the
\"strikeout/underline\" format will be removed.

The District is soliciting public comment on the proposed revisions. The
District is also soliciting comment on changes that were made between
the version of the permits that were issued for public comment in July
of 2003 and the final permits issued December 1, 2003. Though the
District does not believe these changes were of such a magnitude as to
render the issuance notice and comment process inadequate, these permits
were the subject of considerable scrutiny, and so the District wishes to
be as thorough as possible in allowing an opportunity for comment on all
aspects of the final permits. The District will respond to comments
received on these changes from draft to final. Any changes to the permit
that result from comments received will be addressed in a future
revision.

Regarding EPA\'s review of the final permits, EPA has indicated to the
District that, because of the extent of changes made between proposal
and final, it intends to conduct a new review of the refinery permits in
their entirety. The District acknowledges that EPA has this authority
and intends to respond appropriately to any issues EPA may raise in its
review, whether or not those issues relate to the proposed revisions.
EPA has informed the District that it intends to commence a 45-day
review period on the entire content of each refinery Title V permit when
it receives the version of the permit that is proposed for revision.

This statement of basis concerns only changes to the permit. A
comprehensive statement of basis was prepared for the initial issuance
of the permit and is considered to be the statement for basis for the
entire permit. It is available on request.

There is no significant increase in facility emissions due to the
revisions in this permit. The majority of the changes are corrections
and clarifications. Details of the significant (i.e. more than just
typos or extraneous text changes) permit changes are listed in Section G
of this document. The two major permit conditions that were added (Flare
and NOx Box, covered in more detail in Section C.IV), cover details of
source monitoring and do not, in themselves, result in any change in
emissions. The new District permit applications incorporated into the
permit since the December 1, 2003 permit are shown below:

  -------------------------- --------------------------------------------
  Application Number(s)      Description

  2035                       MTBE Phaseout

  3782                       Alkylation Expansion

  8028 and 8247              Spare Tail Gas Unit for Sulfur Plants
  -------------------------- --------------------------------------------

The spare tail gas unit A-64 is an identical backup for the existing
A-24 and normally only one unit will be operating at a time. There will
be short periods when both units are simultaneously operated when
switching units. Assuming this will occur no more than 5 times per year,
it is estimated that the emissions will increase as follows: POC,
0.00032 ton/yr; NOx, 0.006 ton/yr; SO2, 0.000036 ton/yr; PM10, 0.004
ton/yr; and CO, 0.005 ton/yr. For the remaining two applications, the
total POC emissions increase 0.745 tons/yr. These emissions were offset
as required by Regulation 2-2-302.

# Facility Description 

General Description of an Oil Refinery:

An oil refinery is an intermediary between crude oil and a refined
product. It takes dirty, low- value oil from the ground and distills it
under atmospheric pressure into its primary components: gases (light
ends), gasolines, kerosene and diesels (middle distillates), heavy
distillates, and heavy bottoms. The heavy bottoms go on to a vacuum
distillation unit to be distilled again, this time under a vacuum, to
salvage any light ends or middle distillates that did not get separated
under atmospheric pressure; the heaviest bottoms continue on to a coker
or an asphalt plant.

Other product components are processed by downstream units to be cleaned
(hydrotreated), cracked (catalytic or hydrocracking), reformed
(catalytic reforming), or alkylated (alkylation) to form gasolines and
high-octane blending components, or to have sulfur or other impurities
removed to make over-the-road diesel (low sulfur) or off-road diesel
(higher sulfur). Depending on the process units in a refinery and the
crude oil input, an oil refinery can produce a wide range of salable
products: many different grades of gasoline and gasoline blend stocks,
several grades of diesel, kerosene, jet and aviation fuel, fuel oil,
bunker fuels, waxes, solvents, sulfur, coke, asphalt, or chemical plant
feedstocks.

A more detailed description of petroleum refinery processes and the
resulting air emissions may be found in Chapter 5 of EPA's publication
AP-42, [Compilation of Air Pollutant Emission Factors]{.underline}. This
document may be found at:

> http://www.epa.gov/ttn/chief/ap42/ch05/

The principal sources of air emissions from refineries are:

-   Combustion units (furnaces, boilers, and cogeneration facilities)

-   FCC (Fluidized Catalytic Cracking)

-   Storage tanks

-   Fugitive emissions from pipe fittings, pumps, and compressors

-   Sulfur plants

-   Wastewater treatment facilities

#  {#section .unnumbered}

Combustion unit emissions are generally controlled through the use of
burner technology, steam injection, or selective catalytic reduction.
Emissions from the FCCU are controlled through the use of improved
catalyst regeneration, CO boilers, electrostatic precipitators,
hydrotreating the feed, and use of catalysts to remove impurities.
Storage tank emissions are controlled through the use of add on control
and or fitting loss control. Fugitive emissions have been controlled
through the use of inspection and maintenance frequencies. Sulfur plants
are equipped with tail gas units to reduce emissions. Wastewater
treatment facilities are controlled by covering units, gasketing covers,
and add on controls such as, carbon canisters.

**Valero Refining -- Benicia Fast Facts**\
\-- Produces 10 percent of the clean-burning California Air Resources
Board (CARB) gasoline used in California and 25 percent of the CARB used
in the San Francisco Bay Area.\
\
\-- Total feedstock throughput capacity of 180,000 barrels per day
(BPD)\
\
\-- Products include CARB gasoline, diesel, jet fuel, fuel oil, residual
oil and asphalt\
\
**Overview**\
Built as a grass-roots project in 1969, the Benicia refinery has
undergone significant modifications and upgrades over the years. Valero
acquired the facility in 2000.\
\
\
**Output**\
This facility has the ability to process sour crude oils into a high
percentage of light products. Approximately 70 percent of the refinery's
product slate is CARB gasoline -- California's clean-burning fuel. The
refinery also has significant asphalt production capabilities and
produces 25 percent of the asphalt supply in northern California.
Currently, it processes domestic crude both from the San Joaquin Valley
(SJV) in California and from the Alaska North Slope (ANS). Major
refinery units include:\
\-- 135,000-BPD crude distillation unit\
\-- 77,000-BPD fluid catalytic cracking (FCC) unit\
\-- 39,500-BPD coker unit\
\-- 40,000-BPD hydrocracker\
\-- 40,000-BPD catalytic reformer

# Permit Content

The legal and factual basis for the permit follows. The permit sections
are described in the order presented in the permit.

## I. Standard Conditions  {#i.-standard-conditions .unnumbered}

This section contains administrative requirements and conditions that
apply to all facilities. If the Title IV (Acid Rain) requirements for
certain fossil-fuel fired electrical generating facilities or the
accidental release (40 CFR § 68) programs apply, the section will
contain a standard condition pertaining to these programs. Many of these
conditions derive from 40 CFR § 70.6, Permit Content, which dictates
certain standard conditions that must be placed in the permit. The
language that the District has developed for many of these requirements
has been adopted into the BAAQMD Manual of Procedures, Volume II, Part
3, Section 4, and therefore must appear in the permit.

The standard conditions also contain references to BAAQMD Regulation 1
and Regulation 2. These are the District's General Provisions and
Permitting rules.

Condition I.J has been added to clarify that the capacity limits shown
in Table II-A are enforceable limits.

## II. Equipment  {#ii.-equipment .unnumbered}

This section of the permit lists all permitted or significant sources.
Each source is identified by an S and a number (e.g., S24 or S-24).

Permitted sources are those sources that require a BAAQMD operating
permit pursuant to BAAQMD Rule 2-1-302. The Permitted sources are shown
in the Permit Table II A.

The exempt sources may or may not have a source number. The exempt
sources are shown in the Permit Table II B.

Significant sources are those sources that have a potential to emit of
more than 2 tons of a "regulated air pollutant," as defined in BAAQMD
Rule 2-6-222, per year or 400 pounds of a "hazardous air pollutant," as
defined in BAAQMD Rule 2-6-210, per year.

All abatement (control) devices that control permitted or significant
sources are listed. Each abatement device whose primary function is to
reduce emissions is identified by an A and a number (e.g., A24 or A-24).
This abatement equipment is shown in the Permit Table II C. If a source
is also an abatement device, such as when an engine controls VOC
emissions, it will be listed in the abatement device table but will have
an "S" number. An abatement device may also be a source (such as a
thermal oxidizer that burns fuel) of secondary emissions. If the primary
function of a device is to control emissions, it is considered an
abatement (or "A") device. If the primary function of a device is a
non-control function, the device is considered to be a source (or "S").

The equipment section is considered to be part of the facility
description. It contains information that is necessary for applicability
determinations, such as fuel types, contents or sizes of tanks, etc.
This information is part of the factual basis of the permit.

Each of the permitted sources has previously been issued a permit to
operate pursuant to the requirements of BAAQMD Regulation 2, Permits.
These permits are issued in accordance with state law and the District's
regulations. The capacities in the permitted sources table are the
maximum allowable capacities for each source, pursuant to Standard
Condition I.J and Regulation 2-1-403.

There are no equipment differences between the Final Permit issued
December 1, 2003 and this version. There are some minor discrepancies
that were corrected. These include:

-   S-211 was reinstated in the Permitted Sources Table II A. This
    source was originally the MTBE Plant that was taken out of service
    in 2003. However, the main unit tower is now used as an Alkylate
    Debutanizer so S-211 was returned to Table II A to cover this
    source.

-   The Claus Units abatement system was corrected in Table II C. This
    system consists of A-24, The Tail Gas Hydrogenation Unit, followed
    by A-56, the Flexsorb Process. Applications 8028 and 8427 for a
    spare tail gas unit were granted a Permit to Operate in late 2003.
    This spare unit was designated A-62 in error (A-62 is already the
    SCR unit of S-1032 and S-1033). Therefore, a correction was made to
    show A-64, the Spare Tail Gas Hydrogenation Unit.

The District permit applications not included in this proposed permit
are as follows:

-   Application 5846: Valero Improvement Project. This Application was
    granted an Authority to Construct in July 2003.

## III. Generally Applicable Requirements  {#iii.-generally-applicable-requirements .unnumbered}

This section of the permit lists requirements that generally apply to
all sources at a facility including insignificant sources and portable
equipment that may not require a District permit. If a generally
applicable requirement applies specifically to a source that is
permitted or significant, the standard will also appear in Section IV
and the monitoring for that requirement will appear in Sections IV and
VII of the permit. Parts of this section apply to all facilities (e.g.,
particulate, architectural coating, odorous substance, and sandblasting
standards). In addition, standards that apply to insignificant or
unpermitted sources at a facility (e.g., refrigeration units that use
more than 50 pounds of an ozone-depleting compound) are placed in this
section.

Unpermitted sources are exempt from normal District permits pursuant to
an exemption in BAAQMD Regulation 2, Rule 1. They may, however, be
specifically described in a Title V permit if they are considered
significant sources pursuant to the definition in BAAQMD Rule 2-6-239.

## IV. Source-Specific Applicable Requirements {#iv.-source-specific-applicable-requirements .unnumbered}

### General Information {#general-information .unnumbered}

This section of the permit lists the applicable requirements that apply
to permitted or significant sources. These applicable requirements are
contained in tables that pertain to one or more sources that have the
same requirements. The order of the requirements is:

-   District Rules

-   SIP Rules (if any) are listed following the corresponding District
    rules. SIP rules are District rules that have been approved by EPA
    for inclusion in the California State Implementation Plan. SIP rules
    are "federally enforceable" and a "Y" (yes) indication will appear
    in the "Federally Enforceable" column. If the SIP rule is the
    current District rule, separate citation of the SIP rule is not
    necessary and the "Federally Enforceable" column will have a "Y" for
    "yes". If the SIP rule is not the current District rule, the SIP
    rule or the necessary portion of the SIP rule is cited separately
    after the District rule. The SIP portion will be federally
    enforceable; the non-SIP version will not be federally enforceable,
    unless EPA has approved it through another program.

-   Other District requirements, such as the Manual of Procedures, as
    appropriate.

-   Federal requirements (other than SIP provisions)

-   BAAQMD permit conditions. The text of BAAQMD permit conditions is
    found in Section VI of the permit.

-   Federal permit conditions. The text of Federal permit conditions, if
    any, is found in Section VI of the permit.

Section IV of the permit contains citations to all of the applicable
requirements. The text of the requirements is found in the regulations,
which are readily available on the District's or EPA's websites, or in
the permit conditions, which are found in Section VI of the permit. All
monitoring requirements are cited in Section IV. Section VII is a
cross-reference between the limits and monitoring requirements. A
discussion of monitoring is included in Section C.VII of this permit
evaluation/statement of basis. At the top of each set of permit
conditions applicable to a source(s) in Table IV, Valero has also
included a unique environmental file number, shown as either 8.1.XXX or
8.2.XXX. Valero\'s environmental file number cross-references the
District\'s Condition ID# for these same permit conditions, in order to
track and facilitate compliance.

### Complex Permit Issues and Applicability Determinations {#complex-permit-issues-and-applicability-determinations .unnumbered}

#### Combustion Sources Under Alternative Compliance Plan: {#combustion-sources-under-alternative-compliance-plan .unnumbered}

[Sources S-7, S-20, S-21, S-22, S-23, S-24, S-25, S-26, S-30 through
S-33, S-34, S-35,]{.underline}

[S-40, S-41, S-173 and S-220]{.underline}

The above listed sources are combustion sources that are subject to
Regulation 9, Rule 10, because they are located at a refinery and have a
rated heat input that is more than 10 MMBTU/hr. Regulation 9 Rule 10
limits nitrogen oxide (NOx) and carbon monoxide (CO) emissions from
boilers, steam generators and process heaters at refineries. Effective
July 1, 2002, refineries became subject to the emission standard of
0.033 pounds of NOx per million BTU of heat input, averaged over all
affected units each day. This NOx standard is contained in Section
9-10-301. This is the primary standard in this rule. Section 9-10-305
limits CO emissions to 400 ppmv (dry, 3% O~2~). Because of the inverse
relationship between NOx and CO emissions, this CO limit is included in
the rule to ensure that CO emissions do not significantly increase
because of NOx control efforts. Section 9-10-304 contains a separate NOx
limit for CO Boilers of 150 ppm (dry, 3% O~2~), or an abatement system
with an efficiency of at least 50%.

Prior to the effective date of Regulation 9, Rule 10, each refinery was
required to submit a *Control Plan* and a *Monitoring Plan* outlining
how the refinery would comply with Regulation 9, Rule 10. The Control
Plan includes: a list of all affected units, a description of the NOx
control system for each affected unit, the projected NOx emission rate
for each unit, and an implementation schedule for the installation of
additional control equipment. The Monitoring Plan includes: a list of
sources to be equipped with NOx, CO and oxygen continuous emission
monitors (CEMs), a list of sources for which an equivalent verification
system would be used, and a description of fuel flow meters for each
source or group of sources.

Compliance with Regulation 9, Rule 10 is determined daily. The
owner/operator uses a combination of CEM data, unit-specific NOx
emissions factors, fuel usage and fuel heat content data to calculate
the daily average NOx emissions per unit of heat input (lb NOx / million
BTU) for the affected sources. Compliance with the CO Boiler NOx
concentration limit is determined directly by CEM. Compliance with the
CO concentration limit is determined by either CEM or periodic source
tests.

Not all sources are monitoring by CEMs. In general, emissions from large
units are measured with CEMs and emissions from small units may be
determined using an equivalent verification system. The District
determines equivalency for this purpose on a case-by-case basis, guided
by the District policy entitled "*NOx, CO and O~2~ Monitoring Compliance
with Regulation 9, Rule 10"*, signed by Bill De Boisblanc, June 23,
2000, and amended April 10, 2003. This policy states that in lieu of
CEMs, the owner/operator may establish a pre-defined operating range
(often referred to the "NOx Box", which is address below), for smaller
sources (less than 200 MMBtu/hr rating), based on a series of source
tests. Emissions for such sources are calculated based on
source-specific emission factors and measured fuel usage. The
pre-defined operating ranges are specified in BAAQMD Permit Condition \#
21233.

The owner/operator is required to retain records of data necessary to
determine compliance for a period of at least five years, and to submit
written quarterly reports to the District.

This refinery also uses Interchangeable Emission Reductions Credits
(IERCs) as a means of complying with the refinery-wide average NOx limit
in Section 9-10-301. The daily average NOx emission rate (lb NOx/million
BTU) is determined as described above. If this emission rate exceeds the
limit of 0.033 lb/million BTU, the refinery must use sufficient IERCs to
offset the difference between the actual emission rate and the
Regulation 9, Rule 10 limit, plus ten percent of the difference. IERCs
are generated in accordance with Regulation 2, Rule 9, by early
compliance or over-compliance with an emission standard. IERCs must be
formally banked prior to use, and can only be used as part of an
Alternative Compliance Plan (ACP) approved

under Regulation 2-9. At the end of each ACP year, the refinery
surrenders the IERC banking certificates sufficient to cover the IERCs
that were consumed during the prior ACP period.

In the case of Valero Refinery, Sources at Facility B3193 (S19, S20,
S21) are considered together with the sources that are subject to
Regulation 9-10-301 at Facility B2626, Valero Refining. Valero intends
to comply with Regulation 9-10-301 by using IERCs that the facility
generates by over-controlling its CO Boilers. Valero applied for these
IERCs in Application 3915. The evaluation for Application 3915 is
attached in Appendix A. Condition 19329 concerning the IERCs has been
added to the Section IV and VII tables. Valero has continued to apply
for additional IERC's as the credits are generated.

#### NOx Box {#nox-box .unnumbered}

The following discussion explains changes to refinery permit conditions
prescribing monitoring for compliance with Regulation 9-10 at units for
which CEMs are not required, commonly known as the "NOx Box" permit
conditions. To facilitate the reader's understanding of the proposed
changes, this discussion provides background on the 9-10 rule and
CEM-equivalency monitoring provided for therein.

Regulation 9-10 requires each refinery to reduce NOx emissions from
boilers and heaters. All of the boilers and heaters at each refinery
above 10 MMBTU that were in existence on January 5, 1994 are included in
determination of compliance with a facility-wide average emission rate
of 0.033 lb/MMBtu. BAAQMD 9-10-301.

In order to demonstrate compliance, each affected heater must be
equipped with a NOx CEM, or equivalent verification system (BAAQMD
9-10-502). Where combustion processes are sufficiently static over time,
emissions factors combined with MmBtu data can be used to verify
compliance with accuracy equivalent to that of CEMs. An emissions factor
approach can be deemed equivalent if the integrity of the emissions
factors can be assured. The NOx Box approach does this by: 1) verifying
emissions factor accuracy through source-testing, 2) defining the
parameters of operation within which emissions factors have been proven,
and 3) requiring that any excursions outside of those parameters be the
subject of a new source test.

Source tests to establish the NOx Box are conducted at extreme operating
conditions (the "corners" of the NOx Box). As long as the facility
operates within the perimeter defined by these source tests, emissions
are assumed to be equal to the highest emission rate tested. By
monitoring firing rate and O2 in the exhaust, the validity of using the
emission factor is reasonably assured. Periodic source tests confirm
that the emission factor is still valid for the operating range.
Operation outside the box results in scrutiny to determine compliance
with the emission standard, including conduct of a test at the unproven
conditions.

