ILLINOIS
POLLUTION
CONTROL BOARD
April
21,
1988
IN THE MATTER OF:
AMENDMENTS TO 35
ILL.
ADM.
CODE
214,
)
R86—30
SULFUR LIMITATIONS
PROPOSED RULE.
FIRST NOTICE.
PROPOSED OPINION AND ORDER OF THE BOARD
(by J. Theodore Meyer):
This matter
is
before the Board
on
a joint proposal
for
regulatory amendment filed
by the Illinois Environmental
Protection Agency (Agency)
and Shell Oil Company
(Shell)
on July
7,
1986.
The joint proposal seeks
to amend
35 Ill.
Adm. Code
214, which regulates sulfur emissions from stationary sources.
The proposal
is designed
to tighten emissions
from Shell’s Wood
River Manufacturing Complex
(WRMC)
so as
to ensure
the attainment
and maintenance of National Ambient Air Quality Standards
(NAAQS)
for sulfur dioxide
(SO2)
for the Wood River
area.
A merit hearing on the proposal
was held on October
30,
1986
in Wood River,
Illinois.
On February 26,
1987 the Department
of
Energy and Natural Resources
(DENR)
filed
a negative declaration,
setting
forth
its determination that the preparation of
a
formal
economic impact study
is not necessary
in this proceeding.
The
negative declaration was based upon DENR’s findings
that the
economic impact of the regulation
is favorable and
that
the costs
of compliance are small or are borne entirely by the proponent of
the regulation.
On March
4,
1987,
the Board
received
notification that the Economic and Technical Advisory Committee
(ETAC) concurred
in DENR’s negative declaration.
The Hearing
Officer subsequently directed that
the record
be closed on April
30,
1987.
However, on that date the Agency filled
a motion for
extension
of time
to present additional evidence.
The basis
of
the Agency’s request was its notification by the United States
Environmental Protection Agency (USEPA)
that additional technical
work
needed
to be done for the rule
to be federally approvable
as
a part of
the State Implementation Plan
(SIP)
for SO2.
The
Hearing Officer granted
the Agency’s motion,
and ordered
that the
record be kept open
indefinitely.
The necessary technical work was completed
in late 1987,
and
the final
hearing was held on January 22,
1988
in Chicago.
At
that hearing,
the Agency and Shell submitted
a revised proposal
(Ex.
9)
and presented testimony
in support of the revisions.
DENR has
indicated that
it feels
that
its February 1987 negative
declaration
is still appropriate.
88—443
—2—
BACKGROUND
The purpose behind the joint proposal
is
to remedy the
inadequacy
in the Illinois SIP for 502.
On September
28,
1984,
USEPA notified Governor Thompson that
it
found
the SIP
substantially inadequate
to achieve
the NAAQS
for SO~ in the
Alton and Wood River areas
of Madison County,
Illinois.
The SIP
deficiency notice was made pursuant
to Section l10(a)(2)(H)
of
the Clean Air Act,
42 U.S.C.
74l0(a)(2)(H).
(JSEPA called
for
Illinois
to submit
a curative SIP revision
or be subject
to
sanctions
under
the Clean Air Act.
Because Shell’s allowable
emissions contribute significantly to
the modeled
nonattainment
in the Alton—Wood River
area,
Shell and the Agency worked
together
to develop
a proposal
to assure attainment
of the NAAQS
for
SO2.
The
instant proposal
is the result
of that cooperation.
Shell’s WRMC
is the largest refinery
in Illinois,
and
processes approximately 12 million gallons of crude oil per
day.
At the
refinery,
the crude
oil
is separated,
and the parts,
or
fractions,
are converted
and upgraded.
About 6.5 million
gallons
become motor gasoline and aviation
fuel.
The remainder
becomes
home heating
oil,
liquefied petroleum gas,
diesel fuel,
aviation turbine fuel,
industrial
fuel oil,
asphalt, solvents,
chemicals such as benzene and acetone, and more than
500
varieties of lubricating oil.
(See generally Ex.
7.)
The
refinery processes used
to create these products
include
distillation, vacuum flashing,
fluid catalytic cracking,
gas
plant fractionation, hydrocracking,
reforming,
hydrotreating,
and
alkylation.
(Transcript of October
30, 1986
(Tr.I),
p.
58.)
The
WRMC employs over 1700 people,
who earned over $80,000,000
in
wages and benefits in 1985.
(Tr.I, p.
40.)
Sulfur Emission Sources
There are forty—eight SO2 emission sources at
Shell’s
WRMC.
Forty—three of these
sources are fuel combustion emission
sources,
both process heaters and boilers.
The process heaters
supply heat
to the various
refinery processes
for the conversion
and/or separation of crude oil and intermediate products into
gasoline and other saleable products.
