JN—30—2009

1654

HOD6E

DLJYER

ZEMPN

217

523

4948

P.01/45

BEFORE

THE

ILLINOIS

POLLUTION

CONTROL

BOARD

IN

THE

MATTER

OF:

)

)

NITROGEN

OXIDES

EMISSIONS

FROM

)

VARIOUS

SOURCE

CATEGORIES:

)

AMENDMENTS

TO

35

ILL,

ADM.

CODE

)

PARTS2IIand217

)

ROB-

19

(Rulemaking

-

Air)

NOTICE

OF

FILING

TO:

Mr.

John

T.

Thernault

Assistant

Clerk

of

the

Board

Illinois

Pollution

Control

Board

100

W.

Randolph

Street

Suite

11-500

Chicago,

Illinois

60601

(VIA

ELECTRONIC

MAIL)

Timothy

Fox,

Esq.

Hearing

Officer

Illinois

Pollution

Control

Board

100

W.

Randolph

Street

Suite

11-500

Chicago,

illinois

60601

(VIA

FIRST

CLASS

MAIL)

(SEE

PERSONS

ON

ATTACHED

SERVICE

LIST)

PLEASE

TAKE

NOTICE

that

I

have

today

filed

with

the

Office

of

the

Clerk

of

the

illinois

Pollution

Control

Board

the

SUPPORTING

MATERIALS

FROM

UNITED

STATES

STEEL

CORPORATION,

a

copy

of

which

is

herewith

served

upon

you.

Respectfully

submitted,

Dated:

January

30,

2009

Katherine

D.

Flodge

Monica

T.

Rios

HODGE

DWYER

ZEMAN

3150

Roland

Avenue

Post

Office

Box

5776

Springfield,

Illinois

62705-5776

(217)

523-4900

By:

Is!

Katherine

I).

Hodae

Katherine

D.

Hedge

TilES

FiLING

SUaMITTED

ON

RECYCLED

PAPER

---

JAN—30—2009

16:55

H006E

DWYER

ZEMFIN

217

523

4948

P.02/45

BEFORE

THE

ILLINOIS

POLLUTION

CONTROL

BOARD

N

THE

MATTER

OF:

)

)

R08-19

NITROGEN

OXIDES

EMISSIONS

FROM

)

(Rulemaking

-

Air)

VARIOUS

SOURCE

CATEGORIES:

)

AMENDMENTS

TO

35

ILL.

ADM.

CODE

)

PARTS211and217

)

SUPPORTING

MATERIALS

FROM

UNITED

STATES

STEEL

CORPORATION

NOW

COMES

UNITED

STATES

STEEL

CORPORATION

(“U.S.

Steel”),

by

and

through

its

attorneys,

HODGE

DWYER

ZEMAN,

and

submits

the

attached

SUPPORTING

MATERIALS

in

the

above-referenced

matter.

1.

On

December

10,

2008,

Mr.

Larry

Siebenberger

on

behalf

of

U.S.

Steel,

as

well

as

U.S.

Steel’s

consultant,

URS

Corporation

(“TJRS”),

presented

testimony

in

the

above-referenced

matter.

During

the

course

of

U.S.

Steel’s

testimony,

the

Illinois

Environmental

Protection

Agency

(“Agency”)

or the

Illinois

Pollution

Control

Board

(“Board”)

requested

additional

documents

or

information

in

response

to

testimony

by

Mi.

Siebenberger

or

U.S.

Steel’s

consultants.

2.

The

following

materials

are

being

provided

in

response

to

Agency

or

Board

requests

at

hearing:

a.

On

page

18

of

the

December

10,

2008

transcript,

the

Agency

requested

data

calculations

regarding

expected

NOx

emissions

for

Boilers

11 and

12

if

only

desulfi.u’ized

coke

oven

gas

(“COG”)

were

used

in

combination

with

flue

gas

recirculation

(“FOR”).

U.S.

Steel

has

provided

a

“Description

of

NOx

RACT

Emission

Rate

For

Boilers

11

and

12

(Assuming

all Coke

Oven

Gas is

Scrubbed)”

as

Attachment

A.