That the NOx Box approach is consistent with the intent of Regulation
9-10 is evidenced in the District Staff Report for that rule, which
stated:

> "District staff recommends that CEMS be only required on units
> equipped with SCR and SNCR due to high capital and maintenance costs.
> NOx can vary significantly for SCR and SNCR units based on temperature
> and amount of ammonia injected. On the contrary, NOx from non-SCR and
> SNCR units equipped with FGR and low NOx burners and are relatively
> stable and CEMS should not be necessary for these units."

Rule Development Staff Report, Regulation 9, Rule 10, November 19, 1993,
p. 7.

##### Federal Enforceability {#federal-enforceability .unnumbered}

9-10-301 and 9-10-502 are not included in the SIP, and are therefore not
federally enforceable. Revisions to the NOx Box Condition in the Title V
permit may be made by Administrative Amendment.. BAAQMD 2-6-201.

##### Changes from the current conditions {#changes-from-the-current-conditions .unnumbered}

The current Title V refinery permits contain NOx Box conditions based on
an earlier District policy for demonstrating verification system
equivalence. Experience with implementation of these conditions has
allowed the District to identify certain areas for improvement. One
problem with the current set of conditions is that it allows sustained
operation at conditions that have never been tested for compliance with
the NOx Box emission factor.

The proposed condition addresses this problem, and several others that
have been raised by EPA, the facilities, and the public.

The changes can be summarized as follows:

-   The old policy allowed for operation at conditions outside the
    perimeter of test conditions. The reason for this was to account for
    the fact that requiring the facility to test the furnace at specific
    conditions could have an expensive impact on production. While this
    is still true, there was also considerable opportunity for
    circumvention, where a facility could have sustained operation
    outside the box, and then test at conditions that happened to be
    well within the box. The new policy requires that a test be
    conducted that would capture the new conditions. The impact on
    process operation is mitigated by allowing the facility to delay
    testing until the next periodic source test.

-   The old policy used one emission factor for all allowable operating
    conditions. The new policy allows two boxes, with two factors. One
    lower factor applies to routine operating conditions, while another
    higher factor may be used for normal operation at higher levels.
    This provides more flexibility without sacrificing the assurance of
    compliance.

-   The NOx box can be a 5-sided polygon, rather than a simple box.

-   Because the policy is, in some ways, more stringent, time to conduct
    the source tests to establish the new boxes has been allowed.
    Existing NOx Box conditions will remain in effect until June 1,
    2004, when they will be replaced by the new conditions.

-   Under the old policy, two Notices of Violations (NOVs) issued
    because of a single source would automatically trigger a requirement
    to install a NOx CEM. Under the new policy, two NOVs will trigger a
    review by District staff to determine if the NOx Box for that source
    is still deemed equivalent to a NOx CEM. If it is not, a NOx CEM
    will be required.

-   The new policy allows a facility to operate at low firing rates
    (idling) for a limited period of time, without having to expand the
    box to include those conditions. There are two reasons for this.
    First, emissions at low fire are much lower than normal, even if the
    emission factor is higher. Second, it is an extreme hardship to
    require the facility to turn down its production in order to test at
    very low fire conditions.

The following summarizes the various parts of the proposed NOx Box
conditions:

**Part 1** of the condition lists all of the combustion devices subject
to 9-10-301.

**Part 2** requires installation of oxygen monitors. This is necessary
because some of the smaller heaters are not required by Regulation 9-10
to have oxygen monitors. Oxygen content must be monitored continuously
to demonstrate compliance with the condition. Operators will be allowed
six months to install any newly-required oxygen monitors.

**Part 3** requires operation of each combustion device within the box.
Failure to operate within the box is a violation of this condition,
unless excused by one of the deviation procedures in Part 7.

Part 3B covers small units (\<25MMBtu/hr). The NOx Box for small units
is essentially the entire potential operating range for the unit. Rather
than establishing the "corners" of the box, the box is defined to be the
full range of firing rates, and all possible oxygen contents. Existing
data may be used to establish the emission factor that will be applied.
Unless the unit is fired above its rated capacity, it is not possible to
operate outside the box. An annual source test will confirm that the
factor used is still valid.

**Part 4** requires the operators to conduct the source tests necessary
to establish the initial NOx boxes. Each combustion device may have two
NOx boxes, one larger than the other. The smaller NOx box, with the
lower emission factor, represents the typical operating range of the
unit. As long as the unit operates within this range, the listed
emission factor and the measured firing rate will be used to determine
the unit's contribution to the refinery-wide average. The operator may
choose to have a second, larger box, to cover unusual operating
conditions. This larger box will have a higher emission factor
associated with it. The allowance for two boxes means that a higher
emission factor can be used for occasional operation at harsher,
higher-emitting conditions, while still allowing use of a lower emission
factor during normal operation. The District believes this is an
appropriate degree of flexibility that does not unduly complicate
implementation.

The NOx box may be expanded by replacing corner points with new ones
that have been tested. The operator may also decide to increase the
emission factor associated with a NOx box. This may allow operation at a
wider range of conditions; it may be necessary because a source test has
shown that the old factor is no longer valid; it may be desirable to
provide a margin of compliance.

**Part 5** describes the actual NOx box.

Part 5A contains the table that defines the perimeter of the NOx box,
the perimeter of the second NOx box (if the operator chooses to use
one), and the emission factors used.

Part 5B allows established emission factors to be used for operation
outside the box at low firing rate conditions. Although NOx or CO
emission factors (expressed as lb/MMBtu) may be higher under these
conditions, overall emissions are lower because of the greatly reduced
firing rate. Testing under these conditions would have a significant
cost because the operator would need to reduce firing (and production)
to conduct a test. Instead, reduced firing will be treated in the same
manner as a shutdown: for purposes of calculating the refinery average,
the furnace will be treated as if it were operating at its normal firing
rate and emission rate. In other words, though emission factors may be
inaccurate in this low-firing range, there is not a possibility that
emissions will be underestimated.

Part 5C allows a facility to conduct source tests outside the NOx box in
order to increase the range of allowable operation.

**Part 6** describes the steps to be taken if operation outside the box
occurs.

Operation outside the range for which the emission factor has been
demonstrated raises certain questions. Is the emission factor valid for
these conditions? If not, and if emissions were higher, did the higher
emissions result in a violation of the refinery-wide average? The
procedures of this part answer these questions.

Operation outside the NOx box triggers a requirement for the operator to
test the unit under conditions that capture the new operating
conditions. The test may be conducted in lieu of the next scheduled
periodic source test (small furnaces, which may not normally be tested
so soon, will have to be tested within 8 months). It is possible that
the operator may not be able to reproduce the operating conditions
during a source test. Failure to conduct the test will result in a
violation of the Part 5 of the permit condition, and would be considered
a violation of 9-10-502. If more than one such violation occurs during a
5-year period at a given unit, the District will review the NOx Box for
that unit to determine whether it is, in fact, equivalent to a CEM. The
District considered whether to establish in permit conditions a
threshold for concluding that the NOx Box approach was inadequate for a
particular unit and that CEMs must be installed. However, a simple
algorithm for making this determination was not apparent. Instead, the
District will evaluate each situation case by case, and will use its
authorities to require installation of a CEM where appropriate.

If the test shows that emissions are below the factor used for the box,
then no violation has occurred. The operator may choose to expand the
box to utilize the new test results. This emission factor will then be
used in the future.

If, however, the test shows that the emission factor for the new
operating conditions exceeds the NOx box factor, the operator must
reassess past emissions utilizing the higher emission factor. This may
result in violations of the refinery-wide average (Regulation 9-10-301).

**Part 7** requires periodic source tests to demonstrate that the NOx
Box factor is still valid. Usually, tests will be conducted at whatever
conditions the unit is operating at on the day of the test. If, however,
it has been some time since the extreme corners of the box have been
tested, or if there is reason to believe that difficult operating
conditions are being avoided during tests, the APCO may require that the
test be conducted under specific conditions.

Small furnaces are tested once per year. Large furnaces are tested every
six months.

**Part 8** requires periodic CO source tests for units equipped with NOx
CEMs.

**Part 9** requires installation of a CO CEM if two sources tests show
CO levels greater than 200 ppm. Normal CO concentrations are an order of
magnitude lower. One high CO reading is an anomaly. Two high readings
are an indication that CO may be a problem, and continuous monitoring of
firing rate and O2 is not equivalent to continuous monitoring for CO.

**Part 10** requires maintenance of records for the monitoring required
by the permit condition.

#### Flares S-16, S-17, S-18 and S-19 {#flares-s-16-s-17-s-18-and-s-19 .unnumbered}

All of the refinery Title V permits contain permit conditions
implementing requirements for flares. As explained in the response to
comments on the initial Title V permit issuance, development of Title V
permit conditions related to flaring occurred in parallel with the
District's rulemaking on flare monitoring. The flare monitoring rule
(BAAQMD 12-11) addressed many of the issues that the District was
attempting to address in parallel through Title V, and so the Title V
effort was to a significant extent subsumed by incorporation of 12-11
into the final permits. The District's flare monitoring rule in some
ways went beyond similar existing regulations promulgated by other
agencies and in that sense was unprecedented in scope and effect. As far
as the District is aware, its efforts to craft Title V permit conditions
is similarly innovative, and similarly has undergone re-evaluation and
evolution. Even prior to issuance of the refinery Title V permits,
District staff had begun a re-evaluation of some of the approaches and
determinations slated for inclusion in the final permits. The current
proposal to revise certain Title V permit conditions for flares is the
outcome of that re-evaluation. The future effective dates attached to
some of the Title V flare conditions was, in part, a reflection of the
expectation that a re-evaluation was underway and that some additional
time should be allowed before effort and expense were invested in a
particular approach.

All of the flare conditions that were added during the initial Title V
permit issuance process proposed for deletion and replacement with new
conditions. The new conditions address proper operation, monitoring for
visible emissions, and enforcement of determinations that NSPS Subpart J
sulfur monitoring is not applicable.

The new conditions apply only to flares that are subject to Regulation
12-11. All of the flares that are fully exempt from 12-11 (S-17, the
ST-1701 Butane Tank Flare) operate under conditions, and burn materials,
that are unlikely to result in visible emissions. Additionally, because
they are not emergency flares, they are not likely to encounter flow
rates above capacity. The reasons that led to exemption of these flares
from 12-11 are also the reasons why additional Title V conditions
addressing these three areas are not appropriate. .

##### Proper operation {#proper-operation .unnumbered}

Proper flare operation is being addressed to support the conclusion that
flare emissions are not subject to the miscellaneous VOC regulation,
BAAQMD 8-2. A source is exempt from District Regulation 8 (and therefore
from 8-2) if, pursuant to 8-1-110.3, organic compounds are reduced by at
least 90% due to abatement by incineration. Flare emissions qualify for
this exemption if there is a reasonable assurance that 90% reduction is
occurring. The District surveyed available information on flare
efficiency and concluded there is a strong assurance that a 90%
reduction is achieved during proper flare operation. The Title V permit
conditions being proposed are intended to provide assurance that flares
will be operated properly.

The District's Advisory Council has reviewed flare available information
about refinery flares, and has rendered an opinion that hydrocarbon
destruction efficiency of a properly designed and operated flare is
greater than 98%. District staff have been working with the facilities,
activists, citizen groups, and various experts to develop flare
monitoring and control regulations. In the course of that work, the
current body of knowledge about refinery flare operation has been
reviewed. A consensus seems to be that the modern steam-assisted flares
commonly found at refineries are "properly designed" relative to the
purposes for which they are used. District staff have determined that a
properly designed flare may be said to be "properly operated" if the
flow rate is below the design capacity, if the gas being flared has
sufficient fuel value (i.e., 300 Bth/cubic foot), and if flame is
present at all times.

##### Design Capacity {#design-capacity .unnumbered}

**Part 1** of the flare condition requires the facility to operate the
flare below its rated capacity. This raises the question: what happens
if more gas needs to be flared than the flare is rated for? In that
situation, all of the gas will be routed to the flare; the alternative
is to vent the gas to the atmosphere without abatement, which in turn
would precipitate the extreme safety hazard that flares are designed to
prevent. The District therefore anticipates that the safe operation of
the flare will cause the flare to exceed its capacity, with a possible
reduction in destruction efficiency. This will result in a violation,
but the event will be handled safely. The proposed permit condition is
not expected to prohibit the use of the flare as necessary to avoid
safety hazards. There is a functional overlap between the goal of
preventing release of uncombusted gases for safety reasons, and the 90%
reduction threshold contained in 8-1-110.3. A failure to achieve at
least 90% reduction would be at odds with preventing the safety hazard
posed from release of uncombusted gases. In this sense, flares are
categorically distinguishable from the typical "end of pipe" air
pollution control device that is installed to meet a regulatory
requirement but does not otherwise promote the self-interest of the
facility. Refineries have a strong interest in proper flare operation
that prevents the potentially severe consequence of releasing explosive
gases over or near the facility. The fact that proper operation for
safety purposes is also proper operation for District regulatory
purposes provides a substantial assurance that 90% will be achieved. The
permit condition prohibiting operation above rated capacity provides an
additional regulatory enforcement tool to deter such events from
occurring.

**Part 2** requires recordkeeping to demonstrate compliance with Part 1.

##### Fuel value  {#fuel-value .unnumbered}

Flares that are designed to receive low-btu gas are equipped with
supplemental fuel gas lines to ensure that the gas vented to the flares
has sufficient heating value. The new flare monitoring rule, 12-11,
requires vent gas composition monitoring. District staff have presumed
that the systems designed to ensure that flared gases are combustible
are working properly. The monitoring required by 12-11 will provide a
means of verifying this.

##### Flame {#flame .unnumbered}

12-11-503 requires monitoring to ensure that flame is present. A permit
condition would be redundant.

##### Visible emissions {#visible-emissions .unnumbered}

The flare monitoring rule is designed to gather information to ensure
that flares are properly operated, and to be used for possible a future
control measure. It is not designed to assure compliance with other
applicable rules, specifically those regarding particulate and visible
emissions. Therefore, the District is proposing conditions to provide a
reasonable assurance of compliance with visible emissions and
particulate emissions standards.

The new Title V permit condition requires frequent monitoring of a flare
during a flaring event. The operator must check the flare for visible
emissions every half hour until the flaring event is over, or until a
violation is detected.

If the flare is under video surveillance, and if the video image is of
sufficient clarity for the operator to say with certainty that no
visible emissions are present, the video may be used. Otherwise, the
operator must directly view the flare. Regulation 6-301 is the
Ringelmann standard, and requires a trained observer to read the smoke
plume. When a trained observer is not available, the facilities have
agreed to operate under a more stringent "no visible emissions"
standard.

**Part 5** states that, if the surveillance is by a trained observer,
compliance will be demonstrated using EPA Method 9 (the method specified
in Regulation 6-301). Otherwise, an untrained observer observes the
stack, and if visible emissions are detected for three consecutive
minutes, the flare violates the surrogate standard contained in the
permit condition.

##### NSPS Subpart J  {#nsps-subpart-j .unnumbered}

Any flare built or modified after June 11, 1973 is subject to NSPS
Subpart J. Modification of a flare, as defined in Subpart J, would
likely only occur if the burner tip is replaced by one with a larger
capacity -- which is likely to be a rare event. As a result, NSPS
Subpart J typically applies to flares that are built after the effective
date. Valero S-19, the ST-2103 North Flare is covered by NSPS Subpart J.

There is only one requirement for flares subject to subpart J: a
limitation on the sulfur content of gas combusted, and the monitoring to
demonstrate compliance. Subpart J exempts from this requirement the
flaring of upset gases, and fuel gas that is the result of an emergency
breakdown.

Some of the facilities have identified NSPS flares (flares built after
1973) that are not designed to burn anything other than upset gases or
fuel gases that result from emergency breakdowns. These flares are
therefore exempt from the NSPS monitoring requirement, provided they are
used only in that manner. However, at least some of these flares have a
potential for broader use because the physical construction that enables
flaring of gases from upsets or emergencies also enables flaring of
gases from routine processes.

**Part 7** imposes a condition on these flares to assure compliance with
the exemption criteria. The same prohibition found in Part 7 could be
enforced by directly enforcing applicability of Subpart J, that is, by a
determination that the facility has been in violation of Subpart J if,
for instance, routine disposal of gases through flaring has occurred.
However, enforcement of Subpart J in federal court (through the CAA
citizen enforcement provisions) is an unwieldy tool for use by a
permitting agency such as the District that can much more readily
enforce in state court. By incorporating the prohibition against routine
flaring into Title V permits, enforcement of this prohibition becomes
substantially more feasible for the District.

#####  {#section-1 .unnumbered}

##### Issues raised by comments {#issues-raised-by-comments .unnumbered}

The District received a number of comments related to flares during the
initial permit issuance. In anticipation that similar comments may be
received regarding this proposal, the District here offers anticipatory
responses. The formerly-received comments are presented below, together
with a response that tells how the comment is addressed by the revised
permit condition. The District will of course respond to any new
comments received or to refinements of comments noted here.

**Comment**: The Air District should require the performance of
independent testing using available methods for monitoring flare
efficiency under worst case conditions.

**Response:** There is no way to directly monitor flare efficiency.
However, it is possible to monitor flare parameters (flow rate, etc) in
a way to ensure that flares operate as designed. This is the approach
taken in Part 1 of this proposal. The District disagrees with the
suggestion that, because performance measurement techniques are limited,
it follows that specification of minimum flare destruction efficiency is
contrary to Title V requirements. Flare destruction efficiency is a
provision of 12-11, and therefore should be incorporated in the permit.
Despite the technical limits of direct compliance verification, the
requirement has relevance and import as a design requirement.

This comment, proposing as it does "independent testing" and "worst case
conditions," is not a monitoring proposal, but a recommendation for data
development. While perhaps appropriate for rule development, such a
proposal is not within the scope of Title V.

**Comment**: A flaring event that lasts between 3 and 15 minutes could
exceed opacity limits, and this type of violation would go unmonitored
under existing permit monitoring requirements. The District implies that
opacity limitations need only be monitored if the emission is
"significant" or is " a real problem." The District's opacity regulation
does not allow for these exemptions from its requirements.

**Response:** The comment is based upon the faulty premise that the
purpose of Title V monitoring is to detect every violation. Continuous
monitoring for violations can be cost-prohibitive, impractical, and
even, in a case such as this, at odds with good air pollution practices.
The purpose of Title V monitoring is to provide reasonable assurance of
compliance. This requires a balance between cost and difficulty of the
testing, and the likelihood and severity of non-compliance. See, for
example, EPA's guidance on the required monitoring for other sources
subject to visible emission standards.