Nine boilers produce
steam, which
is used primarily for fractionation,
turbine
drivers,
equipment maintenance,
and heat tracing.
The
fuel
demands
of
the process heaters and the boilers are primarily met
with by—product
fuels produced within the refinery,
including
refinery flasher pitch and refinery fuel gas.
Some sources also
use small amounts of residual oil called utility fuel
oil.
In
addition,
a
relatively small amount of
natural gas
is purchased
and used
to balance WRMC1s
fuel gas system.
(Tr.I, pp.
61—62;
Transcript
of January 22, 1988
(Tr.
II),
pp.
40—41.)
88—444
—3—
Shell’s refinery flasher pitch
(RFP)
system
is
a
fuel supply
system which
is unique
to
WRMC.
This
system supplies preheated
pitch
fuel
at
a constant temperature and pressure
to
the larger
fuel combustion sources
at WRMC.
RFP,
which
is
a by—product
of
the vacuum flashing units, has
a very high viscosity and acts
like
a solid at room temperatures.
The sulfur content
of RFP
is
related
to the sulfur content of
the crude oil.
The pitch
is
circulated via supply and return headers.
In addition
to the
main headers,
each
individual unit has
an
internal circulating
loop, allowing pitch
which
is not consumed at
that
individual
source
to go back into the return header.
A small heater
is used
to maintain the temperature of the RFP at
about
500 degrees
Fahrenheit
so
that the pitch may be pumped.
(Tr.I,
pp.
62—3;
Ex.
6,
Figure
I.)
The refinery fuel gas
(RFG)
system
is the other main
fuel
supply system at WRMC.
RFG is primarily composed
of the light
hydrocarbons methane
and ethane with some propane and butane plus
hydrogen.
RFG has
a variable heating value and can have
up
to
7,000 grains
of hydrogen sulfide
(H2S)
per 100 standard cubic
feet
(scf)
prior
to treatment.
By—product vent gases
from
the
various processing
units
at
WRMC
are collected and routed
to fuel
gas absorbers.
The
is removed from the sour
fuel gases,
and
the treated RFG
is then ready to burn
at
the various
fuel
combustion sources.
The recovered
H2S
is routed
to the sulfur
recovery plant where
it is converted and recovered
as elemental
sulfur
(Tr.I, pp.
63—64;
Ex.
6,
Figure
II.)
The five remaining SO2 emission sources are process emission
sources.
WRMC’s process emission sources
include Fluid Catalytic
Cracking Unit
No.
1
(CCU—l), Fluid Catalytic Cracking Unit No.
2
(CCU—2), Asphalt Converter No.
5,
Sulfuric Acid Unit
(SAU),
and
the Sulfur Recovery Unit
(SRIJ).
These processes produce sulfur
emissions
to varying degrees.
(Tr.I, pp.
65—67.)
SO~Air Pollution Control Equipment
Shell currently has several
types of
air pollution control
equipment which control SO2 emissions.
This existing equipment
includes the sulfur recovery plant,
the fuel
gas treatment
facilities,
facilities segregating low and high sulfur content
refinery flasher pitches,
the sulfuric acid unit dual absorption
facilities,
and the fluid catalytic cracking unit feed
hydrotreater.
The estimated
replacement cost
of this control
equipment
is approximately 100 million dollars,
and annual
operating and maintenance costs are on
the order
of 20 million
dollars.
(Tr.I, pp. 68—69.)
THE JOINT PROPOSAL
Shell’s WRMC presently
has a maximum permitted emission rate
of 19,160 pounds
of SO2 per hour.
The actual maximum emission
88—445
—4—
rate during
the period
1982 through
1985 was
11,063
lbs/br,
excluding any period of malfunction.
This maximum emission rate
for 1982—1985,
however,
is
not indicative
of
full capacity
operations
at WRMC.
This
is related
to the general economic
climate
for the refining industry during
this period,
and because
of
reduced operations
on some units since late
1984 due
to
a
major modernization project.
Shell estimates
that
full operating
conditions during this time would have resulted
in maximum
emission rates of approximately 13,000 lbs/hr.
(Tr.I, pp.
48—
49.)
The permitted 19,160 lbs/hr maximum emission rate
is based
upon the supposition that each individual emission source will
operate simultaneously
at maximum permitted
rates.
However,
Joseph Brewster,
Technical Manager
of Process Engineering
—
Environmental Conservation/Utilities
at WRMC,
testified that the
refinery never
operates
in that fashion.
Instead,
the refinery
operation uses
a large
variety of operating combinations with the
maximum permitted emission rates occurring with only
a few of
the
operating combinations.
(Tr.I,
p.
49.)