Attachment

A

is

a

supplement

to

Exhibit

A

of

the

Pre-filed

Testimony

of

Larry

G

Siebenberger

med

with

the

Board

on

November

25,

2008.

b.

On pages

29

through

30

of

the

December

10,

2008

transcript,

the

Agency

requested

data calculations

regarding

expected

NOx

emissions

for

reheat

furnaces

if

only

desulfurized

COG

were

used

---

JAN—30—2009

16:55

HODGE

DWYER ZEMAN

217

523

4948

P.03/45

in

combination

with

the

low

NOx

burner

configuration

now

being

installed.

U.S.

Steel

has

provided an

“Estimation

of

NOx

Emissions

for

Slab

Furnaces

1.2,

3

and

4 assuming

All

Coke

Oven

Gas

is

Desulfurized”

as

Attachment

B.

Attachment

B

is a

supplement

to

Exhibit

B

of

the

Pre-filed

Testimony

of

Larry

G.

Siebenberger

filed

with

the

Board

on

November 25,

2008.

c.

On

page

25

of

the

December

10,

2008

transcript,

the

Agency

requested

historical

data

on

COG

coinbusted in

Boilers 11

and

12.

U.S.

Steel

has

provided

a

spreadsheet

of

historical

data

on

COG

combusted

in

Bolers

11

and

12

as

Attachment

C.

d.

On

page

28

of

the

December

10,

2008

transcript, Mr.

Larry

Siebenberger

verbally

revised

Exhibit

A

to

his

preffled

testimony

changing

the

percentage

of

COG

in

the

fuel

mix

from

60

percent to

40

percent.

U.S.

Steel

has

provided

a

correction

to its

boiler

calculation

submittal

as

Attachment

D,

On

pages

28

through

29

of

the

December

10,

2008

transcript,

the

Agency

requested

information

regarding URS’s

emissions

calculations.

U.S.

Steel

has

provided a summary

of

the

“Boilers

ii

& 12

NOx

Reduction

Study”

performed

by

URS

as

Attachment

E.

f.

On

page

31

of

the

December

10,

2008

transcript,

the

Agency

requested

a

copy

of

the

technical

proposal

from

Bloom for

reheat

furnaces.

U.S.

Steel

has

provided

a

summary

of the

Bloom

Engineering

proposal

as Attacirnient

F.

g.

On

pages

32

through 33

of

the

December

10,

2008

transcript, the

Agency

requested information

regarding

uncontrolled

NOx

rates

for

slab

reheat

furnaces

heated

by

COG

and

natural

gas.

U.S.

Steel

has

provided

such

information

as

Attachment

G.

3.

U.S.

Steel

reserves the

right

to

supplement

these

supporting

materials.

Respectfully

submitted,

Dated:

January

30,

2009

By:

Is!

Katherine

DJodge

Katherine

D

Hedge

Katherine

D.

Hedge

Monica

T. Rios

HODGE

DWYER

ZEMAN

3150

Roland Avenue

Post

Office

Box

5776

Springfield,

Illinois 62705-5776

(217)

523-4900

USSC:OOI/FiI/RO-19/Supportin

Ma(cnals

2

---

JRN—30—2009

16:55

HODGE

DWYER

ZEMAN

217

523

4948

P.04/45

.LLVIZJL1

I

A

United

States

Steel

Corporation

Granite

City

Works

Description of

NOx

RACT

Emission Rate

For

Boilers

11

and

12

(Assuming

all

Coke

Oven

Gas

is Scrubbed)

USS’

Granite

City

Works

has

estimated

the

emissions

for

its

boilers

11

and

12

in

response

to

the

Illinois

Environmental

Protection

Agency’s

proposed

rule

to

require

that the

emissions

units

employ

Reasonably

Available

Control

Technology

(RACT)

on

these

two

units.

The

Illinois

Pollution

Control

Board

has

proposed

revisions

to

Title

35

Part

217

which

would

require

these

Units

to

meet

emissions

limits

that

have

been

proposed

as

RACT. While

these

units

meet

the

definition

of

industrial

boilers

in

which

would

be

regulated

under

Subpart

D

of

the

proposed

rule,

the

fuel

mix

that

they

fire

is

unlike

that

of

a typical

industrial

boiler.