Because the visual observation and sample collection that comprise flare
monitoring are going to be performed by the process unit operator, both
Rule 12-11 and the permit condition require the initial monitoring to
occur 30 minutes into the episode. This is to allow the operator to
place his or her attention, at the beginning of the event, where it
belongs: trying to address the conditions that are resulting in flaring.
A flaring event that can be ended within 15 minutes should be, and
should not be prolonged while the operator goes out to look at the
stack. A flaring event that goes on for thirty minutes, though, is
probably not going to be resolved so quickly. Three minutes to check on
the flare's appearance is not going to seriously affect the duration of
the incident.

The frequency and duration of monitoring for visible emissions is a
matter of judgment, balancing the value of information gained against
the costs of collection. Taking into consideration all of the factors,
District staff have determined that a periodic check every half hour
provides the necessary assurance that significant non-compliance will be
detected.

**Comment:** Regulation 8-2 should apply to refinery flares. Either
monitoring to assure compliance with 8-2 should be imposed, or
monitoring to assure compliance with the 85% destruction efficiency
requirement in 8-1-110.3.

**Response:** Part 1 and Part 2 of the revised permit condition are
intended to address this. By ensuring that the flare is properly
operated, the condition assures that combustion efficiency is maintained
at a high level, thereby assuring that application of the exemption
contained in 8-1-110.3 is appropriate. As noted above, flare destruction
efficiency cannot be measured directly, and so a reasonable substitute
must be used. The District believes there is a reasonable basis for
concluding that 90% destruction efficiency will be met because efficient
destruction is the very reason for the existence of a flare. However,
the permit conditions in this proposal will provide an added measure of
assurance and a regulatory enforcement tool to supplement this inherent
design goal.

**Comment:** The permit should contain monitoring to determine
compliance with subpart J, including fuel H2S monitoring for those
flares subject to the fuel H2S limit.

**Response:** The fuel H2S monitoring is, in fact, the only monitoring
needed to determine compliance with subpart J. This has been included in
Table IV an VII for each flare subject to the limit. Flares subject to
Subpart J, but not the limit, because they only burn upset gas, are
subject to Part 7 of the flare condition.

**Comment:** Please also include record-keeping and reporting
requirements for those flares subject to NSPS J but exempt from the fuel
H2S limit.

**Response:** It is unclear what monitoring is being requested. If the
proposal is to include monitoring to ensure that non-exempt gases are
not vented to exempt flares, the requirements of Regulation 12-11-401
should suffice. We do not consider, however, this monitoring to be
federally enforceable. The only federally enforceable monitoring for
assuring compliance with Subpart J is spelled out in Subpart J.

**EPA Comment:** We also understand that the District will include
opacity monitoring on process flares for compliance with
Ringlemann/opacity Regulations 6-301 & 302 and each of the requirements
that apply on a unit specific basis, and mark all flame monitoring as
"continuous" monitoring.

**Response:** The new condition includes visible emission monitoring to
assure compliance with Regulations 6-301 and 6-302.

**EPA Comment:** Where the necessary Title V monitoring coincides with
the District's Regulation 12-11 flare monitoring rule, the District may
list Reg 12-11 as the monitoring that will satisfy Title V if it is
listed as federally enforceable.

**Response:** Only monitoring to assure compliance with a federally
enforceable limit is supposed to be labeled as "federally enforceable."

**EPA comment:** For sources that must meet a given control efficiency,
the District must include a compliance determination and monitoring
method for those requirements.

**Response:** The District has determined that properly designed,
properly operated flare meet 98% destruction efficiency. All refinery
flares are properly designed and some assurance of proper operation
derives from the fact that an improperly operated flare is not an
effective safety device. Monitoring to provide an additional assurance
that each flare is properly operated has been added to the permit. See
discussion above.

**EPA Comment:** For thermal oxidizers, the permit evaluations \[*sic*\]
must also contain the applicable requirements.

**Response:** The District permit contains all requirements identified
by the District as applicable.

**EPA Comment:** The permits must also require monitoring the flow rate
if necessary to determine compliance with residence time requirements.
This monitoring is in addition to the temperature monitoring that the
District already includes.

**Response:** Valero has oxidizers subject to 40 CFR 61, Subpart FF.
Subpart FF gives you three choices for compliance for incinerators: 95%
control of VOC, 20 ppmv benzene, or 1400 degrees F and 0.5 sec residence
time. The standard requires monitoring of a parameter or parameters, but
doesn\'t specific the parameter. In the past, Valero had told me that
they complied at the main refinery with the requirement to show 95%
control with a performance test instead of design calculations. This is
an option.

#### District Permit Applications Not Included In This Proposed Permit {#district-permit-applications-not-included-in-this-proposed-permit .unnumbered}

This facility sends a large number of permit applications to the
District every year. Review of the following permit applications was not
completed in time to include the results in this version of the Title V
permits. The Title V permit will be revised periodically to incorporate
these applications as permit revisions following the procedures in
Regulation 2, Rule 6, Major Facility Review.

  -----------------------------------------------------------------------
  **Application    **Project Description**
  \#**             
  ---------------- ------------------------------------------------------
  5846             Valero Improvement Project

  7980             Transfer of selected Storage Tank assets to Valero
                   Logistics Operations Facility B5574
  -----------------------------------------------------------------------

## V. Schedule of Compliance  {#v.-schedule-of-compliance .unnumbered}

A schedule of compliance is required in all Title V permits pursuant to
BAAQMD Regulation 2-6-409.10 which provides that a major facility review
permit shall contain the following information and provisions:

"409.10 A schedule of compliance containing the following elements:

10.1 A statement that the facility shall continue to comply with all
applicable requirements with which it is currently in compliance;

10.2 A statement that the facility shall meet all applicable
requirements on a timely basis as requirements become effective during
the permit term; and

10.3 If the facility is out of compliance with an applicable requirement
at the time of issuance, revision, or reopening, the schedule of
compliance shall contain a plan by which the facility will achieve
compliance. The plan shall contain deadlines for each item in the plan.
The schedule of compliance shall also contain a requirement for
submission of progress reports by the facility at least every six
months. The progress reports shall contain the dates by which each item
in the plan was achieved and an explanation of why any dates in the
schedule of compliance were not or will not be met, and any preventive
or corrective measures adopted."

Since the District has not determined that the facility is out of
compliance with an applicable requirement, the schedule of compliance
for this permit contains only sections 2-6-409.10.1 and 2-6-409.10.2.

The BAAQMD Compliance and Enforcement Division has conducted a review of
compliance over the past year and has no records of compliance problems
at this facility during the past year.

## VI. Permit Conditions  {#vi.-permit-conditions .unnumbered}

As part of the Title V permit reopening, the District is proposing
changes made to several permit conditions, these include: conditions
regarding flares and Regulation 9-10 requirements, and, as appropriate,
revised conditions for clarity and enforceability. The Title V permit is
being updated to accurately reflect these applicable requirements. All
changes to existing permit conditions are clearly shown in
"strike-out/underline" format in the proposed permit. When the permit is
issued, all 'strikeout" language will be deleted; all "underline"
language will be retained, subject to consideration of comments
received.

Conditions that were changed in this revision of the permit are as
follows:

Condition 125 and 126 -- Part 2 was reinstated and updated to require
operation and maintenance for the H2S monitor. (EPA Comment \# 196)

Condition 9296 -- Deleted Part A1 and added Part A4 per MTBE Phaseout
Application 2035.

Condition 10797 -- Revised per MTBE Phaseout Application 2035.

Condition 11882 -- Deleted Part 7 because temperature excursions are not
allowed under 40 CFR 61 Subpart FF. (EPA Comment \# 185)

Condition 13319 -- Deleted Part 7 because temperature excursions are not
allowed under 40 CFR 61 Subpart FF. (EPA Comment \# 213)

Condition 19177 -- Added Part 18c monitoring for ammonia injection.
(Valero Comment \# C40)

Condition 19466 -- Updated Part 3 to be consistent with the specific
source equipment subject to BAAQMD Regulation 6-301 compliance
monitoring. (Valero Comment \# 9)

Condition 19466 -- Updated Part 4 to provide unscheduled
start-up/shutdown notification when the event occurs on a
weekend/holiday period.

Condition 19466 -- Updated Part 7 to be consistent with the specific
source equipment subject to BAAQMD Regulation 6-310 compliance
monitoring. (Valero Variance Item #1)

Condition 20806 -- This Flare condition was replaced as discussed in
Section C.IV above.

Condition 21233 -- This "NOx Box" condition was added as discussed in
Section C.IV above.

The regulatory basis is listed following each condition. The regulatory
basis may be a rule or regulation. The District is also using the
following terms for regulatory basis:

-   BACT: This term is used for a condition imposed by the Air Pollution
    Control Officer (APCO) to ensure compliance with the Best Available
    Control Technology in Regulation 2-2-301.

-   Cumulative Increase: This term is used for a condition imposed by
    the APCO which limits a source's operation to the operation
    described in the permit application pursuant to BAAQMD Regulation
    2-1-403.

-   Offsets: This term is used for a condition imposed by the APCO to
    ensure compliance with the use of offsets for the permitting of a
    source or with the banking of emissions from a source pursuant to
    Regulation 2, Rules 2 and 4.

-   PSD: This term is used for a condition imposed by the APCO to ensure
    compliance with a Prevention of Significant Deterioration permit
    issued pursuant to Regulation 2, Rule 2.

-   TRMP: This term is used for a condition imposed by the APCO to
    ensure compliance with limits that arise from the District's Toxic
    Risk Management Policy.

## [VII.]{.smallcaps} Applicable Limits and Compliance Monitoring Requirements  {#vii.-applicable-limits-and-compliance-monitoring-requirements .unnumbered}

This section of the permit is a summary of numerical limits and related
monitoring requirements for each source. The summary includes a citation
for each monitoring requirement, frequency of monitoring, and type of
monitoring. The applicable requirements for monitoring are completely
contained in Sections IV, Source-Specific Applicable Requirements, and
VI, Permit Conditions, of the permit.

The tables below contain only the new limits in the reopened permit for
which there is no monitoring or inadequate monitoring in the applicable
requirements. The District has examined the monitoring for other limits
and has determined that monitoring is adequate to provide a reasonable
assurance of compliance. Calculations for potential to emit will be
provided in the discussion when no monitoring is proposed due to the
size of a source.

**NOx Discussion:**

There are no changes in the permit sources where NOx monitoring is
missing or inadequate.

**CO Discussion:**

There are no changes in the permit sources where CO monitoring is
missing or inadequate.

**SO2 Discussion:**

There are no changes in the permit sources where SO2 monitoring is
missing or inadequate.

+---------------+---------------+---------------------+---------------+
| [PM           |               |                     |               |
| Sources       |               |                     |               |
| ]{.underline} |               |                     |               |
+===============+===============+=====================+===============+
| **\           | **Emission    | **Federally         | **\           |
| S# &          | Limit         | Enforceable         | Monitoring**  |
| Description** | Citation**    | Emission Limit**    |               |
+---------------+---------------+---------------------+---------------+
| S-167, S-168, | BAAQMD        | > Ringelmann 1 for  | > No          |
| Seal Oil      | Regulation    | > more than 3       | > monitoring  |
| Spargers      |               | > minutes in any    |               |
|               | 6-301         | > hour              |               |
+---------------+---------------+---------------------+---------------+
| S-167, S-168, | BAAQMD        | 0.15 grains per     | > No          |
| Seal Oil      | Regulation    | dscf                | > monitoring  |
| Spargers      | 6-310         |                     |               |
+---------------+---------------+---------------------+---------------+

**PM Discussion:**

This change in the Seal Oil Spargers is actually a correction. The
December 1, 2003 permit listed S-167 and S-168 with no monitoring
because the source is capable of exceeding visible emissions or grain
loading standard only during process upset. Under such circumstances,
other indicators will alert the operator that something is wrong. In
fact, these sources vent to the closed refinery fuel gas system. In
addition, the December 1, 2003 permit showed Seal Oil Sparger S-160 with
no 6-310 monitoring. This was an error. BAAQMD Condition \# 19466, Part
7 requires S-160 monitoring for 6-310 compliance verification.

**POC Discussion:**

There are no changes in the permit sources where POC monitoring is
missing or inadequate.

## VIII. Test Methods  {#viii.-test-methods .unnumbered}

This section of the permit lists test methods that are associated with
standards in District or other rules. It is included only for reference.
In most cases, the test methods in the rules are source test methods
that can be used to determine compliance but are not required on an
ongoing basis. They are not applicable requirements.

If a rule or permit condition requires ongoing testing, the requirement
will also appear in Section IV of the permit.

## IX. Permit Shield  {#ix.-permit-shield .unnumbered}

The District rules allow two types of permit shields. The permit shield
types are defined as follows: (1) A provision in a major facility review
permit explaining that specific federally enforceable regulations and
standards do not apply to a source or group of sources, or (2) A
provision in a major facility review permit explaining that specific
federally enforceable applicable requirements for monitoring,
recordkeeping and/or reporting are subsumed because other applicable
requirements for monitoring, recordkeeping, and reporting in the permit
will assure compliance with all emission limits.

The second type of permit shield is allowed by EPA's [White Paper 2 for
Improved Implementation of the Part 70 Operating Permits
Program.]{.underline} The District uses the second type of permit shield
for all streamlining of monitoring, recordkeeping, and reporting
requirements in Title V permits. The District's program does not allow
other types of streamlining in Title V permits.

This facility has the first and second types of permit shield. However,
since the December 1, 2003 permit, there has been no additional permit
shields. There was one correction to the permit shields. BAAQMD 10-52
and 10-59 were deleted from Table IX B-24 because they are
non-applicable requirements, not subsumed requirements. Then, Table IX
A-5 was added to show these Subpart VV and Subpart GGG non-applicability
requirements for equipment leaks. (EPA Comment \# 17)

+---------------+----------------------+-------------------------------+
| **Table IX    |                      |                               |
| A-5**         |                      |                               |
|               |                      |                               |
| **Permit      |                      |                               |
| Shield for    |                      |                               |
| Non           |                      |                               |
| -Applicable** |                      |                               |
|               |                      |                               |
| **Fugitive    |                      |                               |
| Sources**     |                      |                               |
|               |                      |                               |
| **\`****S-51  |                      |                               |
| HCU Feed      |                      |                               |
| Filter        |                      |                               |
| R-410A**      |                      |                               |
|               |                      |                               |
| **S-52 HCU    |                      |                               |
| Feed Filter   |                      |                               |
| R-410B**      |                      |                               |
|               |                      |                               |
| **S-1002      |                      |                               |
| Diesel        |                      |                               |
| Hydrofiner**  |                      |                               |
|               |                      |                               |
| **S-1003      |                      |                               |
| Hydrocracker  |                      |                               |
| (HCU)**       |                      |                               |
|               |                      |                               |
| **S-1005      |                      |                               |
| Catalytic     |                      |                               |
| Feed Hydro.** |                      |                               |
|               |                      |                               |
| **S-1006      |                      |                               |
| Pipestill     |                      |                               |
| Unit**        |                      |                               |
|               |                      |                               |
| **S-1007      |                      |                               |
| Alkylation    |                      |                               |
| Unit**        |                      |                               |
|               |                      |                               |
| **S-1008      |                      |                               |
| Gasoline      |                      |                               |
| Hydrofiner**  |                      |                               |
|               |                      |                               |
| **S-1009 Jet  |                      |                               |
| Fuel          |                      |                               |
| Hydrofiner**  |                      |                               |
|               |                      |                               |
| **S-1011      |                      |                               |
| Heavy Cat     |                      |                               |
| Naphtha       |                      |                               |
| Hydrofiner**  |                      |                               |
|               |                      |                               |
| **S-1014 Cat  |                      |                               |
| Light Ends**  |                      |                               |
|               |                      |                               |
| **S-1020      |                      |                               |
| Heartcut      |                      |                               |
| Tower (MRU),  |                      |                               |
| except for    |                      |                               |
| Heartcut      |                      |                               |
| Stream**      |                      |                               |
|               |                      |                               |
| **S-1021      |                      |                               |
| Heartcut Sat  |                      |                               |
| Unit (MRU)    |                      |                               |
| except for    |                      |                               |
| Heartcut      |                      |                               |
| Stream**      |                      |                               |
|               |                      |                               |
| **S-1022 Cat  |                      |                               |
| Ref T90 Tower |                      |                               |
| MRU**         |                      |                               |
|               |                      |                               |
| **S-1023 Cat  |                      |                               |
| Nap T90 Tower |                      |                               |
| MRU**         |                      |                               |
|               |                      |                               |
| **S-1024 Lt   |                      |                               |
| Cat Nap       |                      |                               |
| Hydrotreater  |                      |                               |
| MRU**         |                      |                               |
|               |                      |                               |
| **S-1026      |                      |                               |
| C5/C6         |                      |                               |
| Splitter      |                      |                               |
| (MRU)**       |                      |                               |
|               |                      |                               |
| **Heartcut    |                      |                               |
| Stream (MRU)  |                      |                               |
| (2)**         |                      |                               |
|               |                      |                               |
| **Fluid       |                      |                               |
| Catalytic     |                      |                               |
| Cracking      |                      |                               |
| Unit**        |                      |                               |
|               |                      |                               |
| **Virgin      |                      |                               |
| Light Ends,   |                      |                               |
| excluding     |                      |                               |
| S-1002,       |                      |                               |
| S-1008, and   |                      |                               |
| S-1009**      |                      |                               |
+---------------+----------------------+-------------------------------+
| **Citation**  | **Title or           | **Reason Not Applicable**     |
|               | Description**        |                               |
+---------------+----------------------+-------------------------------+
| 40 CFR 60     | Standards of         | Per 63.640 (p), equipment     |
| Subpart VV    | Performance For      | leaks that are also subject   |
|               | Equipment Leaks of   | to Part 60 (NSPS) and Part 61 |
|               | VOC In The Synthetic | (NESHAPS) are only required   |
|               | Organic Chemicals    | to comply with Part 63        |
|               | Manufacturing        | (MACT).                       |
|               | Industry.            |                               |
+---------------+----------------------+-------------------------------+
| 40 CFR 60     | Standards of         | Per 63.640 (p), equipment     |
| Subpart GGG   | Performance For      | leaks that are also subject   |
|               | Equipment Leaks Of   | to Part 60 (NSPS) and Part 61 |
|               | VOC In Petroleum     | (NESHAPS) are only required   |
|               | Refineries           | to comply with Part 63        |
|               |                      | (MACT).                       |
+---------------+----------------------+-------------------------------+

# D. Alternate Operating Scenarios: {#d.-alternate-operating-scenarios .unnumbered}

No alternate operating scenario has been requested for this facility.

# E. Compliance Status: {#e.-compliance-status .unnumbered}

[Changes to the permit in this revision:]{.underline}

The facility is not currently in violation of any requirement. Moreover,
the District has updated its review of recent violations and has not
found a pattern of violations that would warrant imposition of a
compliance schedule.