Therefore,
Shell
and
the
Agency worked
to prepare
a regulation which will give Shell
its
necessary operating flexibility while ensuring that ambient
air
quality standards will not be exceeded under any permitted
condition.
The resulting proposal,
as revised, would reduce
Shell’s
allowable SO2 emission from the current 19,160 lbs/hr
to
10,384
lbs/hr.
This
is
a
reduction of 8,776 lbs/hr,
or
46
percent.
(Tr.II,
p.
47;
Ex.
15, Table 2.)
The joint proposal accomplishes
this reduction by bringing
maximum permitted SO2 emissions more
in line with the actual
emissions.
This
is possible because
there
is considerable
redundancy
in the various refinery processes.
For example,
there
are nine boilers
at WRMC.
At any one time only six boilers may
be operating,
with the other three shut down
for maintenance.
(Tr.I,
p.
69.)
Mass Emission Limits
The heart
of the
joint proposal consists
of two basic
concepts set forth
in new Section 2l4.382(c)(3):
Source
Operations Groupings (SOGs)
and the rollback.
A SOG
is
a group
of similar
SO2 sources which have been capped with
a mass SO7
limit.
The emissions cap for
a SOG is less
than the total
of the
current maximum permitted emissions from each individual
source
within that
SOG.
As
a result,
the SOG more closely reflects
actual maximum conditions.
The proposal contains nine SOG5.
Eight of the SOGs are made up of
fuel combustion sources, while
the ninth consists of process emission sources.
The
individual
SOGs were chosen on the basis
of location,
control,
type of
source,
and fuel monitoring.
Sources within
a particular SOG are
located
no more than 500 feet apart and are controlled
from
a
common manned control
room.
In two cases
(distilling unit No.
2
88—446
—5—
and the hydrocracker
complex),
the SOG consists of
sources vented
to
a common
stack.
(Tr.I.
pp.
69—71.)
Exhibit
6,
Figure
IV
shows
the location of the SOGs.
The rollback caps 502 emissions from four SOGs.
The
affected SOGs are distilling
unit No.
1,
the gas plant process
heaters,
the boilers
which generate steam
for general plant use,
the aromatics east process, and asphalt converter No.
5.
This
cap,
which
is set forth
in Section 2l4.382(c)(3)(J),
is
in
addition
to the
individual SOG mass SO2 emission limit and
the
maximum permitted emission limit
for asphalt converter
No.
5.
The justification for
the rollback
is contained
in Exhibits
2 and
12, which
are Agency reports on air quality analysis and
compliance with the SO2 NAAQS
for the Alton—Wood River
area.
Fuel Sulfur Limits
The joint proposal
also imposes limits on
the amount
of
sulfur
in the fuels
used
at WRMC.
New Section 214.382(c)(l)
limits
the refinery flasher pitch
used
at the facility
to that
containing
no more than
3
sulfur by weight.
New Section
214.382(c)(2) limits refinery fuel gas
(RFG)
to 39 grains
of
hydrogen sulfide per
100 dry standard cubic
feet.
These sulfur
limits are consistent with the values presently applicable
to
WRMC
under Section 214.162.
(Tr.I,
pp.
71—72; Tr.II,
pp.
10—11,
39—44.)
Sulfur Recovery Unit Emission Limit
Proposed Section 214.382(b) changes
the emission limit
applicable
to
the sulfur
recovery unit
(SRU)
from
14 pounds per
metric ton
of sulfur recovered
to 1000 parts per miilion(ppm)
sulfur dioxide
in the final
flue gas.
This concentration in the
flue gas
is approximately equal
to the present
14 lbs/T sulfur
recovered at maximum permitted
rates.
Shell contends that
a
concentration limit
is consistent with federal New Source
Performance Standards
(NSPS)
for sulfur recovery units and with
existing Board
regulations for other sulfur recovery units
in
Illinois.
(Tr.
I, pp. 73—74.)
Shell has already made actual emission reductions pursuant
to this proposed
section.
The SRU, which converts hydrogen
sulfide derived
from crude oil processing
to elemental sulfur,
is
the primary SO2 emission control equipment at WRMC.
The SRU has
four
units, or trains,
which were built
at different
times.
The
oldest unit,
called the D—train, previously exhausted
to the
atmosphere without tailgas treatment.
This was the standard
technology
at
the time of
the construction
of the D—train in the
early 1960s,
and was allowed for
by Section
214.382(a)
of the
Board’s regulations.
In
1985, Shell
tied the 0—train
into
the
existing tailgas cleanup unit,
called the SCOT unit.
The SCOT
unit had sufficient capacity to accommodate
the additional
gas
88—447
—6—
load.
This tie—in decreases
SO7 emissions
in the
tailgas
from
approximately 10,000 ppm
to within the proposed standard
of 1000
ppm.