Therefore,

an

evaluation

was

undertaken by

URS

Corporation

for

USS

to evaluate

potential

control

technologies

applicable to the

units

and

estimate

the resulting

emissions for

technologies

that

are

found

to

be

feasible.

The

URS

evaluation found

that

because

of the

unique

mixture

of

fuels

fired

by

the

units,

the

only

technically

feasible

control

technology

is

Flue

Gas

Recircujation

(FGR).

The

potential

emissions and

emissions

reductions

related

to

the

use

of

FGR

were

evaluated. The evaluation

method

is

described

below.

RACT

emissions

estimates

for

NO

emissions

from

boilers

11 and

12

were

developed

as

three

distinct

components

that

represent

three

distinct

operational

conditions

that

the

boilers

operate

under.

These

are:

•

Normal

operations,

•

Operations

while

a

blast

furnace

is

out

of

service

(limiting

the

supply

of

one

of

the

fuels

(blast

furnace

gas

(BFG)

used

by

the

boilers),

and

•

Operations

while

the

desulfurization

unit

that

is being

constructed

to treat

the

coke

oven

gas

(COG),

one

of

the

fuels

used

by

the

boilers

is off-line

in

maintenance

mode.

This

analysis was

done

for

the

two

boilers

in

combination

since

that

is

the

way

the

steam

produced

by

the

boilers

is used.

Each

boiler

has

a heat

input

capacity

of

225

MMBtu

per hour.

Therefore,

the

analysis

has

been

done

based

on

the

total

heat

input

of 450

MMBtu

per

hour.

The

calculation

of

estimated

emissions

for

each

of these

operational

modes

is

described

below.

Boiler

URS

Ca’culation

Corporation

Page

1

of

3

suIf

COG

oiLy

November

24, 2008

---

JRN—30—2009

16:56

HODGE DWYER

ZEMAN

217 523

4948

P.05/45

Normal

Operations

For this analysis,

normal

operations

were calculated

as

operations during those

times when the two

blast furnaces

at the facility

are

in operation

and providing

the

full

potentially

available

BFG.

Key

assumptions

for this mode

of operations

include:

Blast furnace

maintenance time

as shown in table

below:

Ozone Season

Annual

15

15 days

Blast Furnace Rebuild

55 days

Blast Furnace Down

(15%) of

time

annual

basis

23

days Blast

Furnace

Down (15%) of time

ozone season

basis

2

2

days

maintenance

outage

40

72 days

Total Maintenance

Outage

• a fuel

mix on the boilers

of:

o 25%

natural gas (NG)

o

35%

BFG

o

40% COG

• a capacity factor

of 100%

• controlled

NOx

emission rates (lbs/MMBtu) of:

o

0.084

NG

o

0.0288

BFG

o 0.144

COG

Furnace Downtime Operations

• Furnace downtime

o

15 days furnace

rebuild

o

15%

downtime

per furnace (55 days

for

annual

and 23 days

for

ozone

season)

o 2 days mawitenance

outage

•

Fuel Mix

oNG

40%

o COG

60%

• Capacity factor 40%

• Same

emission

rates per fuel

as for normal

operations

Coke

Oven

Gas

Scrubber

Maintenance

Mode

The

Illinois EPA requested

information

on

an

emission

rate

that

does

not

include

coke oven gas scrubber

maintenance mode. Therefore,

this

mode

was

not

included in the results

described below.

URS

Corporation

Page 2 of

3

Ooibr Calcuaton

DeuIf

COG

only

Novamber 24.2008

---

JAN—30—2009

16:56

HODGE DWYER ZEMAN

217

523

4946

P.06/45

Baseline conditions

were calculated

using

the same

assumptions

presented

above but with the

following

emission rates

in lb/MMBtu:

• 0.3

NG

• 0.066

BEG

• 0.729

COG

Results

Based on the

assumptions

and calculations

shown

above, the resulting

ozone

season

average controlled

emission rate,

for Boilers

11 and 12 is 0.093

lb/MMBtu.