# F. Permit Updates and Changes since the Final December 1, 2003 Permit  {#f.-permit-updates-and-changes-since-the-final-december-1-2003-permit .unnumbered}

Section I, II, III changes

1.  In Table IIA, added reference to MTBE Phaseout Application 2035 in
    the Throughput column for S-40, S207, S209 and S-210. Added S-211
    Alkylate Debutanizer which is the only equipment in the MTBE Unit
    that still is operated. (VRC#A5)

2.  In Table IIC, added A-64 Spare Tail Gas Hydrogenation Unit
    consistent with Application 8028.

3.  In Table IIC, deleted the reference to continuous monitoring on A-24
    and A-56. The H2S and TRS monitor does not monitor the SO2 limit of
    9-1-307. Furthermore, it is an operations troubleshooting device and
    deleting the term 'continuous' will avoid any inference that it is a
    CEM for SO2. Note also that S-1 and S-2 are not operated without
    abatement A-24, A-64 and A-56. All SO2 in the S-1 and S-2 Tail Gas
    has to be converted to H2S in A-24 or A-64 to prevent poisoning the
    absorbent in A-56. Therefore SO2 emissions are low and well below
    both the 250 ppm and the 100 lb/day threshold of 9-1-307.

Section IV, Applicable Requirements

1.  In Table IV-X, added reference to Condition 18043, Part 1 to S-1007,
    1012 and 1014 per MBTE Phaseout Application 2035. (VRC#B115)

2.  In Table IV-J9, Condition 10797 Parts 1, 4, 6 & 7 were revised and
    Parts 2, 5, 8 & 9 were deleted per MTBE Phaseout Application 2035.
    (VRC#B125, 126, 127, 128, 129)

3.  In Table IV-A22.1 and A22.2, added ammonia monitoring to Condition
    19177, Part 18(c), consistent with the condition text in Section VI.
    (VRC#C40)

4.  In Table IV-J39 Condition 11882, Part 7 was deleted because
    temperature excursions are not allowed under 40CFR 61 Subpart FF.
    (EPA#185)

5.  In Tables IV-A1 & A2, Condition 125 and 126, Part 2 was reinstated
    and updated to require operation and maintenance of the H2S monitor.
    (EPA#196)

6.  In Tables IV-H4.2 & H5.2, Condition 13319, Part 7 was deleted
    because temperature excursions are not allowed under 40CFR 61
    Subpart FF. (EPA#213)

7.  In Table IV-B1 for S-8, S-10 and S-12, Condition 19466, Part 7 was
    revised to agree with the text in Section VI. (VRC#V1)

8.  In Table IV-B2 for S-11, Condition 19466, Part 7 was revised to
    agree with the text in Section VI. (VRC#V1)

9.  In Table IV-C4.1 for S-160, Condition 19466, Part 7 was revised to
    agree with the text in Section VI. (VRC#V1)

10. In Table IV-B4 for S-176, Condition 19466, Part 7 was revised to
    agree with the text in Section VI. (VRC#V1)

11. In Table IV-B6 for S-232, Condition 19466, Part 7 was deleted to
    agree with the corrected text in Section VI. (VRC#V1)

12. In Table IV-B7 for S-233, Condition 19466, Part 7 was revised to
    agree with the text in Section VI. (VRC#V1)

13. In Table IV-A20 for S-237, Condition 19466, Part 7 was deleted to
    agree with the corrected text in Section VI. (VRC#V1)

14. In Table IV-H4.1, deleted 40 CFR 61.349(f) and (f)(1) which do not
    apply since S-188 is vented to the refinery fuel gas system.
    (VRC#V3)

15. In Table IV-H5.1, added 40 CFR 61.340(a), (c) and (d) for S-189.
    Deleted all the other Subpart FF citations since they do not apply
    for this unit that is vented to the refinery fuel gas system.
    (VRC#V3)

16. In Table IV-H4.2, added the Subpart FF citations that were deleted
    in error. (VRC#V3)

17. In Tables IV-J11 and J12, switched the S-87 and S-89 tank errors in
    the tables. S-89 has a solid guide pole and must be on Table IV-J11.
    S-87 has a slotted guide pole and must be on Table IV-J12. (VRC#V4)

18. In Table IV -- Refinery Generally Applicable Requirements which
    Require Routine Monitoring, deleted Regulation 9-1-302 because since
    the Ground Level Monitoring for SO2 was installed prior to 1/1/1980,
    Regulation 9-1-110 exempts the facility from 9-1-302.

19. In several Section IV tables the effective dates were corrected from
    4/01/03 to 4/01/04 to be consistent with Condition 19466, Part 16.

20. In Tables IV-A1 and A2, corrected the Condition 125 and 126 Part 4
    that reference the A-24, A-56 and A-64, consistent with Condition
    125 and 126 in Section VI.

21. Added Table IV-D1 for S-1004 Catalytic Reformer. (VRC#B79)

22. Added Table IV-D2 for S-1006 Crude Unit. (VRC#B79)

23. Added Table IV-D3 for S-1007 Alkylation Unit. (VRC#B79)

24. Added Table IV-D4 for S-1010 Hydrogen Unit. (VRC#B79)

25. Added Table IV-D5 for S-1012 Dimersol Unit. (VRC#B79)

26. Added Table IV-D6 for S-1014 Virgin Light Ends Splitter. (VRC#B79)

27. Added Table IV-D7 for S-1024 Light Cat Naphtha Hydrofiner. (VRC#B79)

28. Revised Flare Condition 20806, Table IV-A8.1, IV-8.2 and IV-9, and
    Tables VII-A8.1, A8.2 and A9 to reflect the latest flare operation
    and monitoring requirements. Only S-19 is subject to Subpart J
    because it was constructed after 6/11/1973. S-19 only burns upset or
    fuel gas as defined in 40 CFR 60.101 so it is exempt from the sulfur
    oxide standard of Subpart J. The revision to Condition 20806 adds
    clarity to the previous version. (VRC#3, V2, B27, C64 and D14) Also
    added Regulations 12-11-502.1, 12-11-502.2, 12-11-601.1 and
    12-11-602 to Tables IV-A8.1 and A9 for clarification. (Valero Appeal
    #3)

29. Revised Condition 9296 to delete Part A1 and add Part A4 as approved
    in Application 2035 MTBE Phaseout Project. Added Tables IV-D8 and
    VII-D8 for the S-211 Alkylate Debutanizer which is the only item in
    the former MTBE Unit that is still in operation.

30. Added Condition 21233 for Regulation 9-10 Refinery-wide Compliance
    ("NOx Box"). Revised Tables IV-A6.1, A6.2, A10, A11, A12, A15, A16,
    A18 and A19, and Tables VII-A6.1, A6.2, A10, A11, A12, A15, A16, A18
    and A19. (VRC#7, B20, C49, & D9)

31. Revised Condition 19566, Part 4 to allow unscheduled start-up or
    shutdown notification on the next business day when the event occurs
    on a weekend or holiday period. Also updated Table IV -- Refinery
    Generally Applicable Condition.

Section VI, Permit Conditions

1.  Condition 10797 Parts 1, 4, 6 & 7 were revised and Parts 2, 5, 8 & 9
    were deleted per MTBE Phaseout Application 2035. (VRC#C15, 16, 17,
    18, 19)

2.  Condition 19177, Part 18c was revised to add monitoring for ammonia
    injection. (VRC#C40)

3.  Condition 11882, Part 7 was deleted because temperature excursions
    are not allowed under 40CFR 61 Subpart FF. (EPA#185)

4.  Condition 125 and 126, Part 2 was reinstated and updated to require
    operation and maintenance of the H2S monitor. (EPA#196)

5.  Condition 13319, Part 7 was deleted because temperature excursions
    are not allowed under 40CFR 61 Subpart FF. (EPA#213)

6.  Condition 19466, Part 7 was modified for S-10 and S-12 to require
    the annual source test only when the sources are returned to
    service. (VRC#V1)

7.  Condition 19466, Part 7 was modified to allow the S-11 annual source
    test scheduling flexibility. (VRC#V1)

8.  Condition 19466, Part 7 was modified to require a S-160 and S-233
    source test plan and procedure be prepared and submitted by 4/1/04
    for District approval. This is because there is concern that the
    cited ST-15 is not applicable for these small (\<3") sources. The
    annual source test would commence no more than 90 days after the
    District approval of the submission. (VRC#V1)

9.  Condition 19466, Part 7 was modified to delete S-232 because it is a
    closed unit that discharges into S-233. (VRC#V1)

10. Condition 19466, Part 7 was modified to delete S-237 to be
    consistent with the other fuel gas fired boilers. Since all the
    other sources in 19466-7 are material handling, it is likely that
    S-237 was included by mistake. (VRC#V1)

11. Revised Condition 9296 to delete Part A1 and add Part A4 as approved
    in Application 2035 MTBE Phaseout Project.

12. Added Condition 18043 as approved in Application 2035 MTBE Phaseout
    Project.

13. Condition 19466, Part 3 was modified to delete S-232. S-232 is a
    closed unit that discharges into S-233. In addition, provisions were
    added for S-10, S-12 and S-176 to require monitoring only if the
    equipment is returned to service. (VRC#9)

14. Revised Flare Condition 20806, Table IV-A8.1, IV-8.2 and IV-9, and
    Tables VII-A8.1, A8.2 and A9 to reflect the latest flare operation
    and monitoring requirements. Only S-19 is subject to Subpart J
    because it was constructed after 6/11/1973. S-19 only burns upset or
    fuel gas as defined in 40 CFR 60.101 so it is exempt from the sulfur
    oxide standard of Subpart J. The revision to Condition 20806 adds
    clarity to the previous version. (VRC#3, V2, B27, C64 and D14)

15. Added Condition 21233 for Regulation 9-10 Refinery-wide Compliance
    ("NOx Box"). Revised Tables IV-A6.1, A6.2, A10, A11, A12, A15, A16,
    A18 and A19, and Tables VII-A6.1, A6.2, A10, A11, A12, A15, A16, A18
    and A19. (VRC#7, B20, C49, & D9)

16. Revised Condition 19566, Part 4 to allow unscheduled start-up or
    shutdown notification on the next business day when the event occurs
    on a weekend or holiday period. Also updated Table IV -- Refinery
    Generally Applicable Condition.

Section VII, Monitoring Requirements

1.  In Table VII-A22.1 and A22.2, added continuous ammonia injection
    monitoring, consistent with Condition 19177, Part 18(c) in Section
    IV and VI. (VRC#C40, D43)

2.  In Table VII-A20, FP grain loading monitoring Condition 19466, Part
    7 was deleted to be consistent with the other fuel gas fired
    boilers. Since all the other sources in 19466-7 are material
    handling, it is likely that S-237 was included in 19466-7 by
    mistake. (VRC#V1)

3.  In Table VII-B1, modified FP grain loading 6-310 monitoring to
    indicate the annual source test only applied to S-10 and S-12 when
    returned to service. (VRC#V1)

4.  In Table VII-C4, modified FP grain loading 6-310 monitoring to
    indicate the annual source test commences for S-160 Seal Oil Sparger
    after the source test plan and procedure is approved by the
    District. (VRC#V1)

5.  In Table VII-B4, modified FP grain loading 6-310 monitoring to
    indicate the annual source test only applies to S-176 when dry salt
    is added to the tank. (VRC#V1)

6.  In Table VII-B7, modified FP grain loading 6-310 monitoring to
    indicate the annual source test commences for S-233 Storage Bin
    after the source test plan and procedure is approved by the
    District. (VRC#V1)

7.  In Table VII-B6, FP grain loading monitoring Condition 19466, Part 7
    was deleted. Since S-232 is a closed unit discharging into S-233, it
    is likely that S-232 was included in 19466-7 by mistake. (VRC#V1)

8.  In Tables VII-J19, J20, J30 and J31.1, the monitoring for 8-5-301
    was deleted. These tanks are covered by the low vapor pressure
    exemption 8-5-117 so 8-5-301 would not apply. Also, the monitoring
    requirement citation for 8-5-117 was corrected from 8-5-501 to the
    more specific 8-5-501.1 to be consistent with citations elsewhere in
    Section VII. (VRC#V5)

9.  Added Table VII-D1 for S-1004 Catalytic Reformer. (VRC#D62)

10. Added Table VII-D2 for S-1006 Crude Unit. (VRC#D62)

11. Added Table VII-D3 for S-1007 Alkylation Unit. (VRC#D62)

12. Added Table VII-D4 for S-1010 Hydrogen Unit. (VRC#D62)

13. Added Table VII-D5 for S-1012 Dimersol Unit. (VRC#D62)

14. Added Table VII-D6 for S-1014 Virgin Light Ends Splitter. (VRC#D62)

15. Added Table VII-D7 for S-1024 Light Cat Naphtha Hydrofiner.
    (VRC#D62)

16. Revised Condition 9296 to delete Part A1 and add Part A4 as approved
    in Application 2035 MTBE Phaseout Project. Added Tables IV-D8 and
    VII-D8 for S-211 Alkylate Debutanizer which is the only item in the
    former MTBE Unit that is still in operation.

17. In Tables VII-J14, J38 and J41, the monitoring for 8-5-117 was
    deleted. These tanks are subject to Regulation 8-5 and will likely
    never store low vapor pressure material. (VRC#V5 follow-up)

18. Revised Flare Condition 20806, Table IV-A8.1, IV-8.2 and IV-9, and
    Tables VII-A8.1, A8.2 and A9 to reflect the latest flare operation
    and monitoring requirements. Only S-19 is subject to Subpart J
    because it was constructed after 6/11/1973. S-19 only burns upset or
    fuel gas as defined in 40 CFR 60.101 so it is exempt from the sulfur
    oxide standard of Subpart J. The revision to Condition 20806 adds
    clarity to the previous version. (VRC#3, V2, B27, C64 and D14)

19. Added Condition 21233 for Regulation 9-10 Refinery-wide Compliance
    ("NOx Box"). Revised Tables IV-A6.1, A6.2, A10, A11, A12, A15, A16,
    A18 and A19, and Tables VII-A6.1, A6.2, A10, A11, A12, A15, A16, A18
    and A19. (VRC#7, B20, C49, & D9)

Section IX, Permit Shield

1.  Deleted BAAQMD 10-52 and 10-59 from Table IX B-24 because they are
    non-applicable requirements, not subsumed requirements. Added Table
    IX A-5 detailing these Subpart VV and Subpart GGG non-applicable
    requirements for equipment leaks. (EPA#17)

Section X, Glossary

1.  Added definitions for Start-up, Shutdown, and Process Unit for
    reporting purposes.

H:\\pub_data\\titleV\\permit\\evals\\[B2626 Rev 1 sob]{.underline}.doc

APPENDIX A

GLOSSARY

#  {#section-2 .unnumbered}

**ACT**

Federal Clean Air Act

**APCO**

Air Pollution Control Officer

**ARB**

Air Resources Board

**BAAQMD**

Bay Area Air Quality Management District

**BACT**

Best Available Control Technology

> **Basis**
>
> The underlying authority which allows the District to impose
> requirements.

**CAA**

The federal Clean Air Act

**CAAQS**

California Ambient Air Quality Standards

**CAPCOA**

California Air Pollution Control Officers Association

**CEQA**

California Environmental Quality Act

**CFR**

> The Code of Federal Regulations. 40 CFR contains the implementing
> regulations for federal environmental statutes such as the Clean Air
> Act. Parts 50-99 of 40 CFR contain the requirements for air pollution
> programs.

**CO**

Carbon Monoxide

**Cumulative Increase**

> The sum of permitted emissions from each new or modified source since
> a specified date pursuant to BAAQMD Rule 2-1-403, Permit Conditions
> (as amended by the District Board on 7/17/91) and SIP Rule 2-1-403,
> Permit Conditions (as approved by EPA on 6/23/95). Cumulative increase
> is used to determine whether threshold-based requirements are
> triggered.

**District**

The Bay Area Air Quality Management District

> **dscf**
>
> Dry Standard Cubic Feet

**EPA**

The federal Environmental Protection Agency.

**Excluded**

Not subject to any District regulations.

**Federally Enforceable, FE**

> All limitations and conditions which are enforceable by the
> Administrator of the EPA including those requirements developed
> pursuant to 40 CFR Part 51, subpart I (NSR), Part 52.21 (PSD), Part 60
> (NSPS), Part 61 (NESHAPs), Part 63 (MACT), and Part 72 (Permits
> Regulation, Acid Rain), including limitations and conditions contained
> in operating permits issued under an EPA-approved program that has
> been incorporated into the SIP.

**FP**

> Filterable Particulate as measured by BAAQMD Method ST-15,
> Particulate.

**HAP**

> Hazardous Air Pollutant. Any pollutant listed pursuant to Section
> 112(b) of the Act. Also refers to the program mandated by Title I,
> Section 112, of the Act and implemented by 40 CFR Part 63.

**Major Facility**

> A facility with potential emissions of: (1) at least 100 tons per year
> of regulated air pollutants, (2) at least 10 tons per year of any
> single hazardous air pollutant, and/or (3) at least 25 tons per year
> of any combination of hazardous air pollutants, or such lesser
> quantity of hazardous air pollutants as determined by the EPA
> administrator.

**MFR**

> Major Facility Review. The District\'s term for the federal operating
> permit program mandated by Title V of the Federal Clean Air Act and
> implemented by District Regulation 2, Rule 6.

**MOP**

The District\'s Manual of Procedures.

**NAAQS**

National Ambient Air Quality Standards

**NESHAPS**

National Emission Standards for Hazardous Air Pollutants. See in 40 CFR
Parts 61 and 63.

**NMHC**

Non-methane Hydrocarbons (Same as NMOC)

**NMOC**

> Non-methane Organic Compounds (Same as NMHC)

**NOx**

Oxides of nitrogen.

**NSPS**

> Standards of Performance for New Stationary Sources. Federal standards
> for emissions from new stationary sources. Mandated by Title I,
> Section 111 of the Federal Clean Air Act, and implemented by 40 CFR
> Part 60 and District Regulation 10.

**NSR**

> New Source Review. A federal program for pre-construction review and
> permitting of new and modified sources of pollutants for which
> criteria have been established in accordance with Section 108 of the
> Federal Clean Air Act. Mandated by Title I of the Federal Clean Air
> Act and implemented by 40 CFR Parts 51 and 52 and District Regulation
> 2, Rule 2. (Note: There are additional NSR requirements mandated by
> the California Clean Air Act.)

**Offset Requirement**

> A New Source Review requirement to provide federally enforceable
> emission offsets for the emissions from a new or modified source.
> Applies to emissions of POC, NOx, PM10, and SO2.

**Phase II Acid Rain Facility**

> A facility that generates electricity for sale through fossil-fuel
> combustion and is not exempted by 40 CFR 72 from Titles IV and V of
> the Clean Air Act.

**POC**

Precursor Organic Compounds

**PM**

Particulate Matter

**PM10**

Particulate matter with aerodynamic equivalent diameter of less than or
equal to 10 microns

**Process Unit**

For the purpose of start-up and shutdown reporting, a process unit is
defined as in 40 CFR Part 60 Subpart GGG: Process Unit means components
assembled to produce intermediate or final products from petroleum,
unfinished petroleum derivatives, or other intermediates; a process unit
can operate independently if supplied with sufficient feed or raw
materials and sufficient storage facilities for the product.

