ILLINOIS POLLUTION CONTROL BOARD

November

3,

1988

IN THE MATTER OF:

AMENDMENTS TO

35

ILL.

)

ADM. CODE

214,

)

R86—30

SULFUR LIMITATIONS

(Petition

)

of Shell Oil Company)

ADOPTED RULE.

FINAL ORDER.

OPINION AND ORDER OF THE BOARD

(by

3.

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

(ETC)

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 filed

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.

93—369

---

—2—

On April

21,

1988 the Board proposed for First Notice

a rule

which was substantially the same as

the rule submitted by Shell

and the Agency.

The proposed rule was published

in the Illinois

~gister

on May 13,

1988,

at

12

Ill.

Reg.

8219.

Several comments were received after

First Notice

publication.

The Department

of Commerce and Community Affairs

filed

a comment which stated that

the proposed rule will have no

effect on small businesses regulated by the rule.

(P.C.

#2.)

The Board notes

that this rule regulates only Shell’s WRMC.

Comments were also filed by Shell

(P.C.

#1) and the Agency

(P.C.

#3).

(The substance of those comments will be addressed

later

in

this Opinion.)

On October 19, 1988 the Joint Committee on Administrative

Rules

(JCAR)

filed

its Certification of No Objection

to the

rule.

To satisfy concerns raised by JCAR,

the Board has agreed

to modify Sections 214.104

and 214.382,

and

to update the

authority

note,

to read

as set forth

in the Order below.

These

modifications do not change

the substance of the rules.

BACKGROUND

The purpose behind

the joint proposal

is

to remedy the

inadequacy

in the Illinois SIP for SO2.

On September

28,

1984,

USEPA notified Governor Thompson that

it found the SIP

substantially inadequate

to achieve the NAAQS

for SO2

in the

Alton and Wood River areas of Madison County,

Illinois.

The SIP

deficiency notice was made pursuant

to Section 11O(a)(2)(H) of

the Clean Air Act,

42 U.S.C.

7410(a)(2)(H).

USEPA 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,

hydrocrackirig, 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.)

93—370

---

—3—

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 WRMC’s fuel gas system.

(Tr.I,

pp.

61—62;

Transcript

of January

22,

1988

(Tr.

II),

pp.

40—41.)

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

(1.0

lb.)

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 H2S

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

(SAtJ),

and

.3—371

---

—4—

the Sulfur Recovery Unit

(SRU).

These processes produce sulfur

emissions

to varying degrees.

(Tr.I, pp.

65—67.)

SO2 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

rate during the period 1982

through 1985 was 11,063 lbs/hr,

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 oroposal,

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 s02 emissions more

in line with

the actual

emissions.

This

is possible because

there

is considerable

redundancy

in the various refinery processes.

For example,

there

93—372

---

—5—

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

limit.

The emissions cap for

a SOG is less than the total of the

current maximum permitted emissions from each individual source

within that SaG.

As

a result,

the SOG more closely reflects

actual maximum condition.s.

The proposal contains nine SOGs.

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

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 SO2 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 milliort(ppm)

93—373

---

—6—

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 l960s,

and was allowed

for by Section 214.382(a)

of the

Board’s regulations.

In

1985, Shell

tied the D—train into the

existing tailgas cleanup unit, called

the SCOT unit.

The SCOT

unit had sufficient capacity

to accommodate the additional gas

load.

This tie—in decreases SO2 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 D—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 214.382(c)(l).

The joint

proposal would also add

a new subsection

Cc)

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 sho~icompliance with proposed Section 2l4.382(c)(2).

Additionaly,

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)(1)

states that

compliance with that subsection shall

be demonstrated by daily

93—374

---

—7—

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, USEPA 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

source

to which subsection

(c)

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

9

3—375

---

—8—

modeling done

to assure that the joint proposaJ

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 SO, 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 sEudies 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 regulatio~5were

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

at

any receptor near WRMC are less

than or equal

to the 24—hour

air quality standard for SO2.

Thus,

the Agency 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 Reductions

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/Roliback

(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

93—376

---

—9—

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—1,

and LFE—Ext

Furnaces

—657

Revise SRU/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 SO2 per hour,

full

capacity operations

at WRMC produce actual emission rates

of

approximately 13,000 pounds

per hour.

(Tr.

I,

pp.

48—49.)

Since

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.

RESPONSE TO FIRST NOTICE COMMENTS

Section

214.101.

In

its First Notice proposal, the Board made

some changes

to Section 214.101(c) which were intended merely

to

clarify which procedures are

to be used for solid

fuel averaging

measurements.

Shell believes that these proposed changes go

beyond

the scope of this proceeding, and states that the changes

are the subject of rulemaking

in Measurements Methods

for

Emissions of Sulfur Compounds, R87—31.