URS Corporation

Page

3 of 3

Boiler Calculation Oesulf COG Only

Novan, bar 24,

2008

---

JRN—30—2009

16:56

HODGE

DW’’ER ZEMAN

217 523 4946

P.07/45

A11AC11MI

B

United

States

Steel

Corporation

Granite City Works

Estimation of

NOx

Emissions

for

Slab

Furnaces 1,2,3 and 4

assuming

All Coke

Oven

Gas is Desulfurized

USS’ Granite

City

Works has estimated

the

emissions for its slab furnaces 1, 2,

3, and

in

response to the Illinois

Environmental

Protection Agency’s

proposed

rule to require that

the emissions

units employ

Reasonably

Available

Control

Technology (RACT) on these

four units.

The Illinois

Pollution Control

Board

has proposed revisions to

Title 35

Part 217

which

would require these units to meet

emissions

limits that have

been

proposed as

RACT.

These

units meet the

definition

of

recuperative

reheat

furnaces

which would be regulated

under Subpart

H

of the

proposed

rule.

Therefore,

an

evaluation was undertaken

by USS

to evaluate

potential control

technologies

applicable

to the units and estimate

the resulting

emissions for

technologies

that are found to

be

feasible.

The

evaluation found that for

these

particular units, the

only technically

feasible

control

technology

is the installation

of low

NOx

burners. The potential

emissions

and

emissions

reductions related to the use

of tow

NO

burners were evaluated.

The

evaluation method is

described below.

RACT

emissions estimates

for

NOx

emissions

from slab furnaces I

through 4

were

developed

based on

a set of key assumptiotis. These

are:

• Emission

rates

developed

by manufacturer of

low

NOx

burners designed

for

these

furnaces (Bloom);

Projected

Ozone

Season

Furnace

Thermal Input

Emission Rate

0.

(MMBtu/yr)

(lb/MMBtu)

1

1,654,304

0.162

2

1,654,304

0.162

3

1,654,304

0.214

4

2,206,238

0.212

• Furnace downtime for maintenance

is assumed to occur

during the ozone

season;

• At the

request of the

IEPA, this calculation does

not consider the

impact

of

COG

desulfurization being

down for maintenance

35 days per year during

the ozone season.

1/3012009

Page 1 of

2

---

JFN—3Ø—2ØØ9

165E

HQDGE

DWYER

ZEMRN

217

523

4946

P.09/45

Resujts

Assuming

that

all

COG

is

desulfurized,

the

average

controlled

emission

rate

for

slab

furnaces

I

through

4

is

0.156

lb/MMBtu.

1/30/2009

Page

2

of

2

---

ATFACHI4ENT

C

LI-)

\

XE

OVEN

GAS

JAN

FEB

MAR

APR

UAV

JUN

JUL

AUG

SEP

OCT

NOV

DEC

16

%WBtu

%

MMBIu

%

MMBIu

$

h!MBIu

%

Ii58Btu

%

MMatu

%

MMBI,i

%

MMBIu

%

IlMBtu

%

liMmu

%

MMBIu

%

MMBLu

%

0..

0

Bonr3

109.054

26.66%

91,6962986%

304,597

3165%

1942423254%

90,642

27.899.

33,299

32.83%

73,079

2486%

103.496

39.07%

9l605

3883%

130,917

4347%

127,560

36.46%

115.843

40.51%

33,812

38.03%

43,605

3963%

53,52?

36.79%

50,14?

30.77%

43,164

2023%

26.507

25.58%

43,496

5928%

21,390

46.72%

36.120

3082%

40.039

3124%

48446

42.40%

50.405

46.38%

581,194

Baler

43,991

3735%

46.615

40.34%

53,007

42.01%

50.460

41.10%

93160

2563%

14.724

7525%

81.156

56.79%

90.415

13.24%

81,04?

64.10%

66.614

6699%

69.760

72.95%

41.447

47.32%

722.570

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

(J

7

WllBIu

%

IlMEtti

%

MMSIU

%

MMBOu

$

MMBLU

$

MMD,tu

%

MMBto

%

MF4SIu

%

MMBILI

%

MMStu

%

MMBIII

%

MMBIe

%

Total

10&68r5

113.151

31.78%

66.304

31211%

99.583

28.49%

04.639

28.45%

111276

34.05%

07.026

25.14%

76,230

22.65%

61.953

17.44%

73,018

23.50%

66,297

1525%

70.036

2295%

33.2132038%

Bcder

40,454

26.99%

14,960

10.74%

3.665

241%

33,632.