**PSD**

> Prevention of Significant Deterioration. A federal program for
> permitting new and modified sources of those air pollutants for which
> the District is classified \"attainment\" of the National Air Ambient
> Quality Standards. Mandated by Title I of the Act and implemented by
> both 40 CFR Part 52 and District Regulation 2, Rule 2.

**Start-up**

> For reporting purposes only, a start-up shall be defined as any of the
> following; the removal of boundary blinds, first fire to a furnace, or
> the introduction of process feed to a unit. A start-up only occurs
> following a shutdown unless it involves a newly constructed process
> unit.

**Shutdown**

> For reporting purposes only, a shutdown shall be defined as any of the
> following; there is no process feed to a unit, no furnace fires, or
> the boundary blinds are installed.

**SIP**

> State Implementation Plan. State and District programs and regulations
> approved by EPA and developed in order to attain the National Air
> Ambient Quality Standards. Mandated by Title I of the Act.

**SO2**

Sulfur dioxide

> **THC**
>
> Total Hydrocarbons (NMHC + Methane)

**Title V**

> Title V of the federal Clean Air Act. Requires a federally enforceable
> operating permit program for major and certain other facilities.

**TOC**

Total Organic Compounds (NMOC + Methane, Same as THC)

**TPH**

Total Petroleum Hydrocarbons

**TRMP**

Toxic Risk Management Plan

**TSP**

Total Suspended Particulate

**VOC**

Volatile Organic Compounds

**Units of Measure:**

bhp = brake-horsepower

btu = British Thermal Unit

cfm = cubic feet per minute

> g = grams
>
> gal = gallon

gpm = gallons per minute

hp = horsepower

> hr = hour
>
> lb = pound
>
> in = inches
>
> max = maximum
>
> m^2^ = square meter
>
> min = minute

mm = million

MMbtu = million btu

MMcf = million cubic feet

ppmv = parts per million, by volume

ppmw = parts per million, by weight

> psia = pounds per square inch, absolute

psig = pounds per square inch, gauge

> scfm = standard cubic feet per minute
>
> yr = year

APPENDIX B

Permit Evaluations for

Application 2035 MTBE Phaseout

Application 3782 Alkylation Expansion

Application 8028 Spare Tail Gas Unit, Phase I

Application 8247 Spare Tail Gas Unit, Phase II

**EVALUATION REPORT**

**VALERO REFINERY**

**MTBE PHASEOUT PROJECT**

**APPLICATION 2035, PLANT 12626**

**[INTRODUCTION]{.underline}**

In 1996, the refineries had to produce cleaner burning gasolines \--
California Air Resources Board (CARB) Phase II gasoline \-- to achieve
emission reductions from gasoline-fueled vehicles as required by the
1990 amendments to the Federal Clean Air Act and the California Clean
Air Act. The reformulated gasoline evaporates less readily, reduces
emissions of smog-forming and toxic compounds, and burns more
completely. To produce these cleaner burning gasolines, the refiners had
to meet tougher fuel specifications for Reid vapor pressure, aromatics,
olefins, distillation temperatures (T~50~ and T~90~), sulfur and
benzene. In addition, the refineries were required to blend oxygenated
compounds into the gasoline to lower carbon monoxide emissions from the
vehicle exhaust. The oxygenated gasolines had to contain at least 2.0 %
oxygen content, by weight. All gasolines sold in the San Francisco Bay
Area had to meet this requirement starting on November 1, 1992.

Valero Refining Company (henceforth Valero) blended Methyl Tertiary
Butyl Ether (MTBE) into their gasoline to meet the required oxygen
content. MTBE has one oxygen atom and contains 18.2% oxygen, by weight.
To meet the required oxygen level, Valero blended approximately 12%
MTBE, by volume, into the gasoline.

In Application number 6968, Valero was authorized to import MTBE to the
refinery via ship and to store its product in the S-207 external
floating roof storage tank. Later, Valero was approved in Application
9425 to build and operate a MTBE Manufacturing Facility (S-211), which
significantly reduce their dependency on imported MTBE to the Benicia
Refinery.

The Governor of California has now called for a ban on MTBE because of
environmental concerns stemming from groundwater contamination. The
refineries have until December 31, 2002 to remove MTBE entirely from the
gasoline and replace it with a more environmental friendly oxygenated
product. Valero has decided to replace MTBE with ethanol. It has one
oxygen atom and contains 34.8% oxygen, by weight. Because of the higher
oxygen content, only half as much ethanol as MTBE is needed to meet the
2.0 wt% oxygen level.

Valero has submitted Application #2035 to obtain the necessary
Authorities to Construct and Permits to Operate for plant modifications
to effect the changeover to ethanol. The project will require
modifications to existing processing facilities, such as, pumps,
instrumentation, vessel internal hardware, and piping changes. The new
operation will not entail any new sources.

**[Hydrofining Process]{.underline}**

Valero is proposing to minimize gasoline sulfur levels. In the
hydrofining process, Valero utilizes a catalyst in the presence of
hydrogen to remove more than 99% of the sulfur from the processed
stream. When the hydrofiner's catalyst is being replaced, the gasoline
stream that is being produced has a higher sulfur content. This stream
must be segregated and blended sparingly into the gasoline to avoid
non-compliance with the sulfur limit. Valero is proposing to store the
high sulfur component produced during the shutdown in either S-163 or
S-77 storage tank. This product will be recycled back through the
hydrofiner after the catalyst is changed out. To insure adequate
capacity to handle the additional load, the S-1024 Light Cat Naphtha
Hydrofiner (LCNHF) will have the internal trays in its stripper tower
modified and an additional recycle pump will be added. These
modifications will increase the capacity of the LCNHF from 21 MB/D to 24
MB/D (calendar year average). This increased capacity will be used for
the recycled material in need of sulfur removal and any additional
material that may require sulfur removal prior to blending. Some
modifications will be made to the connections and trays in the existing
Cat Naphtha Splitter Tower to insure proper delivery of the high sulfur
component to the LCNHF.

**[Vapor Pressure Minimization]{.underline}**

Blending one half as much ethanol into the base gasoline instead of MTBE
increases the vapor pressure of the finished motor gasoline. The vapor
pressure of the base hydrocarbon stock must be reduced to continue to
meet the gasoline RVP specification. Butane is one of the most volatile
hydrocarbon components and has been targeted by Valero to be removed in
the fractionation process. The saturated pentane will go through an
additional fractionation step to remove unwanted butane prior to its
storage. This will occur in the existing tower in the Alkylation Unit
(S-1007) that is currently used to separate butanes from alkylate. The
displaced alkylate will be treated in the existing tower of the MTBE
Manufacturing Unit (S-211) which is no longer needed. The internal trays
in this larger tower will be modified for the removal of additional
butane from the alkylate before it is sent to storage.

**[MTBE Manufacturing Unit Shut Down and Dimersol
Reliability]{.underline}**

The MTBE manufacturing process used two feedstocks: a light hydrocarbon
containing isobutylene and methanol. Because of the shutdown of the MTBE
Manufacturing Unit, the isobutylene feed will be routed to the
Alkylation Unit. To accommodate this additional isobutylene feed, some
of the current propylene feed will be sent to the existing S-1012
Dimersol Unit. The S-1007 Alkylation Unit and the S-1012 Dimersol Unit
will continue to be operated within their historical design rates.
Valero has experienced in the past fouling problems in the Dimersol Unit
due to corrosion buildup in the heat exchangers. Valero is proposing to
replace the tube material in the Dimerol Unit with a mild alloy to
improve the system reliability.

**[Ethanol Blending]{.underline}**

A mixture of gasoline/ethanol will readily pick up water as the blended
gasoline is transported by pipeline, ultimately resulting in a two-phase
product (gasoline plus water). To keep the water out of the finished
gasoline, ethanol would need to be blended with the gasoline at the
distribution terminal. Thus, Valero will produce a gasoline base stock,
called CARBOB, that is formulated to be blended with ethanol at the
local truck loading racks just prior to delivery to the service
stations. The Benicia Marketing Terminal (Plant #12611) handles about
10-15% of the refinery's gasoline production. Ethanol will be blended
into the CARBOB at this site. Application #2391 has been submitted for
the necessary modifications at the Benicia Marketing Terminal. For
completeness, both applications will be cross referenced, as
appropriate.

Valero has an existing truck unloading station (S-209) and a storage
tank (S-210) which was used to provide the methanol feed stock to the
MTBE Manufacturing Unit (S-211). Since these sources are no longer
needed for MTBE production, they will be used to receive and store
ethanol prior to blending it into the gasoline. Pumps, piping and
instrumentation will be installed to transport and blend the ethanol at
the truck racks of the marketing terminal.

The affected equipment based on the above changes for the entire MTBE
Phaseout Project is as follows:

**[Valero Benicia Refinery (Plant #12626)]{.underline}**

Modification Alteration Condition Changes

S-40 Steam Boiler (Administrative)

S-77 Floating Roof Tank (Store LCNHF)

S-163 Floating Roof Tank (Store LCNHF)

S-207 Mogas/MTBE Storage Tank yes

S-209 Methanol Unloading Station yes

S-210 Methanol Tank yes

S-211 MTBE Production Unit yes

S-1007 Alkylation Unit yes

S-1014 Cat Light Ends Splitter yes

S-1024 LCNHF yes

S-1012 Dimersol Unit yes

**[Valero Marketing Terminal (Plant #12611)]{.underline}**

S-1 Tank Truck Loading yes

S-2 Tank Truck Loading yes

**[EMISSIONS SUMMARY]{.underline}**

Fugitive Emissions

Valero intends to install 265 valves, 6 pumps and 795 flanges
(connectors) to be used in light and heavy hydrocarbon services at both
facilities. The POC emissions from the additional fugitive equipment
were estimated at 0.869 ton/year with 0.571 ton/year attributable to
refinery operations and 0.289 ton/year chargeable to the Benicia
Marketing Terminal. The emission factors were based on the CAPCOA
correlation equations and screening values. The District approved the
use of the CAPCOA correlation equations for determining the mass rate of
emissions from fugitive equipment during the last plant renewal cycle
for Valero. The emissions factors are:

Average Emission Factor

[(lb/day/comp)]{.underline}

Valves 0.00249

Pumps 0.25

Flanges/Connectors 0.0034

**FUGITIVE EMISSIONS**

**MTBE PHASEOUT PROJECT**

**Valves Pumps Flanges/Connectors**

**[Count]{.underline} [TPY]{.underline} [Count]{.underline}
[TPY]{.underline} [Count]{.underline} [TPY]{.underline}
[Total]{.underline}**

**[Benicia Marketing]{.underline}**

**[Terminal]{.underline}**

**Plant #12611**

S-1 and S-2 Bulk 50 0.023 4 0.183 150 0.093 0.298

Loading Station

**[Benicia Refinery]{.underline}**

**Plant #12626**

S-211 Alkylate 20 0.009 60 0.037 0.046

Debutanizer

(MTBE Tower)

S-1007 20 0.009 60 0.037 0.046

C-5 Debutanizer

S-1012 10 0.005 30 0.019 0.023

Dimersol Unit

S-1014 Cat 10 0.005 30 0.019 0.023

Light End Splitter

S-1024 LCNHF 20 0.009 1 0.046 60 0.037 0.092

Naphtha Rerun 75 0.034 1 0.046 225 0.140 0.219

Sulfur Analyzer 30 0.014 90 0.039 0.053

Contingency 30 0.014 90 0.056 [0.069]{.underline}

**Total 0.869**

Tank Emissions

There will be a net decrease in POC emissions due to storing ethanol
instead of methanol in the S-210 storage tank. The Reid vapor pressure
of ethanol is about ½ of that of methanol (2.3 psia ethanol as compared
to 4.5 psia methanol). The annual throughput limit for S-210 will remain
unchanged (575,000 barrels/day).

Process Units

The modifications made to the internal trays of the S-1014 Cat Naphtha
Splitter, S-1024 LCNHF and S-211 Alkylate Debutanizer Tower will not
result in any increase in emissions from these units. The throughput
capacity for S-1024 LCNHF will increase by an average of 3 MBbl/day.
This increase is needed to handle the rerun of elevated sulfur streams
stored for reprocessing during periods when the Hydrofiner's catalyst is
being replaced. This increase in daily capacity will not debottleneck
the refinery. The refinery is limited to processing no more than 135,000
barrels of crude oil per day.

**PLANT CUMULATIVE INCREASE**

POC: 0 (existing) + 0.571 (proposed: refinery only) = 0.571 TPY

NOx: 0 (existing) + 0.0 (proposed) = 0.0 TPY

SO2: 0 (existing) + 0.0 (proposed) = 0.0 TPY

PM10: 0 (existing) + 0.0 (proposed) = 0.0 TPY

TSP: 0 (existing) + 0.0 (proposed) = 0.0 TPY

CO: 0 (existing) + 0.0 (proposed) = 0.0 TPY

**[TOXIC RISK SCREEN]{.underline}**

This proposed project including the Benicia Marketing Terminal will not
emit benzene in amounts at or above its threshold listed in Table
2-1-316. Therefore, a toxic risk screen is not required.

Trigger Level

[Lb/year]{.underline} [Lb/year]{.underline}

Benzene 6.61 6.7

**[BEST AVAILABLE CONTROL TECHNOLOGY]{.underline}**

BACT is triggered for POC emissions per Regulation 2, Rule 2 for sources
which emit in excess of 10 lbs/day per Section 301.1. For this proposed
project involving emissions from fugitive components, BACT is not
triggered for the fugitive POC emissions. Nonetheless, all the valves,
pumps and flanges/connectors placed in service as a result of the MTBE
Phaseout Project will satisfy the BACT requirements.

**[COMPLIANCE]{.underline}**

The internal floating roof storage tank (S-210) holding ethanol should
continue to comply with Regulation 8, Rule 5 \"Storage of Organic
Liquids\" including Section 325 which requires welded tanks with zero
gap secondary seals. It has liquid mounted primary and secondary seals.
The internal floating roof tank (S-210 ) is subject to the NSPS in
subpart kb of 40 CFR 60. It will comply with NSPS since it will be
equipped with a continuous liquid mounted primary seal.

The fugitive equipment should comply with the Standards of Regulation 8,
Rule 18 for Valves, Pumps and Flanges. The leak standards for valves,
pumps and flanges will be 100 ppm, 500 PPM and 100 ppm, respectively.

VALVES \-- Most valves will use graphite packing which is the best
material available to achieve low emissions in a wide variety of
applications. All valves will be required to meet a leak rate of no more
than 100 ppm.

PUMPS \-- The pumps will be equipped with double mechanical seals and an
approved Inspection and Maintenance (I&M) Program to reduce emissions
from pump seals. A leak standard of 500 PPM will be required to be met.

FLANGES \-- The flanges will use graphite or equivalent designed flange
gaskets to reduce POC fugitive emissions. A leak standard of 100 PPM
will be required to be met.

The requirements of CEQA have been satisfied through a Negative
Declaration granted by the Bay Area Air Quality Management.

The project is over 1000 feet from the nearest school and is therefore
not subject to the public notification requirements of Regulation
2-1-412.

This proposed project should not pose a health threat to the general
public.

BACT, PSD and NESHAPS are not triggered.

**[CALIFORNIA ENVIRONMENTAL QUALITY ACT]{.underline}**

On May 30, 2001, the Bay Area Air Quality Management, acting as lead
agency, approved a Final Negative Declaration for the MTBE Phaseout
Project which satisfies the requirements under CEQA. A copy of the
Negative Declaration is attached.

**[OFFSETS]{.underline}**

Offsets are required for this proposed project for POC since the
plant\'s emissions are greater than 15 tons per year (Regulation
2-2-302). The offsets required for POC emissions for the entire project
are 0.869 TPY \[0.571 TPY from the refinery operations and 0.289 TPY
from the Benicia Marketing Terminal\]. Valero will use contemporaneous
POC emissions reduction credits occurring from the shutdown of the MTBE
Manufacturing Unit (S-211) and the MTBE shipping operation associated
with the MTBE Receiving Tank (S-207). Offsets for S-211 and S-207 were
provided in Applications number 9425 and 6968, respectively.

In Application #9425, Valero had to offset 4.95 tons/year of POC
emissions to allow them to install and operate the following equipment:

Fugitives Equipment

[TPY]{.underline} [TPY]{.underline} [Total]{.underline}

S-209 Methanol Unloading Station 0.19 0.19

S-210 Methanol Tank 0.35 0.35

0.16 0.16

S-211 MTBE Manufacturing Unit [4.25]{.underline} [4.25]{.underline}

4.60 0.35 4.95

The offsets required for the project were 5.94 TPY \[4.95 x 1.2\].
Valero surrendered Banking Certificate #87 holding 72.4 TPY of POC
credits to cover this offset obligation. Banking Certificate \# 277 was
issued back to Valero to cover the unused POC credits.

When the project was actually completed, Valero had underestimated the
fugitive emissions count for the MTBE project. Actual emissions from
fugitives were 11. 5 tons/year of POC instead of 4.6 tons/year. In
accordance with their permit conditions (Condition #9296) which allowed
for offset adjustments prior to permit issuance, Valero provided offsets
for an additional 8.28 tons/year (6.9 TPY x 1.2) of POC emissions.
Valero submitted Banking Certificate 347 having 33.672 TPY of POC
credits to satisfy this offset obligation. Banking Certificate #441 was
issued back to Valero in the amount of 25.392 to cover the balance.

The final totals for the project were:

Additional

Fugitives Equipment Fugitives

[TPY]{.underline} [TPY]{.underline} [TPY]{.underline}
[Total]{.underline}

S-209 Methanol Unloading Station 0.19 0.22 0.41

S-210 Methanol Tank 0.35 0.35

0.16 0.35 0.51

S-211 MTBE Manufacturing Unit [4.25]{.underline} [6.33]{.underline}
[10.58]{.underline}

4.60 0.35 6.90 11.56

In Application #6968, Valero had to offset 6.51 tons/year of POC
emissions to allow them to install and operate the following equipment
to import and store MTBE:

**POC EMISSIONS**

Fugitives Equipment

[TPY]{.underline} [TPY]{.underline} [Total]{.underline}

S-207 MTBE Storage Tank 1.44 1.58 3.02

Associated Ship Emissions [3.48]{.underline} [3.48]{.underline}

1.44 5.07 6.50

The POC offsets required for S-207 were 7.15 TPY \[6.5 x 1.1\]. Valero
surrendered Banking Certificate #86 which contained 122 tons/year of POC
credits. to cover this offset obligation. Banking Certificate \# 210 was
issued back to Valero to cover the unused POC credits.

As shown in the tables, the shutting down of the MTBE unit (S-211),
except for the tower, and the MTBE ship operation will generate more
than enough contemporaneous POC emissions reduction credits to offset
the increase in POC emissions from the proposed project. The following
table shows the POC credits due to Valero due to the phasing out of
MTBE.