This step reduces maximum permitted
and maximum actual
emissions by 2,406 pounds per hour.
(Tr.I,
pp.
50—52.)
Compliance
One of
the issues raised by USEPA
in its April
9,
1987
letter
(Ex.
11) detailing
its concerns about
the federal
approvability of the
joint proposal
was the lack
of compliance
test methods.
The revised proposal addresses this concern.
Proposed amendments
to Section 214.104 will incorporate by
reference two standard test methods.
An addition
to subsection
(b)
will
incorporate
“Standard Test Method for Sulfur
in
Petroleum Products
(X—Ray Spectographic Method)”, ASTM 0—2622
(1982).
(Ex.
17.)
This method will be used
to measure
the
amount
of sulfur
in the refinery flasher pitch
in order
to
determine compliance
with new Section 2l4.382(c)(1).
The joint
proposal would also add
a new subsection
(c)
incorporating
by
reference
the Tutwiler procedure.
(Ex.
18.)
This
standard
procedure,
found at 40 CFR 60.648
(1986),
is
to be used
to
measure
the amount of
hydrogen sulfide
in refinery
fuel gas,
so
as
to show compliance with proposed Section 2l4.382(c)(2).
Additionally, new Section 214.382(d)
specifies that compliance
with the emission limits
of Section 214.382(b)
and
(C)
shall be
demonstrated
on
a
three—hour
block average basis.
The Board has
added
a sentence to subsection
(d)
which requires that collection
of data necessary
to adequately determine
the SO2 emission
rate
from each SOG be made
a permit condition.
Agency comment
is
requested on the adequacy of
the listed data and any need
to
expand the list.
New Section
2l4.382(c)(l) states
that
compliance with that subsection shall
be demonstrated
by daily
sampling of
the refinery flasher pitch, while new Section
214.382(c)(2) provides
that compliance~with the refinery fuel gas
standard shall
be demonstrated
by sampling the gas once every
shift
(i.e.
every eight hours).
Comment
is requested
on the
eight hour sampling
requirement.
Shell
introduced
a report
entitled
“Sulfur Dioxide Emissions Determination Procedure”
(Ex.
16),
which describes how Shell
will
implement
the rule
to show
compliance
on an ongoing basis.
A Shell engineer testified
that
Shell expects
this report
to be referenced
as
a standard
condition
in future operating permits.
(Tr.
II,
pp.
8—10,
42—
46.)
Finally,
tJSEPA expressed concern
over which emission limits
apply
to the various sources
at WRMC.
A summary of
the limits
applicable
to each source
is contained
in Exhibit
15, Table
1.
Alternative Emission Standard
Shell
and
the Agency also propose
a new Section 214.382(g),
which would provide
for establishment of
an alternative emission
rate
to the limits found
in Section 214.382(c).
Proposed
subsection
(g) states that any owner
or operator
of
an emission
88—448
—7—
source
to which subsection
Cc)
applies may petition the Board
for
approval
of an alternative
rate.
Such person would be required
to demonstrate
in
an adjudicative hearing
that
the proposed rate
would
not under
foreseeable conditions
cause or contribute
to
a
violation
of any applicable SO7 air quality standard
or
any
applicable prevention of significant deterioration
(PSD)
increment.
Shell
testified that this provision
is intended
to
provide
flexibility
for
future development.
Mr. Brewster stated
that
there
could come
a time when Shell wanted
to retire an older
process and substitute
a new process.
This alternative emission
standard procedure
is
intended to allow
such changes without the
necessity of
a lengthy rulemaking proceeding.
(Tr.I.
pp.
83—85.)
Modifications
New Section 214.382(g) would change the definition
of
modification
for purposes
of this set of
rules only.
New
subsection
(g) provides
that notwithstanding
the definitions
contained
in Section 201.102, any physical change
in any emission
source which alters the height
of release, diameter of
the exit
stack,
temperature,
or volumetric
flow rate
of
the effluent gases
shall
be deemed
a modification
for purposes
of Section 201.142
“Construction Permit Required.”
The Agency stated at hearing
that this subsection will provide
for Agency review of
a physical
change which may alter
the impact
of the emissions
from the
source,
regardless
of whether
the change would increase
the
amount of emissions.
This
is necessary because the predicted air
quality
is already at the maximum
level.
(Tr.I, pp.
85—88.)
Environmental Impact
The Agency presented
two witnesses who testified
to the
modeling done
to assure that the joint proposal will
result in
SO2 emissions which
are within the NAAQS.
(Tr.I, pp.
7—36;
Tr.II, pp. 1—34;
Ex.
2,
12.)
Two different studies were
performed:
one prior
to the development of
this proposal
(Ex.