29.92%

10233

31.47%

20,202

31.34%

8.839

6.15%

15,398

17.08%

83,786

8340%

35,801

2823%

313,198

15.67%

34,5192734%

257.131

gciiec

iiu

28.50%

a

10.59%

565

1.50%

13.636

67.15%

85,347

76.90%

65,961

65.73%

14.164

26.80%

20,965

25.72%

43,083

51.72%

47.797

4425%

45671

41.54%

53,806

57.55%,

493,799

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

98

MMBtu

%

MMB(u

%

MMBta

%

MNBtu

%

UMB6s,

%

MMBIu

%

MMBLu

%

MMBIu

%

MIWIU

%

UMBIu

%

MMDLo

%

MMBtu

%

106viler

97.842

2550%

66,663

31.94%

97.015

31.09%

53.438

7938%

95.915

2790%

813,653

3614%

67.673

73104%

41,442

33.51%

80.313

2923%

83,05?

2743%

91542

31.11%

110,118

3426%

66466348

BaSer

21.756

3527%

21555

39310%

25349

21.93%

27,073

20.35%

83.789

2086%

49566

2851%

18,214

19.44%

42.85?

38.89%

48.469

4938%

53,429

4834%

33,315

41.12%

34.101

35.54%

383,167

50,466

47.73%

37296

4121%

51,257

4520%

47,585

42.92%

60,139

6583%

9

6.90%

34,135

4120%

35,300

36.12%

34.189

21.75%

34.160

2583%

32.506

43.47%

36,100

34.64%

456.485

JAN

FEB

MAR

APR

MAY

JUN

JUL

543G

SEP

OCT

NOV

DEC

39

UMBlu

%

MMBIU

%

MMBIu

%

MMDIu

%

MMBtu

%

MlABtij

%

W1BIu

%

MMBtu

%

MMBhi

%

MMB4u

%

MMUki

51

MSlBtu

%

Total

181

6ii1a

109,500

33.78%

51207

32.55%

638,091

41.60%

76.085

28.47%

07.685

33.30%

80.930

26.32%

50346

22.28%

56237

28.80%

67,902

21.37%

125.23?

31.42%

193,955

32.17%

91,386

29.3170

#5865448

Ooler

34.842

36.85%

30,95626.99%

33,337

34.63%

28.338

34.75%

3,277

94.09%

24.538

46.60%

30.143

41.40%

41.113

3211%

32,560

26.09%

54.725

4929%

38.324

3142%

40,423

28.32%

407.135

2

13,611

1551%

21,101

24.06%

34.S3

32.54%

35.103

3616%

31.830

3214%

26,015

25.82%

31.724

32.89%

32,199

1235%

5.995

11.27%

239

1.94%

33,988

37.24%

36.308

39.88%

303.265

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

0*

MMDIa

‘6.

IIMEILI

%

MiABtu

%

MMBtu

%

MMfllu

%

MMD8u

51

MMSIu

V.

MMDtu

51

MMUIu

51

MMBti

%

MMBtu

V.

MMBIu

V.

Total

.19

Ba7a,

82,35.7

28.46%

81,252

2854%

68632

1973%

102,980

31.25%

63951

2659%

44325

2460%

90,751

2853%

197,467

25.20%

66,296.

2654%

109,923

2942%

1391919

4)81%

Z4,C64

36.50%

I

04.1cr

21245

4.39%

12.298

9.4511

29291

14.74%

26,803

22.16%

36.196

31.55%

20.896

3560%

30,814

26.11%

26.990

24.04%

28.745

2655%

4296

33.17%

15.136

13.77%

16,552

14.04%

281.904

l2)ar

92.017

0.04%

745

01111

7.845

5.97%

46.394

15.32%

17816

11.16%

15901

16.75%

30.557

2857%

245.31

32.45%

6.104

34.43%

22,080

2585%

3,226

3.49%

3,704

355%

169,191

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

451

MUSh.