**ALLOWABLE POC CREDITS**

Allowed

Baseline POC

[Shutdown]{.underline} [tons/year]{.underline} [Adjustments]{.underline}
[Credit]{.underline}

(S-207)

MTBE Tank and Yes 3.48 0.000^1^ 3.48

Marine Related Emissions (No Ship Emissions) (offset level)

(Banking Certificate 86)

(S-211)

MTBE Production Unit Yes 4.25 0.000^2^ 4.25

(No MTBE) (Offset level)

(Banking Certificate 87)

Yes 6.33 0.000^2^ 6.33

(More fugitives) (Offset level)

(Banking Certificate 347)

> Total 14.06

^1^There are no regulations that apply to POC emissions from ships and
assist tugboats

^2^All fugitive components were equipped with present BACT controls

The allowable POC credits are 14.06 tons. After providing 0.869 tons to
offset this project increase which includes the Benicia Marketing
Terminal, Valero will have 13.191 tons of POC credits remaining. Valero
has requested to receive a banking certificate for the POC credits in
excess of those needed to meet their offset obligation. Condition number
1 for S-211 which allowed up to 10.58 TPY of POC emissions has been
deleted. Condition number 1 for S-207 has been modified to back out the
3.48 TPY of POC emissions from the ship and to reflect only POC
emissions from the storage tank.

Valero has also requested to receive credits for NO~x~, SO~2~ and PM10
emissions due to the elimination of ship emissions from the importation
of MTBE. Since the MTBE Phaseout Project does not involve any increase
in these pollutants, Valero would need to submit a formal banking
application to the District to bank these emissions.

**[CONDITIONS]{.underline}**

**[BENICIA REFINERY (PLANT #12626)]{.underline}**

**S-211 [Alkylate Debutanizer at]{.underline} MTBE Unit (Condition
9296)**

1\. [Deleted]{.underline} ~~Total fugitive POC emissions from S-208
shall not exceed 10.58 tons in any rolling 365 consecutive day period.
The owner/operator shall submit a revised pump, valve and flange count
within 15 days of start up in order to show compliance with this permit
condition. If fugitive emissions from this source exceed 4.25 tons/year,
then the District may adjust the cumulative increase attributable to
this permit application before the issuance of the Permit to Operate.~~

2\. [Deleted]{.underline} ~~The owner/operator of S-208 shall implement
an inspection and maintenance program for all pumps, valves and flanges
in accordance with District Regulation 8, Rules 18, 25 and 28.~~

[3. Deleted]{.underline} ~~The fugitive equipment shall have a leak
concentration not to exceed 500 ppm for valves, 500 ppm for flanges and
1000 ppm for pumps above background (expressed as methane measured at 1
cm) unless the leaks are repaired or minimized no later than 7 days in
accordance with Regulation 8, Rules 18, 25 and 28.~~

[4. The MTBE unit shall be completely shutdown except for the MTBE tower
used to remove butane from the Alkylate as part of the MTBE Phaseout
Project. \<Basis: Banking Credits\>]{.underline}

**S-1007 Alkylation Unit**

**S-1014 Virgin Light Ends Splitter**

**S-1012 Dimersol Unit**

**(Condition 18043)**

[1. Total fugitive POC emissions from the MTBE Phaseout Project at the
Benicia Refinery (Plant #12626) shall not exceed 0.571 ton in any
rolling 12 consecutive month period. The owner/operator shall submit a
revised pump, valve and flange count within 15 days of start up in order
to show compliance with this permit condition. If fugitive emissions
from this source exceed 0.571 ton/year, then the District may adjust the
cumulative increase attributable to this permit application before the
issuance of the Permit to Operate]{.underline}. [\<Basis: Cumulative
Increase, Toxics\>]{.underline}

[2. The owner/operator shall implement an inspection and maintenance
program for all pumps, valves and flanges used in this MTBE Phaseout
Project at the Benicia Refinery (Plant 12626) in accordance with
District Regulation 8, Rule 18. \<Basis: Compliance Verification,
Periodic Monitoring\>]{.underline}

[3. The fugitive equipment used in this MTBE Phaseout Project at the
Benicia Refinery (Plant #12626) shall have a leak concentration not to
exceed 100 ppm for valves, 100 ppm for flanges and 500 ppm for pumps
above background (expressed as methane measured at 1 cm) unless the
leaks are repaired or minimized no later than 7 days in accordance with
Regulation 8, Rules 18. \<Basis: RACT, Cumulative Increase,
Toxics\>]{.underline}

**S-1024 Light Cat Naphtha Hydrofiner**

**(New Conditions to be added to Condition #10574)**

[1. The total throughput of product at this source shall not exceed
24,000 barrels per day, as averaged over any calendar year. \<Basis:
Cumulative Increase, Toxics\>]{.underline}

[2. The total daily throughput of product at this source shall be
recorded daily in a District approved log. This record shall be retained
for a period of at least five years from date of entry. It shall be kept
on site and made available to the District staff upon request. \<Basis:
Recordkeeping\>]{.underline}

**S-209 ~~Methanol~~ [Ethanol]{.underline} Unloading Station (Condition
#9296)**

1\. The transport trucks shall travel on paved roads at all times inside
of [this]{.underline} ~~the Exxon~~ Facility[. \<Basis: Cumulative
Increase\>]{.underline}

2\. All deliveries [to S-209 Unloading Station]{.underline} of
[ethanol]{.underline} methanol shall be from the transport trucks unless
[the operator]{.underline} ~~Exxon~~ first receive prior written
approval from the APCO to use other delivery modes. [\<Basis: Cumulative
Increase, Toxics\>]{.underline}

3\. [Deleted]{.underline} ~~Exxon shall pave 9600 square feet of
unpaved/unvegetated surface as a part of this project in advance of any
operation of this new facility.~~

4\. The total number of truck deliveries of ~~methanol~~
[ethano]{.underline}l at [this facility]{.underline} ~~Exxon~~ shall not
exceed 2920 trucks in any rolling 12 consecutive month period. [\<Basis:
Cumulative Increase\>]{.underline}

5\. The dispensed [ethanol]{.underline} ~~methanol~~ from the transport
trucks shall be delivered to the S-210 ~~methanol~~
[ethanol]{.underline} tank or any storage tank with equivalent controls.
~~subject to advance written approval by the APCO.~~ [\<Basis:
Cumulative Increase\>]{.underline}

6\. Total fugitive POC emissions from S-209 shall not exceed 0.41 ton in
any rolling 12 consecutive month period. ~~The owner/operator shall
submit a revised pump, valve and flange count within 15 days of start up
in order to show compliance with this permit condition. If fugitive
emissions from this source exceed 0.41 ton/year, then the District may
adjust the cumulative increase attributable to this permit application
before the issuance of the Permit to Operate.~~ [\<Basis: Cumulative
Increase, Toxics\>]{.underline}

7\. The owner/operator of S-209 shall implement an inspection and
maintenance program for all pumps, valves and flanges in accordance with
District Regulation 8, Rules 18 ~~25 and 28~~. [\<Basis: Compliance
Verification, Periodic Monitoring\>]{.underline}

8\. The fugitive equipment shall have a leak concentration not to exceed
100 ppm for valves, 100 ppm for flanges and 500 ppm for pumps above
background (expressed as methane measured at 1 cm) unless the leaks are
repaired or minimized no later than 7 days in accordance with Regulation
8, Rules 18~~, 25 and 28~~. [\<Basis: BACT, Cumulative Increase,
Toxics\>]{.underline}

9\. The total number of truck deliveries of ~~methanol~~
[ethanol]{.underline} shall be recorded weekly in a District approved
log and totalized monthly. This record shall be retained for a period of
at least ~~2~~ [5]{.underline} years from date of entry. It shall be
kept on site and made available to District staff upon request.

[\<Basis: Recordkeeping\>]{.underline}

**S-210 ~~Methanol~~ [Ethanol]{.underline} Tank (Condition #9296)**

1\. The total throughput of product from S-210 shall not exceed 575,000
barrels of [ethanol and/or]{.underline} methanol in any rolling 12
consecutive month period. [\<Basis: Cumulative Increase,
Toxics\>]{.underline}

2\. Total POC emissions from S-210 Storage Tank, including associated
fugitive POC emissions, shall not exceed 0.87 ton in any rolling 12
consecutive month period~~. The owner/operator shall submit a revised
pump, valve and flange count within 15 days of start up in order to show
compliance with this permit condition. If fugitive emissions from the
fugitive equipment exceed 0.16 ton/year, then the District may adjust
the cumulative increase attributable to this permit application before
the issuance of the Permit to Operate.~~ [\<Basis: Cumulative Increase,
Toxics\>]{.underline}

3\. The owner/operator of S-210 shall implement an inspection and
maintenance program for all pumps, valves and flanges in accordance with
District Regulation 8, Rules 18~~, 25 and 28~~. [\<Compliance
Verification, Periodic Monitoring\>]{.underline}

4\. The fugitive equipment shall have a leak concentration not to exceed
100 PPM for valves, 100 PPM for flanges and 500 PPM for pumps above
background (expressed as methane measured at 1 cm) unless the leaks are
repaired or minimized no later than 7 days in accordance with Regulation
8, Rules 18~~, 25 and 28~~. [\<Basis: BACT, Cumulative Increase,
Toxics\>]{.underline}

5\. The S-210 internal floating roof tank shall only store
[ethanol]{.underline} ~~methanol~~ unless written authorization is
received from the APCO allowing the use of another product in advance of
any use of such product. [\<Basis: Cumulative Increase,
Toxics\>]{.underline}

6\. The total monthly throughput of [ethanol]{.underline} ~~methanol~~
withdrawn from the S-210 Storage Tank Shall be recorded in a District
approved log. This record shall be retained for a period of at least
~~2~~ [5]{.underline} years from date of entry. It shall be kept on site
and made available to District staff upon request.

[\<Basis: Recordkeeping\>]{.underline}

**[S-40 Steam Boiler (Condition #9296)]{.underline}**

[1. The firing rate of the S-40 boiler shall not exceed 218 million Btu
per hour. \<Basis: Cumulative Increase, Regulation 9 , Rule
10\>]{.underline}

~~1~~ [2]{.underline}. The steam boiler (S-40) shall be equipped with
Low NOx burners and flue gas recirculation. [\<Basis: BARCT, Regulation
9, Rule 10\>]{.underline}

~~2~~ [3]{.underline}. The NOx concentration shall not exceed 30 ppmv,
dry, corrected to 3 % oxygen, as averaged ove ra calendar year.
[\<Basis: BARCT\>]{.underline}

~~3~~ [4]{.underline}. The CO concentration shall not exceed 400 ppmv,
dry, corrected to 3 % oxygen. [\<Basis: BARCT\>]{.underline}

~~4~~ [5]{.underline}. The scrubber system upstream of S-40 Boiler shall
have a yearly averaged (calendar year) sulfur concentration not to
exceed 65 PPM, by volume. [\<Basis: BARCT\>]{.underline}

~~5~~ [6]{.underline}. Deleted ~~The owner/operator shall conduct a
District approved source test no later than 30 days after start up to
verify compliance with Conditions number 2 and 3. All source test shall
be done in accordance with the District\'s Manual of Procedures. Exxon
shall install all necessary source test ports, subject to the approval
of the Manager of Source Test in the District Technical Section, prior
to any operation of these sources. The results shall be delivered to the
District no later than 30 days from the date of test.~~

~~6~~ [7]{.underline}. [The owner/operator]{.underline} ~~Exxon~~ shall
maintain daily records, in a District approved log, of the sulfur
concentration required in Condition number 4. These records shall be
retained for a period of at least ~~2~~ [5]{.underline} years from date
of entry. The logs shall be kept on site and made available to District
staff upon request. [\<Basis: Recordkeeping\>]{.underline}

**[S-207 Mogas/Components Storage Tank (Condition #10797)]{.underline}**

1\. The total release of emissions from this S-207 [Storage
tank]{.underline} ~~project for delivery and storage of MTBE, which
includes the cargo ships and tugs in District waters,~~ shall not exceed
[4.62 tons of POC emissions]{.underline} in any rolling 365 consecutive
day period the following limit: [\<Basis: Cumulative Increase,
Toxics\>]{.underline}

~~Pollutant Tons~~

~~NOx 36.7~~

~~CO 3.7~~

~~POC 8.1~~

~~SO2 9.5~~

~~PM10 1.6~~

2\. [Deleted]{.underline} ~~The total release of POC emissions from this
S-207 MTBE project shall not exceed 140 pounds in any rolling 24
consecutive hour period. This POC total is defined as the sum of all
project-related emissions from: (a) the storage tank; (b) valves, pumps
and flanges (fugitive emissions); and (c) the cargo ships and tugs in
District waters, assist tugs, tugs during maneuvering and (d)
transferring of the MTBE from the cargo carrier to the S-207 Receipt
Tank.~~

3\. The owner/operator of S-207 shall implement an inspection and
maintenance program for all pumps, valves and flanges associated with
the land-based aspects of this project in accordance with District
Regulation 8~~, Rules 18, 25 and 28~~. [\< Basis: Compliance
Verification, Periodic Monitoring\>]{.underline}

4\. The S-207 External Roof Storage Tank shall store ~~MTBE and/or~~
mogas[/components]{.underline} only.

[\<Basis: Cumulative Increase, Toxics\>]{.underline}

5\. [Deleted]{.underline} ~~The total throughput of MTBE at S-207 shall
not exceed 5,800,000 barrels in any rolling 365 consecutive day
period.~~

6\. The total throughput of mogas[/components]{.underline} at S-207
shall not exceed 16,936,400 barrels in any rolling 365 consecutive day
period. [\<Basis: Cumulative Increase, Toxics\>]{.underline}

7\. The total daily throughput of ~~MTBE and~~
mogas[/components]{.underline} withdrawn from the S-207 Storage Tank
shall be recorded in a District approved log. This record shall be
retained for a period of at least ~~two~~ [five]{.underline} years from
date of entry. It shall be kept on site and made available to the
District staff upon request[. \<Basis: Recordkeeping\>]{.underline}

8\. [Deleted]{.underline} ~~The owner/operator shall maintain daily
records (calendar day), in a District approved log, for: (1) the total
number of MTBE deliveries by ship and barge, (2) ship and tug boat fuel
usage (actual or estimated if not logged in) in District waters
attributable to the S-207 project only, (3) type of fuel, (4) hours of
ship operation in District waters attributable to the S-207 project
only, (5) size capacity of ship and barge in DWT. In addition, the daily
throughput of MTBE transferred at the Exxon dock from the cargo ship or
barge to S-207 shall be recorded in a District approved log. All records
shall be retained for a period of at least two years from the date of
entry. This log shall be kept on site and made available to the District
on request.~~

~~If a cargo carrier for this S-207 project calls on multiple ports,
such as in Martinez, Exxon will be charged for all round trip emissions
from the port to the existing Exxon dock in Benicia and back to port.
For the purposes of record keeping, Exxon need to maintain records only
for the portion of the project chargeable to their operation.~~

9\. [Deleted]{.underline} ~~On the day of MTBE delivery at Exxon and
each day of MTBE transfer from the cargo carrier to S-207, the
owner/operator shall determine, using a District approved calculation
procedure, the total POC emissions from this project to verify
compliance with Conditions Number 2. These daily totals shall be entered
into the log and shall be summarized monthly. A Quarterly summary report
shall be submitted to the District by the 10th day of the month
following the close of the quarter. All records shall be retained for at
least two years from date of entry. This log shall be kept on site and
made available to the District staff upon request.~~

**[The conditions for the Benicia Marketing Terminal are shown for
completeness purposes only. These changes will be handled in Application
#2391.]{.underline}**

**[Valero Marketing Terminal (Plant #12611)]{.underline}**

**[Condition #18042]{.underline}**

S-1 Tank Truck Loading

S-2 Tank Truck Loading

1\. ~~Exxon\'s vapor recovery system shall not emit into the atmosphere
more than~~ [S-1 and S-2 shall not be operated unless abated A-1 Carbon
Adsorption Vapor Recovery System. Abated emissions from S-1 and S-2
shall not exceed]{.underline} 7.2 grams of precursor organic compounds
per cubic meter (0.06 lbs per 1000 gallons) of organic loaded.

[\<Basis: Cumulative Increase, Toxics\>]{.underline}

2\. The total [abated]{.underline} daily precursor organic compound
emissions from [S-1 and S-2]{.underline} ~~Exxon's vapor~~ ~~recovery
system~~ shall not exceed 56 lbs per day including ethane but excluding
fugitive emissions. [\<Basis: Cumulative Increase, Toxics\>]{.underline}

3\. [Owner/operator]{.underline} ~~Exxon~~ shall install a continuous
hydrocarbon emissions monitor at the exhaust outlet of the vapor
recovery system. This detector shall continuously measure hydrocarbon
concentration in PPM as C4. This monitor shall be coupled to a 2-stage
alarm system. The first stage shall sound an alarm when the exhaust
concentration reaches 8000 PPM (as C4). The second stage shall shut down
the loading rack when the exhaust concentration reaches 10,000 PPM (as
C4). [\<Basis: Monitoring\>]{.underline}

4\. The average hydrocarbon concentration shall not exceed 2600 PPM (as
C4) at the exhaust outlet of the vapor recovery system for the entire
cycle of each carbon bed. [\<Basis: Cumulative Increase\>]{.underline}

5\. [Owner/operator]{.underline} ~~Exxon~~ shall install a continuous
strip chart recorder to record the temperature of each of the carbon
beds. If the temperature exceeds 195^o^F, an alarm shall sound and no
gasoline loading shall occur[. \<Basis: Monitoring, Public Safety,
Public Nuisance, Odors, Cumulative Increase, Toxics\>]{.underline}

6\. The monitoring equipment required in Condition #3 shall be subject
to the procedure set forth in District Regulation 1 Section 522 with the
exception of Regulation 1-522.5. All monitors shall be calibrated
weekly. [\<Basis: Monitoring Accuracy\>]{.underline}

7\. [Combined]{.underline} ~~Exxon\'s~~ average daily throughput [of S-1
and S-2]{.underline} shall not exceed the lesser of: (a) 270,000 gallons
per hour nor 950,000 gallons per day, or; (b) the CARB certified
terminal gasoline limits. [\<Basis: Cumulative Increase,
Toxics\>]{.underline}

8\. All equipment at this facility, which is subject to Regulation 8-33,
shall be maintained in good operating conditions at all times. The
maintenance of the vapor recovery unit shall be conducted in accordance
with current manufacturer\'s recommendations[. \<Basis:
RACT\>]{.underline}

9\. All monitoring and maintenance records required for the vapor
recovery system at this facility, which is the subject to Regulation
8-33, shall be kept on site for ~~two~~ [five]{.underline} years from
the date of entry and made available to the APCO upon request. [\<Basis:
recordkeeping\>]{.underline}

10\. No gasoline [or ethanol]{.underline} loading shall occur when the
temperature on any of the carbon beds reaches 195^o^F. At such time, the
vapor recovery unit shall be shut down. Owner/operator ~~Exxon~~ shall
follow the \"High Carbon Bed Temperature Shutdown\" procedures as set
forth in the current manufacturer\'s operating manual. \<[Basis:
Monitoring, Public Safety, Public Nuisance, Odors, Cumulative Increase,
Toxics\>]{.underline}