Shell submits that the

changes

to

subsection

Cc)

are not required

to make this site

specific rule operative.

The Board agrees,

and will not adopt

any changes

to subsection

(C).

The Board also proposed

a new Section 214.101(h)

to provide

for the use of the Tutwiler procedure for measurement of the

concentration of hydrogen sulfide

in petroleum refinery fuel

gas.

Shell believes that this subsection needs to be qualified

as applying only to compliance determinations for Section

214.382(c).

(Section 2l4.382(c) contains the bulk of

the

rules

proposed

in this proceeding,

and applies only to Shell’s WRMC.)

Shell states that other petroleum refineries

in Illinois use

other measurement procedures

as permitted by the Agency.

Shell

also maintains that subsection

(h),

as proposed at First

Notice,

could

be

in conflict with future changes

to the federal

93—377

---

—10—

new source performance standards, which may set

a standard

for

continuous emission monitors.

The Board again agrees with

Shell’s comments,

and will qualify Section 214.101(h)

as applying

only to compliance determination for Section 214.382(c).

Section 214.382(d)

—

permit conditions.

At First Notice the

Board added

a sentence

to proposed Section 214.382(d)

which

requires,

as a permit condition,

that data be maintained

in order

to adequately demonstrate compliance.

The Board specified

certain types of data,

and asked

for comment

on that listed

data.

In its comments,

the Agency agrees

that these

types of

data are necessary to calculate compliance.

The Agency does

suggest that some proviso be

inserted

to allow

the elimination of

some of the required data,

through permit decision,

if that data

is no longer needed because

of the addition of continuous

emission monitors.

Shell maintains that the listed information

is much

too specific and would

not be necessary if Shell chooses

to show compliance through

the use of continuous emission

monitors or other measurement methods.

Shell proposes that the

language of Section 214.383(d)

be modified.

The Board

is persuaded that the language of Section

214.382(d)

should be less specific on what data must be

maintained.

Therefore,

the Board will delete the specific data

listed

in

its First Notice proposal, and

instead generally

require that sufficient data be maintained

to adequately

determine

compliance.

Thus,

the Agency will determine,

as part

of the permitting process,

exactly what information must be kept

by Shell.

The Board believes that this change will

allow for the

flexibility desired by Shell and suggested by the Agency, while

achieving the Board’s objective of proof

of compliance.

Section 214.382(e)

—

exemption from the “combination of fuels”

rule.

In

its April

21 First Notice opinion,

the Board expressed

concern over the proposed exemption from Section 214.162

“Combination of Fuels.”

The Board stated that it was unable

to

clearly see why Shell cannot use the equation set out

in Section

214.162,

and asked

for comment on the issue.

Both the Agency and

Shell have responded.

The Agency states that the practical

reason

for the

exemption from Section 214.162

is that the Tutwiler procedure,

which

is specified for compliance demonstration, does not

calculate emissions

in pounds per million Btu and thus will not

yield

a pounds per hour emission rate.

Instead,

the Tutwiler

method calculates the amount of sulfur

in the fuel.

The Agency

states that

Shell

has

shown

that

the

heat

content

of

its

fuel

is

remarkably

constant.

With that basic

fact,

and using the

Tutwiler method,

the Agency submits that compliance may be shown

in

a

very straightforward

manner.

Likewise, Shell contends that

the exemption from the combination of fuels

rule

is meant only

to

greatly simplify compliance auditing.

Shell

states that the

93—373

---

—11-

emission limits

in Section 214.382

are not higher than wot~ldbe

provided

for

in Section 214.162.

The Board

is satisfied by these

responses,

and will adopt the exemption from Section 214.162.

Procedure for

alternative emission rates.

The only portion of

the joint proposal which

the Board did not propose

for First

Notice was the

request for

a subsection which would establish

a

procedure for obtaining an alternative emission rate to the

limits set forth

in this rule.

In

its comments,

Shell again asks

that such

a procedure be included

in the

rule.

Shell contends

that an alternative emission rate procedure is desirable and

necessary

to provide flexibility

for future development.

Shell

maintains that the delay required

for full rulemaking would most

likely stifle Shell’s ability to respond

to changes

in technology

or market place demands.

The Agency did not comment on this

issue.

The Board will not add

an alternative emission rate

procedure

to the proposed rule.

As noted

in the April

21,

1988

First Notice opinion,

a site specific rule is,

by definition,

tailored

to

the needs

of

a particular

facility.

An alternative

emission rate within a site specific regulation might allow

a

facility

to “escape”

from emission limits which

the facility

itself originally proposed, without proceeding through the notice

and comment provisions of rulemaking.

The Board also notes

that

although Shell contends

in its comments that an alternative

emission rate would not change limitations on sulfur content

of

fuel and sulfur dioxide from various processes,

the revised joint

proposal suggests that alternative emission rates be allowed

from

the subsections which set limits on the sulfur content of

the

refinery flasher pitch and the allowable hydrogen sulfide

in the

refinery fuel gas burned by Shell.