2),
and one after
USEPA,
in its April
1987
letter,
raised several
questions about the modeling.
(Ex.
12.)
The studies used
a
comprehensive inventory of all SO7 emission sources
in the area,
modeled
at their maximum permitted
levels,
and five years of
representative meteorological data.
Appropriate dispersion
modeling
techniques were
then used to characterize potential
ambient SO2 concentration levels
in the Wood River
area.
(The
modeling
studies and
their results are discussed more fully
in
Exhibits
2 and 12.)
These studies concluded
that
the 24—hour
average ambient
air quality standard
is
violated when the maximum
SO2 emission rates currently allowed by Board
regulations were
used
in the dispersion calculations.
No violations
of
the annual
or
3—hour average
air quality standards were found.
After Shell
and the Agency developed
a compliance strategy,
additional
modeling runs were performed.
This analysis showed that
the
second—high impacts
for any year
of meteorological data modeled
88—44 9
—8—
at any receptor near WRMC are less
tb-an
or equal
to
the 24—hour
air
quality
standard
for
SO2.
Thus,
the
A.gency
feels
that
this
joint
proposal
will
adequately
protect
the
NAAQS
for
sulfur
dioxide.
At the January 22, 1988 hearing,
an Agency witness
testified
that the Agency believes that USEPA’s questions have
been satisfactorily answered.
(Tr.
II, pp.
32—34.)
Summary of T~eductions
In addition
to the emission reductions made by tieing
the D—
train of the SRU into the existing
tailgas cleanup unit,
Shell
has made other reductions by doing
such
things as relinquishing
operating permits
for asphalt converters
1,
2,
and
4.
The
following
table
(Ex.
12, Table 13) summarizes
the reductions made
by the proposed rule
and through
Shell’s operating changes:
SO
Emission
Tons/Year)
Current Maximum Permitted Emissions
83,921
Proposed Emission Reductions:
SOGs/Rollback (Maximum
3
Sulfur
Pitch Content)
—20,711
Tie—in D—Train to SCOT
—10,665
Reduce Catalytic Cracker Units
maximum permitted emissions by 27.5
—5,694
Relinquish operating permits
for
Asphalt Converters Nos.
1,
2,
and 4
—850
Relinquish permit
to burn utility
fuel
oil
and
substitute
refinery
fuel
gas
at Precursor, Alky HM—l,
and LFE—Ext
Furnaces
—657
Revise SRtJ/SCOT emission limit to
a ppmv
limit
from
a
lbs/ton
limit
+128
Total
Reductions
38,449
Proposed
Maximum
Permitted
Emissions
—45,472
The Board specifically notes
that although the proposal
greatly
reduces
Shell’s
permitted
emission
limits,
the
actual
reductions
will
be
smaller.
This
is
because
although
Shell
is
currently
permitted
to
emit
19,160
pounds
of
s02
per
hour,
full
capacity
operations
at
WRMC
produce
actual
emission
rates
of
approximately
13,000
pounds
per
hour.
(Tr.
I,
pp.
48—49.)
Since
88—450
—9—
this proposal
is based
upon bringing maximum permitted SO2
emissions
into line with actual emissions,
the actual
emission
reduction
is
less than
the
38,449 tons per year indicated
in the
table.
Shell’s actual emissions will be reduced approximately
20
by the proposal, while
its permitted emission will
be
reduced
46.
FINDINGS
The Board
first
notes
that there
is no evidence
in this
record which
in any way rebuts or
challenges
the testimony
presented
by the Agency and Shell
in support of
the
joint
proposal.
Therefore,
there are
no controversies or conflicting
testimony
for the Board
to resolve.
The Board will
propose
the
bulk
of
the requested relief for First Notice publication.
The
Board wishes
to point out that the record does
not contain any
information
as
to the manner
in which the proponents
arrived at
the actual mass emission limits for each
SOG.
There
is
no
justification for the manner
in which specific emission limits
for each particular
SOG were allocated,
and thus no way for
the
Board
to determine whether these
limits are reasonable.
Nevertheless,
because Shell
and
the Agency have agreed on those
particular limits and because
the modeling shows
that
the
total
emissions
under
this proposal will protect the NAAQS
for SO2,
the
Board will propose
the suggested limits.
The fact that this
is
a joint proposal with a somewhat
scanty record has posed other problems
in reviewing
the requested
rule.
First,
the Board notes
that
35
Ill.
Adrn.
Code 214.301,
which sets
a SO2 emission limit
of 2000 ppm for process emission
sources,
continues
to apply to Shell’s process emission sources
other than the
sulfur recovery unit
(SRU).
This fact has been
articulated
in new Section 214.382(f).
Sulfur emissions from the
SRU are limited to 1000 ppm under new 35
Ill.