[11. Total fugitive POC emissions installed as part of the MTBE Phaseout
Project at S-1 and S-2 shall not exceed 0.298 ton in any rolling 12
consecutive month period. The owner/operator shall submit a revised
pump, valve and flange count within 15 days of start up in order to show
compliance with this permit condition. If fugitive emissions from this
source exceed 0.298 ton/year, then the District may adjust the
cumulative increase attributable to this permit application before the
issuance of the Permit to Operate. \<Basis: Cumulative Increase,
Toxics\>]{.underline}

[12. The owner/operator of S-1 and S-2 Bulk Truck Loadout Terminal shall
implement an inspection and maintenance program for all pumps, valves
and flanges in accordance with District Regulation 8, Rule 18. \<Basis:
Compliance Verification, Periodic Monitoring\>]{.underline}

[13. The fugitive equipment installed for the MTBE Phaseout Project
shall have a leak concentration not to exceed 100 PPM for valves, 100
PPM for flanges and 500 PPM for pumps above background (expressed as
methane measured at 1 cm) unless the leaks are repaired or minimized no
later than 7 days in accordance with Regulation 8, Rules 18. \<Basis:
RACT, Cumulative Increase, Toxics\>]{.underline}

**[AUTHORITY TO CONSTRUCT]{.underline}**

I recommend that conditional Authorities to Construct be granted to
Valero for the modifications and alterations indicated herein to
phaseout of MTBE at the Benicia Refinery:

**[Valero Benicia Refinery (Plant #12626)]{.underline}**

S-40 Steam Boiler (Administrative)

S-77 Floating Roof Tank (Store LCNHF)

S-163 Floating Roof Tank (Store LCNHF)

S-207 MTBE/Mogas Storage Tank: to be changed for Mogas only

S-209 Methanol Unloading Station: to be changed to ethanol station

S-210 Methanol Tank: to be changed to store ethanol

S-211 MTBE Production Unit: To be shutdown except for main tower

# Modification to internal trays {#modification-to-internal-trays .unnumbered}

S-1007 Alkylation Unit: Route isobutylene feed to Alkylate Unit

S-1014 Cat Light Ends Splitter: Modifications to connectors and trays

S-1024 LCNHF: modify internal trays on stripper tower

S-1012 Dimersol Unit: Changes to optimize unit's performance

## Replace tube material in heat exchanger with mild alloy {#replace-tube-material-in-heat-exchanger-with-mild-alloy .unnumbered}

**Banking Certificate**

I recommend that a banking certificate be issued to Valero for the POC
emissions reduction occurring as a result of the MTBE phaseout at the
time the credits are realized due to shutdowns and other modifications.
The preapproved POC credits eligible to be banked at a future date when
the project has been fully implemented are:

**13.191 TPY**

\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_

Douglas Wayne Hall

Supervising Air Quality Engineer

**EVALUATION REPORT**

**VALERO REFINING CO. - CALIFORNIA**

######## APPLICATION #3782 {#application-3782 .unnumbered}

# [BACKGROUND]{.underline} {#background-1 .unnumbered}

In 1996, the refineries had to produce cleaner burning gasoline \--
California Air Resources Board (CARB) Phase II gasoline \-- to achieve
emission reductions from gasoline-fueled vehicles as required by the
1990 amendments to the Federal Clean Air Act and the California Clean
Air Act. The reformulated gasoline evaporates less readily, reduces
emissions of smog-forming and toxic compounds, and burns more
completely. To produce these cleaner burning gasolines, the refiners had
to meet tougher fuel specifications for Reid vapor pressure, aromatics,
olefins, distillation temperatures (T~50~ and T~90~), sulfur and
benzene. In addition, the refineries were required to blend oxygenated
compounds into the gasoline to lower carbon monoxide emissions from the
vehicle exhaust. The oxygenated gasolines had to contain at least 2.0 %
oxygen content, by weight. All gasoline sold in the San Francisco Bay
Area had to meet this requirement starting on November 1, 1992.

Valero Refining Company (henceforth Valero) blended Methyl Tertiary
Butyl Ether (MTBE) into their gasoline to meet the required oxygen
content. MTBE has one oxygen atom and contains 18.2% oxygen, by weight.
To meet the required oxygen level, Valero blended approximately 12%
MTBE, by volume, into the gasoline.

The Governor of California has now called for a ban on MTBE because of
environmental concerns stemming from groundwater contamination. The
refineries have until December 31, 2002 to remove MTBE entirely from the
gasoline and replace it with a more environmental friendly oxygenated
product. Valero has decided to replace MTBE with ethanol. It has one
oxygen atom and contains 34.8% oxygen, by weight. Because of the higher
oxygen content, only half as much ethanol as MTBE is needed to meet the
2.0 wt% oxygen level.

Valero submitted Application #2035 to obtain the necessary Authorities
to Construct and Permits to Operate for plant modifications to effect
the changeover to ethanol. The Authority to Construct was granted on May
24, 2001. The project requires modifications to existing processing
facilities, such as, pumps, instrumentation, vessel internal hardware,
and piping changes. This operation is still under construction and will
not entail any new sources.

**[INTRODUCTION]{.underline}**

Valero has submitted this application, assigned number 3782, to make
minor changes in their operation to produce higher quantities of CARBOB
(base gasoline stock prior to blending MTBE or Ethanol). This increased
production will be accomplished by diverting about 2000 B/D of existing
propylene feed from the Dimersol Unit (S-1012) to the Alkylation Unit
(S-1007). Also, Valero would like the flexibility to feed imported
isobutane (via rail cars) to the Alkylation Unit as the market dictates.
A sulfuric acid catalyst will be used to convert olefin streams
consisting of propylenes and butylenes into gasoline blending
components.

Alkylate production will increase from a maximum annual design rate of
about 18,500 B/D to 22,800 B/D. The process will require additional
cooling to accommodate higher Alkylate production rates. Additional
steam will be needed for fractionation heat. The steam will come from
existing permitted and offset boilers (Sources S-237, S-1031 and S-1033)
at Valero. The new equipment for this proposed project includes:

1\. Additional exchangers, pumps, piping and instrumentation to install
an acid wash section.

2\. Additional piping to allow propylene and butylenes segregation.

3\. Alterations to the Alkylation (S-1007) and Cat Light Ends cooling
water system. The cooling water systems do not contain hydrocarbons.
This project will involve a minor modification to an existing operation
that will accommodate a higher Alykalate production rate.

This minor modification will not result in the emissions of any
regulated air pollutant not previously emitted in a quantity that would
cause the source to fail a toxic risk screen.

Upstream process units will not be affected by this project.

The alkylate will continue to be stored at the S-78 External Floating
Roof Tank. The alkylate will then be blended into several existing Mogas
storage tanks (S-79, S-80, S-82, S-84, S-86, S-92 and S-97) which have
unused capacities. Rail traffic due to the existing importing of
isobutane should not increase.

# [EMISSIONS]{.underline} {#emissions .unnumbered}

The proposed project is estimated to require the installation (net
count) of about: (a) 1 pump, (b) 100 valves, (c) 200 flanges/connectors
and (d) 2 pressure relief valves. The emissions from these additional
fugitive components are estimated to be 0.643 pound/day (235
pounds/year, 0.118 TPY). See attached table.

The project will result in a net increase in Alkylate throughput at S-78
External Floating Roof Tank (TK-1739). The increase will result in more
product turnovers. VOC emissions were estimated using EPA Tanks 4.0
equivalent calculation methodology. The VOC emissions from S-78 are
estimated to increase by 13 pounds per day. See attachment.

The acid wash section will include additional heat exchangers, pumps and
associated piping. The only emissions associated with the acid wash
section are two pumps in hydrocarbon service. The VOC emissions are
estimated to be about 0.27 pounds per day (99 lbs/yr).

Alkylate will be blended into the Mogas Tanks (S-79, S-80, S-82, S-84,
S-86, S-92 and S-97). The throughput capacities for these tanks will not
be exceeded. It should be noted that Dimate and LPG sales are reduced
when Alkylate production is increased. The amount of Dimate blended into
the affected Mogas Tanks will decrease when Alkylate is increased.

# CUMULATIVE INCREASE {#cumulative-increase .unnumbered}

235 (fugitives) + 13 (tank) + 99 (fugitives) = 347 lb/year (0.174 TPY)

**Existing Proposed Total**

**[(TPY)]{.underline} [(TPY)]{.underline} [(TPY)]{.underline}**

#  {#section-3 .unnumbered}

# POC 0.0 + 0.174 = 0.174 {#poc-0.0-0.174-0.174 .unnumbered}

####### TOXICS {#toxics .unnumbered}

This project does not trigger a toxic risk screen per Table 2-1-413. The
toxic contaminant of concern for this proposed project is benzene.
Alkylate contains about 0.3% benzene, by weight.

347 lb/yr x 0.003 lb Benzene = 1.04 lb/yr Benzene

Toxic trigger level is 6.7 lb/yr Benzene

# [COMPLIANCE]{.underline} {#compliance .unnumbered}

The alterations to the S-1007 Alkylation Unit which include mostly
additional fugitive components should continue to be in compliance with
applicable governing rules and regulations. The additional fugitive
components should comply with Regulation 8, Rule 18. The increase in VOC
emissions from the fugitive components (valves, flanges, pressure relief
valves, pumps) including the acid wash section will be less than 1
pound/day.

The Alkylate Storage Tank (S-1007) will continue to comply with
Regulation 8, Rule 5.

The Mogas Tanks (S-79, S-80, S-82, S-84, S-86, S-92 and S-97), where the
additional Alkylate will be blended to form finished gasoline, will
continue to comply with Regulation 8, Rule 5 requirements.

These proposed changes are not within 1000 feet of a school. Therefore,
it is not subject to the public notification requirements of Regulation
2-1-412.

This application is considered to be categorical exempt per District
Regulation 2-1-312.6:

-   Permit applications relating to minor alterations of existing
    facilities' equipment or sources involving negligible or no
    expansion of use beyond that previously existing.

BACT, NSPS, NESHAPS and PSD are not triggered.

# [OFFSETS]{.underline} {#offsets .unnumbered}

Because Valero is a major facility for POC emissions, offsets will be
provided in accordance with Regulation 2-2-302. The offsets needed are:
0.174 TPY x 1.15 = 0.200 TPY

#  {#section-4 .unnumbered}

#### The offsets will come out of Certificate 682, which was surrendered recently to cover the offset obligation for the Cogeneration Project (Application 2488 and 2695). After offsets were provided a balance of 7.147 tons/year was refundable back to Valero. Valero has requested that 0.2 TPY be used out of the remaining balance for that certificate to offset this project emission. Valero will be issued a Banking Certificate for the balance of 6.947 TPY POC \[14.769 TPY POC Certificate 682 -- 7.622 TPY Cogeneration Project (Application #2488 and #2695) -- 0.2 TPY (Application #3782)\].  {#the-offsets-will-come-out-of-certificate-682-which-was-surrendered-recently-to-cover-the-offset-obligation-for-the-cogeneration-project-application-2488-and-2695.-after-offsets-were-provided-a-balance-of-7.147-tonsyear-was-refundable-back-to-valero.-valero-has-requested-that-0.2-tpy-be-used-out-of-the-remaining-balance-for-that-certificate-to-offset-this-project-emission.-valero-will-be-issued-a-banking-certificate-for-the-balance-of-6.947-tpy-poc-14.769-tpy-poc-certificate-682-7.622-tpy-cogeneration-project-application-2488-and-2695-0.2-tpy-application-3782. .unnumbered}

#  {#section-5 .unnumbered}

# [CONDITIONS]{.underline} {#conditions .unnumbered}

###### **MAJOR FACILITY REVIEW PERMIT** {#major-facility-review-permit .unnumbered}

The conditions for the Alkylation Unit (S-1007) are found in condition
#10574. However, there is no specific condition that limits the
throughput for the Alkylation Unit. A condition was added (number 51) to
limit the daily throughput to no more than 22,800 barrels. It reads as
follows:

51\. The total daily throughput of alkylate from the Alkylation Unit
(S-1007) shall not exceed 22,800 barrels. (Basis: BACT, Cumulative
Increase)

The capacity limitation in the draft Title V permit is 18,500 barrels
per day. Per this permit application, it will be changed prior to going
out on public comment to 22,800 barrels per day.

#####  {#section-6 .unnumbered}

##### FUGITIVE EMISSIONS {#fugitive-emissions .unnumbered}

The fugitive components in Phase III of the Clean Fuels Project will be
subject to the same conditions found in Condition #10574 for the Clean
Fuels Project (Application #10392) in Phase II which includes the
Alkylation Unit (S-1007). Condition #10574 is attached. For this
project, another condition was added (number 52) to allow for an
adjustment in the final fugitive count beyond the project's estimated
quantity. The condition reads as follows:

> 52\. The Alkylate Production Project in Application 3782, when
> installed shall consist of no more than 100 valves, 200
> connectors/flanges, 2 pressure relief valves and 3 pumps. The POC
> emissions from the entire project shall not exceed 0.2 ton/year. The
> annual mass limit for POC may be adjusted based on final fugitive
> component count. Any additional POC offsets required due to a larger
> fugitive component count would need to be provided prior to permit
> issuance. (Basis: Cumulative Increase Offsets)

#  {#section-7 .unnumbered}

# RECOMMENDATION {#recommendation .unnumbered}

I recommend that Valero Refining Company be granted a conditional
Authority to Construct to make piping changes and other alterations to
increase daily production of alkylate at the Alkylation Unit (S-1007).

By: Date:

Douglas W. Hall

Supervising Air Quality Engineer

**EVALUATION REPORT**

**VALERO BENICIA REFINERY**

**SPARE TAIL GAS HYDROGENATION REACTOR**

**APPLICATION 8028, PLANT 12626**

**[BACKGROUND]{.underline}**

The Valero Benicia Refinery (Valero) operates a tail gas treatment
process that abates the discharge vapors from the Sulfur Plants. This
process consists of

S-1 Claus Sulfur Plant A, 480 short tons/day (VIP rate), 58,400 short
tons/yr (Title V)

S-2 Claus Sulfur Plant B, 480 short tons/day (VIP rate), 58,400 short
tons/yr (Title V)

A-24 Tail Gas Hydrogenation unit (Beavon Process) consisting of a
Reducing Gas Generator, Hydrogenation Reactor, and Waste Heat Boiler

A-56 Flexsorb Absorption Unit, including an amine Adsorption Unit and
Regenerator. The H~2~S containing acid gas is recycled back to the Claus
Units.

P-50 Cleaned Tail Gas discharge from Flexsorb unit.

The trains (not currently represented properly in Databank) are as
follows:

S1,A24,A56,P50 and

S2,A24,A56,P50.

This process works well discharging vapors that comply with District
regulations. However, this unit is critical to the operation of the
refinery. Since there is no alternative treatment, any failure of the
unit can result in a refinery shut down. Normally, periodic refinery
turnarounds are capable to address any maintenance or reliability issues
with critical units such as this tail gas treatment system. However, the
catalyst in the S-24 Hydrogenation Reactor has two to three year life,
which is shorter than the target refinery turnaround cycle.

This application if for the installation of a spare hydrogenation unit:

**A-62 Spare Tail Gas Hydrogenation Unit with Reactor and Waste Heat
Boiler**

Originally, this application was submitted as a complete 100% spare to
the existing A-24 unit. Furthermore, the application requested approval
under the Accelerated Permit Program because mandatory recertification
of the unit's waste heat boiler requires a unit shutdown in February
2004. The applicant tried to obtain a deferral of the boiler
recertification to avoid a special shutdown and a compressed
construction schedule. However, this option was rejected.

Upon review of the original application, it was determined that the
spare unit did not qualify for the Accelerated Permit Program because
there is an increase in emissions. When the spare unit is brought
online, there is an 8 to 12 hour transition period where both Reducing
Gas Generators will be operating concurrently as the spare unit comes up
to temperature. The Reducing Gas Generator (aka the Combustor) burns
natural gas so the combined combustion products from both units would
result in a net increase of emissions. This transition period to the
spare unit is expected infrequently (every 2 to 3 years), and according
to the applicant, the emission increase would be small. However, the
increase is real (and currently undefined), preventing qualification for
the Accelerated Permit Program.

To resolve this issue, the applicant agreed to remove the Reducing Gas
Generator from the application, leaving only the Hydrogenation Reactor
and the Waste Heat Boiler. Tie-ins for a future Reducing Gas Generator
would be provided, but the installation would be the subject of a future
application. Until the installation of the spare Reducing Gas Generator,
the existing fired equipment will be used at 100% duty and manifolded to
both the existing reactor and the spare reactor. With this change to the
application, any concurrent operation of the primary and spare unit will
not result in an increase in emissions. Consequently, on August 13,
2003, the District granted approval of equipment installation and
operation under the Accelerated Permit Program.

**[EMISSIONS SUMMARY]{.underline}**

There are no changes in emissions due to this application. The design
and performance of the spare equipment is identical to the existing
unit.

**[PLANT CUMULATIVE INCREASE]{.underline}**

There are no net changes to the plant cumulative emissions.

**[TOXIC RISK SCREEN]{.underline}**

This proposed throughput change would not emit toxic compounds in
amounts different that previously emitted. Therefore, a toxic risk
screen is not required.

**[BEST AVAILABLE CONTROL TECHNOLOGY]{.underline}**

BACT is triggered for new or modified sources that emit criteria
pollutants in excess of 10 lbs/day. However, Regulation 2-1-234 defines
a modified source as one that results in an increase in daily or annual
emissions of a regulated air pollutant. For this application, there is
no change in emissions. Therefore, BACT does not apply.

**[PLANT LOCATION]{.underline}**

According to the SCHOOL program, the closest school is Semple
Elementary, which is just over one mile from the facility.

**[COMPLIANCE]{.underline}**

The installation of this spare equipment will not change the compliance
for the Sulfur Plants S-1 and S-2. Tail gas emissions from S-1 and S-2,
abated by either A-24 or A-62, then by A-56, will comply with
Regulations 6-301, 6-310 and 6-330:

**6-301 Ringelmann No. 1 Limitation:** Except as provided in Sections
6-303, 6-304 and 6-306, a person shall not emit from any source for a
period or periods aggregating more than three minutes in any hour, a
visible emission which is as dark or darker than No. 1 on the Ringelmann
Chart, or of such opacity as to obscure an observer\'s view to an
equivalent or greater degree.

**6-310 Particulate Weight Limitation:** A person shall not emit from
any source particulate matter in excess of 343 mg per dscm (0.15 gr. per
dscf) of exhaust gas volume.

**6-330 Sulfur Recovery Units:** A person shall not emit from any
operation manufacturing sulfur, using as a principal raw material any
sulfur-containing material, any emission having a concentration of SO~3~
or H~2~S0~4~, or both, expressed as 100% H~2~S0~4~, exceeding 183 mg
dscm (0.08 gr. dscf) of exhaust gas volume.