(Ex.

9.)

Other comments.

In

its April

21,

1988 Proposed Opinion,

the

Board raised questions on several other

issues.

The Agency and

Shell responded

to those questions.

First, Shell has provided

the equivalency calculation for the emission limit change

for the

sulfur recovery unit (SRU)

from 14 lbs/ton of sulfur recovered

to

1000 ppm in the final flue gas.

(P.C.

#1, Attachment

A.

)

The

Agency states that the proposed 1000 ppm limit approximates the

present limit of 14 lbs/ton of sulfur recovered.

Both the Agency

and Shell agree

that the primary reason

for

the change

to a

concentration limit

is

to provide a simpler and more easily

audited method of determining compliance.

Second,

the Agency and

Shell

state that the eight—hour

sampling requirement

for refinery

fuel gas

(Section 2l4.382(c)(2))

is consistent with the

requirements of Shell’s existing permits from the Agency.

Third,

both the Agency and Shell explain

that the emission limits

for

each source operations grouping

(SOG) were based on air quality

limits.

The allowable emissions

under current Board regulations

were reduced until modeling showed that the reduced emissions

would

not meet the NAAQS.

Finally, Shell states that the

93— 379

---

—12—

proposed rule has been placed within the section which

regulates

the industry

to be consistent with other

portions of the air

regulations.

The Agency agrees with

the Board that this rule

could be placed

in its own section, but submits

that leaving

the

rule within Section 214.382 will not cause confusion.

Thus,

the

Board sees no need

to alter

the proposed rule in response

to any

of these issues.

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 adopt

the

bulk

of the requested relief.

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 adopt 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.

The Board

notes that 35 Ill.

Adm. 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 SEW 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.

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.

93—380

---

—13—

ORDER

The Board hereby adopts,

as final,

the following amendments

to be

filed with the Secretary of State.

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).

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 be 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.T.M. procedures shall be used for solid

fuel sampling,

sulfur

and heating value determinations.

h)

Hydrogen Sulfide Measurement.

For purposes of

determining compliance with Section 214.382(c),

the

concentration of hydrogen sulfide

in petroleum refinery

fuel gas shall be measured usin9

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:

93—381

---

—14—

btu

British

thermal units

(60

F)

ft

foot

gçains

J

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

vol u me

ng/J

nanograms per Joule

ppm

parts per million

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

1b/T

0.500

kg/Mg

mmbtu/hr

0.293

MW

1

lb/mmbtu

1.548

kg/MW—hr

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.

These

incorporations do not include any later amendments or editions.

a)

40 CFR 60, Appendix A

(1982):

1)

Method

6:

method for measurement of sulfur dioxide

emissions;

93—382

---

—15—

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 D—2013

(1976)

2)

For sulfur determinations:

P.STM D—3177

(1976)

ASTM D—2622

(1982)

3)

For heating value determinations:

ASTM D—2015

(1976)

ASTM D—3286

(1976)

c)

Tutwiler Procedure for hydrogen sulfide,

40 CFR 60.648

(1986).

(Source:

Amended

at

12

Ill. Reg.

______,

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

n~w

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.

~e exeeed ~4 ib~’P~?

~?ttr

d~4~e

per

me~r4e

~on

ef ~ft~r

ree ~ere~

f~

~g+~

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

93—383

---

—16—

fuel gas contains more

than 39 grains hydrogen

sulfide

per

100

dry

standard

cubic

feet

(893

mg/scm).

This shall

be demonstrated by sampling

the refinery fuel gas once every eight

hours,

pursuant

to the Tutwiler Procedure (Section

214. 104(c)).

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

(5~71kg/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).

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).

C)

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).

J

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

tI,230 kg/br).

d)

Compliance with

the emission limitations of subsections

(b) and

(c)(3)

of this Section shall

be demonstrated on

a three—hour

block average basis.

Such demonstrations

Shall

require,

as

a permit condition,

that data

as

required by the fliThois Environmental Protection Agency

93—384

---

—1

7—

(35 Iii.

Adm Code 201.161)

be maintained

in order

to

adequat~e1y

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

35

Ill.

Adm. Code

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

35

Ill.

Adm.

Code 201.142

of

this Chapter.

(Source:

Amended

at

12

Ill.

Reg.

______,

effective

____________

IT

IS SO ORDERED.

R.

Flemal

was

not

present.

I, Dorothy M.

Gunn, Clerk

of the Illinois Pollution Control

Board,

hereby certify that the above Proposed Opinion

and Order

was adopted

on the

~

day

of

~

,

1988,

by

a

vote

of

~--O

2

Dorothy

M./Gunn,

Clerk

Illinois

Pollution

Control

Board

93— 385