Adm. Code
214.382(b).
Shell’s
other individual
process emission sources
are not given
a new rate—based
limit by the proposal:
the only
new emission limits are under the SOG and rollback provisions.
(Tr.
II, pp.
40—41.)
The Board points out that each individual
process or
fuel combustion emission source either remains
regulated
under
the existing standard or
is subject
to
a new
standard for that
individual source which
is equivalent or more
stringent
than existing regulatory standards.
Second, and more troubling,
the record does not clearly show
why the proposal includes an exemption
from Section 214.162
“Combination
of Fuels.”
It
is not clear why Shell cannot use
the
equation set out
in that section.
The original proposal
specified
that refinery flasher pitch
(RFP) would be limited
to
3.33 pounds of SO2 per million btu (lbs/mmbtu)
of actual heat
input, while refinery
fuel gas
(RFG) would be limited
to
39
grains of ~2 per 100 dry standard cubic
feet
(gr/scf).
At the
first hearing
it was stated
that these limits were equivalent
to
88—451
—10—
3
sulfur
in
the
RFP and 0.1 lbs/mmhtu
for
the RFG.
(Tr.
I,
pp.
71—72).
The revised proposal substituted the
3
sulfur by weight
standard
for RFP.
cthen testifying
to the need
to exempt Shell
from
the combination of fuels
rule,
an Agency witness stated that
because
the original RFG standard and the revised RFP standard
are not expressed
in lbs/mmbtu,
those standards would not yield
a
lbs/hr emission rate when used
in the Section 214.162 combination
of fuels
rule.
(Tr.
II,
p.
10.)
Since
the testimony at the
first hearing provided
the emission limits
in lbs/rnmbtu,
it
is
unexplained why the RFG and RFP emission
limits cannot be
expressed
in values applicable
to Section 214.162.
In sum,
the
Board questions:
(1) why,
under
this proposal,
Section 214.162
cannot apply
to Shell’s WRMC;
and
(2) whether
the emission limits
given
in Section 214.382 are higher than those provided
for
in
Section 214.162.
Comments
on these issues are invited during the
First Notice period.
For purposes
of
First Notice,
the Board
will propose
an exemption from Section 214.162
for sources
in the
Village of Roxana which burn RFG and RET.
The Board also notes
that the record
is somewhat unclear
on
equivalence considerations.
For example,
the proposed revision
to Section 214.382(b)
changes
the emission limit
for the SRU
from
14 lbs/T sulfur
recovered
to 1000 ppm
in
the
final
flue
gas.
Although
it
is stated that the 1000 ppm standard
is approximately
equal
to the
14
lbs/T of sulfur recovered
rule
(Tr.
I,
p.
74),
the equivalence calculation has not been provided.
The record
is
also somewhat foggy on how compliance will
be
shown when
a
particular
source
is subject
to more
than one of
the proposed
limits.
For example, distilling unit No.
1
is subject
to the RFP
standard of Section
2l4.382(c)(l),
the RFG standard of Section
2l4.382(c)(2),
the SOG ceiling of
Section 2l4.382(c)(3)(A),
and
the rollback of
Section 2l4.382(c)(3)(J).
(See
Ex.
15,
Table
1.)
The Board assumes
that compliance with
the limitations
of
each applicable section will be shown.
This also again raises
the issue of why Section 214.162 “Combination
of Fuels” cannot be
used
in those
instances where
a source uses more
than one type
of
fuel.
Comments are invited on these issues.
It
is also not clear why the proposed regulation has been
placed
in Section 214.382, which regulates
the petroleum and
petrochemical processes
industry,
rather
than
in
a separate
section.
The Board notes that there are other
refineries
in the
Wood River
—
Alton
area,
and
is unclear
as
to what rules
applies
to these other refineries.
Since
the effect of
the proposal will
be the same regardless
of where
the regulation
is placed,
however,
the Board will propose
the
rule as requested,
pending
any comments on
this issue.
The only portion of the joint proposal which
the Board will
not propose
for First Notice
is the request
for
a subsection
which would establish
a procedute
for obtaining
an alternative
emission rate
to the limits set
forth
in this rule.
The record
88—452
—11—
contains no
justification for such
a procedure beyond Shell’s
assertion
that
it
is needed
to provide
flexibility
for future
development.
(Tr.
I, pp.
84—85.)
The Board believes
that
it
is
not good policy
to provide
a procedure
for obtaining an
alternative emission
rate within
a site specific rule.
By
definition,
a
site specific rule
is itself tailored
to the needs
of
a particular
facility.
To place
an alternative emission rate
procedure within a site specific regulation could
lead
to a
situation where
a facility attempts
to
“escape” from emission
limits which
it originally proposed,
without proceeding through
the notice and comment provisions
of
a rulemaking.