The closest school is over a mile from the facility, so the Public
Notice requirements of Regulation 2-1-214 do not apply.

Toxics, CEQA, NESHAPS, BACT, Offsets and NSPS do not apply.

**[CONDITIONS]{.underline}**

Existing Conditions 125 and 126 will be modified as follows:

There are currently four District Permit Conditions that apply to Sulfur
Plants S-1 and S-2 which are shown here for information. Condition 125
is for S-1, Condition 126 is for S-2, Condition 18344 only has deleted
parts, and Condition 19466 is the Title V monitoring condition currently
shown as a Future Condition. These conditions are copied from Databank,
with the applicable parts highlighted in 19466. Condition 18344 is the
only condition shown as current in Databank. Therefore, one of the
actions of the application's form letter request will be to update the
condition listings in Databank.

Note that Conditions 125 and 126 only state that the tail gas must be
treated by A-56, the Flexsorb Unit (i.e. Part 4's do not specifically
list A-24 as a required treatment for the tail gas). At one time it was
proposed that A-56 be redefined to include the facilities of A-24, but
this change was either not approved or not fully implemented (the
proposed Title V Permit shows A-56 to include the pretreatment
hydrogenation unit, Databank still shows A-24 as current). In any case,
this is not a concern since the A-56 Flexsorb H~2~S adsorption process
is only operated when the A-24/A-62 Hydrogenation unit converts the tail
gas SO~2~ to H~2~S. Stating that the tail gas will be abated by A-56
means A-24 will also be in the treatment train, regardless of whether
A-56 contains the hydrogenation

COND# 125
\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--

#### Valero Refining Company -- California {#valero-refining-company-california .unnumbered}

3400 E. Second Street

Benicia, Ca 94510

Application 8028

S-1 Sulfur Plant A

Previous Applications: 26227(1977), 26878(1979), 29808 (1984),
17850(1997)

1\. Reasonable access to 24 hour sulfur production data shall

be provided by the owner/operator whenever the APCO or his designated

representative performs compliance determination on the

Sulfur Recovery Unit (SRU), Tail Gas Clean-up Unit and main

stack.

2\. The owner/operator shall install the best available H2S monitoring
system on the Tail Gas Clean-up Unit exhaust stack,

subject to approval by the APCO.

3\. Except during upset conditions, the owner/operator shall not open
motor operated valve

(MOV-001), which allows Tail Gas from S-1 to flow to the

incinerator (F-1302A; A-14), when either

of the sour gas feed valves (F002, F004) to source (S-1) are

open. A closed block valve or blind in the pertinent lines

shall be considered sufficient to fulfill this requirement.

4\. Except during upset conditions, the owner/operator shall route the
tail gases from the

S-1 Sulfur Recovery Unit to the Beavon and Flexsorb SE Tail Gas
Treatment Units (A-24, A-62 and A-56). The

recovered hydrogen sulfide shall be returned to the S-1

and/or S-2 SRU for recovery as elemental sulfur.

list condition NUMBER \>\> 126

COND# 126
\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--

#### Valero Refining Company -- California {#valero-refining-company-california-1 .unnumbered}

3400 E. Second Street

Benicia, Ca 94510

Application 8028

S-2 Sulfur Plant B

Previous Appications: 26227(1977), 26878(1979), 29808 (1984),
17850(1997)

1\. Reasonable access to 24 hour sulfur production data shall

be provided by the owner/operator whenever the APCO or his designated

representative performs compliance determination on the

Sulfur Recovery Unit (SRU), Tail Gas Clean-up Unit and main

stack.

2\. The owner/operator shall install the best available H2S monitoring
system on the Tail Gas Clean-up Unit exhaust stack,

subject to approval by the APCO.

3\. Except during upset conditions, the owner/operator shall not open
motor operated valve

(MOV-003), which allows Tail Gas from S-2 to flow to the

incinerator (F-1302B; A-15), when either

of the sour gas feed valves (F052, F054) to source S-2 are

open. A closed block valve or blind in the pertinent lines

shall be considered sufficient to fulfill this requirement.

4\. Except during upset conditions, the owner/operator shall route the
tail gases from the

S-2 Sulfur Recovery Unit to the Beavon and Flexsorb SE Tail Gas
Treatment Units (A-24, A-62 and A-56). The

recovered hydrogen sulfide shall be returned to the S-1

and/or S-2 SRU for recovery as elemental sulfur.

Condition 18344 is the condition currently shown as current in Databank
for S-1 and S-2. This condition will be archived.

COND# 18344
\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--

1\. Deleted (Application #3902, 1/02)

2\. Deleted (Application #3902, 1/02)

Condition 19466 is the future condition for S-1 and S-2. This condition
is the Title V monitoring condition. The pertinent parts are
highlighted.

COND# 19466
\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\-\--

VALERO REFINING COMPANY

TITLE V CONDITIONS

[1. The Permit Holder shall conduct an annual District-]{.mark}

[approved source test on the S-1 and S-2 Claus Units to]{.mark}

[demonstrate that 95% of the H2S in the refinery fuel]{.mark}

[gas is removed and recovered on a refinery-wide basis]{.mark}

[and 95% of the H2S in the process water streams is]{.mark}

[removed and recovered on a refinery-wide basis AND 95%]{.mark}

[of the ammonia in the process water stream is removed.]{.mark}

[The test results shall be provided to the District\'s]{.mark}

[Compliance and Enforcement Division and the District\'s]{.mark}

[Permit Services Division no less than 30 days after]{.mark}

[the test. The test shall include sampling of the]{.mark}

[inlet and outlet of the fuel gas scrubber and sour]{.mark}

[water stripper towers. \[Basis: Regulation 9-1-313.2\]]{.mark}

2\. The Permit Holder shall conduct an annual District-

approved source test on the S-188 CPS Units to

demonstrate that the combined collection/destruction

efficiency of the \<A- \> is no less than 95%, by

weight, for VOC. The test results shall be provided

to the District\'s Compliance and Enforcement Division

and the District\'s Permit Services Division no less

than 30 days after the test. These records shall be

kept for a period of at least 5 years from date of

entry and shall be made available to District staff

upon request. \[Basis: Regulation 8-8-302.3\]

[3. The permit holder shall monitor and record on a]{.mark}

[monthly basis the visible emissions from Sources S-1,]{.mark}

[S-2, S-5, S-6, S-8, S-10, S-11, S-176, S-232 and S-233]{.mark}

[to demonstrate compliance with Regulation 6-301]{.mark}

[(Ringlemann 1 or 20% opacity). These records shall be]{.mark}

[kept for a period of at least 5 years from date of]{.mark}

[entry and shall be made available to District staff]{.mark}

[upon request. \[ Basis: Regulation 6-301\]]{.mark}

4\. The permit holder shall monitor and record on a

semi-annual basis the visible emissions from the S-231

and S-236 to demonstrate compliance with Regulation 6-

301 (Ringlemann 1 or 20% opacity). These records

shall be kept for a period of at least 5 years from

date of entry and shall be made available to District

staff upon request. \[BAAQMD 6-301\]

5\. The emissions from the S-3 and S-4 CO Boilers shall

be abated by the A-1 through A-5 Electrostatic

Precipitators and exhausted through the main stack

(P-1). \[Basis: Regulation 6-301 and Regulation 6-

304\].

[6. The permit holder shall perform an annual source]{.mark}

[test on Sources S-1, S-2, S-5, S-6, S-8, S-10, S-11,]{.mark}

[S-12, S-176, S-232, S-233 and S-237 to demonstrate]{.mark}

[compliance with Regulation 6-310 (outlet grain loading]{.mark}

[no greater than 0.15 grain/dscf). The test results]{.mark}

[shall be provided to the District\'s Compliance and]{.mark}

[Enforcement Division and the District\'s Permit]{.mark}

[Services Division no less than 30 days after the test.]{.mark}

[These records shall be kept for a period of at least 5]{.mark}

[years from date of entry and shall be made available]{.mark}

[to District staff upon request. \[ Basis: Regulation]{.mark}

[6-310\]]{.mark}

7\. The permit holder shall perform an annual source

test on Sources S-8, S-10, S-11, S-12, S-176, S-232

and S-233 to demonstrate compliance with Regulation 6-

310.3 (outlet grain loading no greater than 0.15

grain/dscf @ 6% oxygen). The test results shall be

provided to the District\'s Compliance and Enforcement

Division and the District\'s Permit Services Division

no less than 30 days after the test. These records

shall be kept for a period of at least 5 years from

date of entry and shall be made available to District

staff upon request. \[ Basis: Regulation 6-310.3\]

[8. The Permit Holder shall perform an annual source]{.mark}

[test on S-1 and S-2 to determine compliance with]{.mark}

[Regulation 6-330 (Outlet grain loading not to exceed]{.mark}

[0.08 grain/dscf of SO3 and H2SO4). The test results]{.mark}

[shall be provided to the District\'s Compliance and]{.mark}

[Enforcement Division and the District\'s Permit]{.mark}

[Services Division no less than 30 days after the test.]{.mark}

[These records shall be kept for a period of at least 5]{.mark}

[years from date of entry and shall be made available]{.mark}

[to District staff upon request. \[ Basis: Regulation]{.mark}

[6-330\]]{.mark}

9\. The Permit Holder shall perform an annual source

test on Sources S-5, S-6, S-8, S-10, S-11, S-12, S-

176, S-232, S-233 and S-237 to demonstrate compliance

with Regulation 6-311 (PM mass emissions rate not to

exceed 4.10P0.67 lb/hr). The test results shall be

provided to the District\'s Compliance and Enforcement

Division and the District\'s Permit Services Division

no less than 30 days after the test. These records

shall be kept for a period of at least 5 years from

date of entry and shall be made available to District

staff upon request. \[ Basis: Regulation 6-311\]

10\. The Permit Holder shall conduct a District-

approved source test on an semi-annual basis on

Sources S-7, S-20, S-23, S-24, S-26, S-30, S-31, S-

32, S-33, S-34, S-35, S-38 and S-39 to demonstrate

compliance with Regulation 9-10-305 (CO not to

exceed 400 ppmv, dry, at 3% O2, operating day

average. The test results shall be provided to the

District\'s Compliance and Enforcement Division and

the District\'s Permit Services Division no less than

30 days after the test. These records shall be kept

for a period of at least 5 years from date of entry

and shall be made available to District staff upon

request. \[Basis: Regulation 9-10-305\]

11\. The Permit Holder shall conduct a semi-annual

District-approved source test on Sources S-43, S-44

and S-46 to demonstrate compliance with Regulation

9-9-301.1 (NOx not to exceed 55 ppmv, dry, at 15%

O2, fired on refinery fuel gas. The test results

shall be provided to the District\'s Compliance and

Enforcement Division and the District\'s Permit

Services Division no less than 30 days after the

test. These records shall be kept for a period of

at least 5 years from date of entry and shall be

made available to District staff upon request.

\[Basis: Regulation 9-9-301.1\]

12\. The VOC emissions from the S-159 Lube Oil Reservoir

shall be abated by the S-36 Boiler. \[Basis:

Cumulative Increase\]

13\. The VOC emissions from S-167 and S-168 Seal Oil

Spargers shall be vented in a closed system to the

fuel gas header to be introduced into the refinery

fuel gas stream. \[Basis: Cumulative Increase\]

**[RECOMMENDATION]{.underline}**

It is recommended that an Authority to Construct be waived and a Permit
to Operate be granted to Valero for:

**A-62 Spare Tail Gas Hydrogenation Unit with Reactor and Waste Heat
Boiler**

\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_
\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_

Arthur P. Valla Date

Air Quality Engineer

**EVALUATION REPORT**

**VALERO BENICIA REFINERY**

**SPARE TAIL GAS REDUCING GAS GENERATOR**

**APPLICATION 8427, PLANT 12626**

**[BACKGROUND]{.underline}**

The Valero Benicia Refinery (Valero) operates a tail gas treatment
process that abates the discharge vapors from the Sulfur Plants. This
process consists of

S-1 Claus Sulfur Plant A, 480 short tons/day (VIP rate), 58,400 short
tons/yr (Title V)

S-2 Claus Sulfur Plant B, 480 short tons/day (VIP rate), 58,400 short
tons/yr (Title V)

A-24 Tail Gas Hydrogenation unit (Beavon Process) consisting of a
Reducing Gas Generator, Hydrogenation Reactor, and Waste Heat Boiler

A-56 Flexsorb Absorption Unit, including an amine Adsorption Unit and
Regenerator. The H~2~S containing acid gas is recycled back to the Claus
Units.

P-50 Cleaned Tail Gas discharge from Flexsorb unit.

The trains (not currently represented properly in Databank) are as
follows:

S1,A24,A56,P50 and

S2,A24,A56,P50.

This process works well discharging vapors that comply with District
regulations. However, this unit is critical to the operation of the
refinery. Since there is no alternative treatment, any failure of the
unit can result in a refinery shut down. Normally, periodic refinery
turnarounds are capable to address any maintenance or reliability issues
with critical units such as this tail gas treatment system. However, the
catalyst in the S-24 Hydrogenation Reactor has two to three year life,
which is shorter than the target refinery turnaround cycle.

To avoid shutting down the refinery in the event of failure of the tail
gas treatment system, the applicant has proposed to install an identical
spare (backup) unit. The spare will consist of a hydrogenation Unit with
reactor, waste heat boiler and a reducing gas generator unit. This
proposed project was broken up into two phases. Phase I includes the
hydrogenation Unit with reactor and the waste heat boiler, which was
permitted in Application #8028. This application is for the permitting
of the equipment in Phase II:

**A-62 Spare Tail Gas Reducing Gas Generator, natural gas fired, 9.1
MMBtu/hour**

When this spare unit is brought online, there is an 8 to 12 hour
transition period where both Reducing Gas Generators (existing and
spare) will be operating concurrently as the spare unit comes up to
temperature. The Reducing Gas Generator (aka the Combustor) burns
natural gas so the combined combustion products from both units would
result in a net increase of emissions. This transition period to the
spare unit is expected infrequently (every 2 to 3 years). The emission
increase from this proposed project is small.

**[EMISSIONS CALCULATION]{.underline}**

The warmup periods where both Reducing Gas Generators will be operating
concurrently will occur no more than 5 times per year. The firing rate
during the warmup period will be around 2 MMBtu/hr and last about 12
hours.

The emission factors come from AP-42, Small Boilers, Uncontrolled, Table
1.4-1 and 1.4-2.

NOx: 0.098 lb/MMBtu x 2 MMBtu/hr x 12 hours/event x 5 events/year x
ton/2000 lbs

> = 0.006 ton/year NOx

CO: 0.082 lb/MMBtu x 2 MMBtu/hr x 12 hours/event x 5 events/year x
ton/2000 lbs

> = 0.005 ton/year CO

PM10: 0.0069 lb/MMBtu x 2 MMBtu/hr x 12 hours/event x 5 events/year x
ton/2000 lbs

> = 0.0004 ton/year PM10

SO2: 0.0006 lb/MMBtu x 2 MMBtu/hr x 12 hours/event x 5 events/year x
ton/2000 lbs

> = 0.000036 ton/year SO2

POC: 0.0054 lb/MMBtu x 2 MMBtu/hr x 12 hours/event x 5 events/year x
ton/2000 lbs

> = 0.00032 ton/year VOC

**[PLANT CUMULATIVE INCREASE]{.underline}**

POC: 0.059 (existing)+ 0.00032 (proposed) = 0.05932 TPY

NOx: 0 (existing) + 0.006 (proposed) = 0.006 TPY

SO2: 0 (existing) + 0.000036 (proposed) = NEGLIBLE TPY

PM10: 0.004 (existing)+ 0.0004 (proposed) = 0.0044 TPY

CO: 0 (existing) + 0.005 (proposed) = 0.005 TPY

**[TOXIC RISK SCREEN]{.underline}**

The addition of a spare reducing gas generator should not emit toxic
compounds in amounts different that previously emitted. Therefore, a
toxic risk screen is not required.

**[PLANT LOCATION]{.underline}**

According to the SCHOOL program, the closest school is Semple
Elementary, which is just over one mile from the facility.

#  {#section-8 .unnumbered}

# [OFFSETS]{.underline} {#offsets-1 .unnumbered}

The POC offset required is 0.00032 TPY \* 1.15 = 0.00036 TPY

The NOx offset required is 0.006 TPY \* 1.15 = 0.007 TPY

The plant has elected to use the offset deferral provision allowed in
Regulation 2-2-421. The facility has valid Banking Certificates to cover
this small increase and the facility's cumulative increase is less than
15 tons/year. As discussed with the applicant, offsets will be provided
at least 30 days prior to the date of the annual permit renewal (i.e.,
no later than July 1, 2004).

The cumulative increase for PM10 is 0.0004 TPY. A review of the
available information in the District's databank covering past projects
for the Valero Asphalt Plant since April 5, 1991 revealed that there was
a pre-existing cumulative increase for PM10 of 0.004 tons/year from
Application #7471. Pursuant to the provisions in Regulation 2-2-303,
offsets will be deferred until the PM10 cumulative increase exceeds 1.0
ton/year.

**[COMPLIANCE]{.underline}**

The installation of this spare equipment will not change the compliance
for the Sulfur Plants S-1 and S-2. Tail gas emissions from S-1 and S-2,
abated by either A-24 or A-62, then by A-56, will comply with
Regulations 6-301, 6-310 and 6-330:

**6-301 Ringelmann No. 1 Limitation:** Except as provided in Sections
6-303, 6-304 and 6-306, a person shall not emit from any source for a
period or periods aggregating more than three minutes in any hour, a
visible emission which is as dark or darker than No. 1 on the Ringelmann
Chart, or of such opacity as to obscure an observer\'s view to an
equivalent or greater degree.

**6-310 Particulate Weight Limitation:** A person shall not emit from
any source particulate matter in excess of 343 mg per dscm (0.15 gr. per
dscf) of exhaust gas volume.

**6-330 Sulfur Recovery Units:** A person shall not emit from any
operation manufacturing sulfur, using as a principal raw material any
sulfur-containing material, any emission having a concentration of SO~3~
or H~2~S0~4~, or both, expressed as 100% H~2~S0~4~, exceeding 183 mg
dscm (0.08 gr. dscf) of exhaust gas volume.

The closest school is over a mile from the facility, so the Public
Notice requirements of Regulation 2-1-214 do not apply.

Toxics, CEQA, NESHAPS, BACT, Offsets and NSPS do not apply.

**[CONDITIONS]{.underline}**

S-1 and S-2 Sulfur Plants are subject to Conditions #125 and #126. These
conditions were modified in the Phase I application (#8028). No new
conditions are needed because of adding the new spare tail gas reducing
gas generator.

**[RECOMMENDATION]{.underline}**

It is recommended that an Authority to Construct be waived and a Permit
to Operate be granted to Valero for Phase II of the proposed project to
install the following equipment:

**A-62 Spare Tail Gas Reducing Gas Generator, natural gas fired, 9.1
MMBtu/hour**

\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_
\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_

Douglas W. Hall Date

Supervising Air Quality Engineer