Finally,
it should be pointed out that the Board
has
slightly revised
the regulation proposed by Shell and the
Agency.
These revisions are not substantive;
for example,
the
exemption from Section 214.162 has been moved
from that section
to Section 214.382(e).
The language
of
some of
the proposed
sections has also been modified
to clarify
the purpose of those
sections.
The substance
of the regulation
remains
the same.
ORDER
The Board hereby directs
the Clerk of the Board
to cause
publication
in
the Illinois Register
of the First Notice
of the
following amendments:
TITLE
35:
ENVIRONMENTAL PROTECTION
SUBTITLE
B:
AIR POLLUTION
CHAPTER
I:
POLLUTION CONTROL BOARD
SUBCHAPTER
c:
EMISSION STANDARDS AND
LIMITATIONS FOR STATIONARY SOURCES
PART 214
SULFUR LIMITATIONS
SUBPART
A:
GENERAL PROVISIONS
Section 214.101
Measurement Methods
a)
Sulfur Dioxide Measurement.
Measurement of sulfur
dioxide emissions from stationary sources
shall
be made
according
to
the procedure published
in
40 CFR 60,
Appendix
A,
Method
6
(1982),
or by measurement
procedures specified by the Illinois Environmental
Protection Agency
(Agency) according
to the provisions
of
35
Ill.
Adm.
Code
201.
b)
Sulfuric Acid Mist and Sulfur Trioxide Measurement.
Measurement of sulfuric acid mist and sulfur trioxide
shall
be according
to the barium—thorin titration method
as published
in 40 CFR 60, Appendix
A,
Method
8
(1982).
88—453
—12—
c)
Solid
Fuel Averaging Measurement.
If
low sulfur solid
fuel
is
used
to comply with Sections 214.121,
214.122,
212.141,
214.142,
214.162 and 212.421,
the applicable
solid
fuel sulfur dioxide standard shall
he met by
a two
month average of daily samples with
95 percent
of the
samples
being
no greater
than
20 percent above
the
average.
A~S~-TTM7procedures D—2234
(1976)
and D—20l3
(1976)
shall be used
for solid
fuel sampling, D—3177
(1976) and D—2622
(1982)
for sulfur determinations and
D—2015
(1976)
and D—3286
(1976)
for heating value
determinations.
d)
(Reserved)
e)
(Reserved)
f)
(Reserved)
g)
(Reserved)
Ia)
Hydrogen Sulfide Measurement.
The concentration of
hydrogen sulfide
in petroleum refinery fuel gas shall
be
measured using
the Tutwiler Procedure specified
in
40
CFR 60.648
(1986).
(Source:
Amended
at
12
Ill.
Reg.
______,
effective
______________
Section 214.102
Abbreviations and Units
a)
The following abbreviations are used
in this Part:
btu
British thermal units
(60
F)
ft
foot
grains
3
Joule
kg
kilogram
kg/MW-hr
kilogram per megawatt—hour
km
kilometer
lbs
pounds
lbs/mmbtu
pounds per million btu
m
meter
mg
milligram
Mg
megagram, metric ton or
tonne
mi
mile
mmbtu
million British thermal units
mmbtu/hr
million British thermal units
per hour
MW
megawatt;
one million watts
MW—hr
megawatt—hour
ng
nanogram,
one billionth of
a gram by
volume
ng/J
nanograrns per Joule
ppm
parts
per million
88—454
—13—
scf
standard cubic
foot
scm
standard cubic meter
T
English
ton
b)
The following conversion factors have been used
in this
Part:
English
Metric
2~205 lb
1
kg
1 T
0.907 Mg
1 lb/T
0.500
kg/Mg
mmbtu/hr
0.293
MW
1 lb/mmbtu
1.548 kg/MW—hr or 430 ng/J
1
mi
1.61 km
1
gr/scf
2289 mg/scm
(Source amended
at
12
Ill.
Reg.
_______,
effective
______________
Section 214.104
Incorporations by Reference
The following materials
are incorporated
by reference:
a)
40
CFR 60, Appendix A (1982):
1)
Method
6:
method
for measurement of sulfur dioxide
emissions;
2)
Method
8:
barium—thorin titration method
b)
American Society for Testing
and Materials,
1916 Race
Street,
Philadelphia,
PA 19103:
1)
For solid
fuel sampling:
ASTM D—2234
(1976)
ASTM 0—2013
(1976)
2)
For sulfur determinations:
ASTM D—3l77
(1976)
ASTM D—2622
(1982)
3)
For heating value determinations:
ASTM D—20l5
(1976)
ASTM D—3286
(1976)
c)
Tutwiler Procedure for hydrogen sulfide,
40 CFR 60.648
(1986).
88—455
—14—
(Source:
Amended
at
12
Ill.
Req.
,
effective
Section
214.382
Petroleum and Petrochemical Processes
a)
Section
214.301 shall
not apply to existing processes
designed
to remove sulfur compounds
from the flue gases
of petroleum and petrochemical processes.
b)
No person shall
cause
or allow the emission of more than
1,000 ppm of sulfur dioxide
into the atmosphere from any
~ew process emission source
in the St. Louis
(Illinois)
major metropolitan area designed
to
remove sulfur
compounds from the flue gas
of petroleum and
petrochemical processes.
~o exeee~ ~4 ~s/~
e~~
~ex~de
pe~me~~e~
e?
~
~eee~e~ed
-?~ kq-)-~-
c)
The following
limitations apply
to any petroleum
refinery
in the Village of Roxana:
1)
No person shall
cause
or allow
the combustion
of
refinery flasher pitch containing more than 3.0
(three percent)
sulfur
by weight.
This shall
be
demonstrated
by daily sampling
of
refinery flasher
pitch.
2)
No person shall burn petroleum refinery
fuel gas
in
any fuel gas combustion device
if that
refinery
fuel
gas contains more than 39 grains hydrogen
sulfide
per
100 dry standard cubic
feet
(893
my/scm)
.
This shall
be demonstrated
by sampling
the refinery fuel gas once every eight hours.
3)
No person shall cause or allow
the total emission
of
sulfur dioxide
into the atmosphere from the
following source groupings
to exceed
the following
amounts:
A)
All process
heaters
at distilling
unit No.
1
—
459 lbs/hr
(208
kg/hr).
B)
All process heaters
at distilling unit
No.
2
—
1260 lbs/hr
(571
kg/hr).
C)
All gas plant process heaters
—
159 lbs/hr
(72.1
kg/hr).
D)
All vacuum flasher unit heaters
—
378 lbs/hr
(171 kg/hr).
88—456
—15-
E)
All
process heaters
at the alkylation,
benzene
extraction unit
and catalytic
feed
hydrotreating units
—
346
lbs/hr
(157 kg/hr).
F)
All boilers generating steam
for
general plant
use—
2,400 lbs/hr
(1,090 kg/hr).
G)
All heaters serving
the hydrocracker
unit
catalytic reformer No.
1,
and the saturates
gas plant
—
1,660 lbs/hr
(753 kg/hr).
H)
All process heaters
at
the aromatics east
process
—
768 lbs/hr
(348 kg/hr).
I)
All catalytic cracking units
—
3,430
lbs/hr
(1,560 kg/hr).
3
All asphalt converters, distilling
unit
No.
1,
the aromatics east process,
all boilers
generating steam for
general plant
use,
and
all gas plant process heaters
—
2,710
lbs/hr
(1,230 kg/hr.)
d)
Compliance with
the emission limitations
of
subsections
(b)
and
(c)(3)
of this Section 214.382 shall
be
demonstrated
on
a three—hour block average basis.
Such
demonstrations
shall require,
as
a permit condition,
that data,
including but not limited
to,
fuel
feed
rates, specific gravity
of refinery flasher
pitch, sour
water sulfide content,
fresh and hydrotreated
feed rates
to the catalytic cracking units
and the percent oxygen,
carbon monoxide and carbon dioxide
in the flue gas
leaving
the catalytic cracker unit regenerators be
maintained
in order
to adequately determine
the sulfur
dioxide emission rate from each source operations group.
e)
Sources
in the Village
of Roxana are not subject
to the
emission limitations
of Section 214.162 when burning
refinery flasher pitch
or refinery
fuel gas.
f)
Individual
process emission sources
in the Village
of
Roxana are still subject
to the emission limitation of
Section 214.301 notwithstanding
their
inclusion
in
a
source operations group.
~j
Notwithstanding
the provisions
of Section
201.102 of
this Chapter, any physical change
in any emission source
subject
to subsection
(b),
(c),
(d),
or
(e)
of
this
Section which alters the height of
release, temperature
or volumetric
flow rate of
the effluent gases of such
source,
or alters
the diameter
of
the exit stack,
shall
be deemed
a modification
for the purposes of
Section
201.142 of
this Chapter.
88—4 57
—16—
(Source:
Amended
at
12
Ill.
Req.
_______,
effective
_____________
IT
IS SO ORDERED.
I, Dorothy M.
Gunn,
Clerk of
the Illinois Pollution Control
Board, hereby certify that the above Proposeid Opinion and Order
was adopted on
the
~
day of
_________________,
1988,
by
a
vote
of
7—a
~
Dorothy M.
nn, Clerk
Illinois Pollution Control Board
88-458