51

MMBOU

51

MUBIu

51

NMSOIJ

V.

MMBtu

51

MMBtu

51

MllBtii

51

MB0ii

V.

MMBtu

51

MMRIu

51

MUSh.

51

MMBtu

51

Total

96588

29.22%

81.681

26.33%

61,666

16.08%

63,103

17.72%

53133

95.24%

44,930

13.52%

63,115

57.85%

99576

19.99%

66594

28.25%

41,560

12.70%

54,210

37.91%

50275

1750%

764.031

I

Bai1r

13970

11.3614

26553

23.03%

45766

3329%

23,629

2156%

24,929

20.16%

22.085

79.82%

20,738

1843%

27,277

1867%

25,520

25.5.2%

9,294

1507%

20,199

3915%

25.925

18.10%

268.951

2BGiler

4.464

4.11%

24,709

27.00%

37.0710

3440%

38.156

3730%

42,289

44.19%

21.279

36.13%

26,749

44.73%

4.196

23.18%

18,572

29.83%

25,450

2960%

3,038

7.91%

27568

2083%

383,920

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

W

92

MM54a

51

UMBIu

51

MIOBtu

51

UMBIu

51

MMBW

51

MMBIu

51

MMB8u

51

MMBtU

51

MUSh.

V.

MMStu

51

UMBIu

51

MMBta

51

P\j

.95909II

02.532

17.33%

48.696

14.40%

50,392

6331%

53,220

15.13%

07547

17.71%

53.314

1475%

53,42?

1544%

59.053

3632%

43.403

11.94%

66,975

1692%

47,704

13,54%

53,170

3457%

995,752

I

Baler

4095

2.23%

2

000%

852

6.76%

0

5816%

9

003%

0

900%

0

0.00%

0

0.90%

0

0.00%

44?

129%

1,733

8.64%

4,478

4.13%

10,050

2

BaSer

33,396

3109%

37,747

36.00%

47,937

44,92%

44.404

47.78%

15,242

4024%

30500

36.96%

31.613

3619%

43,53247.41%

28.833

36,00%

24.950

2267%

33,900

37.52%

53,283

45.40%

441,044

JAIl

FED

MAR

APR

MAY

JUN

JUL

1.010

SEP

OCT

MDV

LIEU

203

MMBIu

51

MMS3u

$

MMBIU

%

381lEtu

51

MMBtu

51

MMBlu

51

Mll.Bti’

51

90908W

51

MMBIu

51

MMBtu

51

MMB(u

V.

MUBJu

51

Tolal

-Ia

Bolers

50,679

1549%

30,805

9946%

30.738

957%

51392

1599%

60.887

16.1

7%

52,750

14.11%

44,443

1255%

48597

34.19%

44,531

1337%

50.576

14.54%

27,945

7.93%

41.905

12.38%

564.456

1

Baler

81,310

30.31%

8

0.00%

139

0.83%

12

001%

1

8500%

15,783

13.86%

11.120

10.65%

3,527

5.65%

4907

441%

2.461

5.19%

I)

0.00%

0

8500%

50.0910

2BaIer

28.306

27.91%

33,220

3644%

43,327

4606%

49,292

51.18%

18,484

46.41%

6,343

720%

10,845

1038%

28401

24.35%

12537

12.09%

11.590

13.12%

6.117

5.06%

21l17

24.58%

270,24?

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

304

MMS3U

V.

MMDlu

51

MMBtij

51

MUSh.

51

MMBIi

V.

MMBLIi

51

MMD8u

51

MMBtu

51

IlMBtu

51

MMhlu

51

WBtu

51

MMDLII

51

Total

I-105$lers

42.403

15,48%

49,623

15.86%

46,202

1543%

34574

12.38%

38668

12.96%

33,304

11.41%

63,375

0.27%

41,113

16.53%

40,492

35.86%

23.830

7.01%

30,918

1293%

41,968

13.65%

473,563

Ii

Baler

0

6.00%

0

0.06%

0

0.08%

0

0.00%

0

0.89%

I)

90018,

1)

8500%

0

600%

31,200

29.44%

2,400

4.32%

(I

0.90%

8)

0.06%

33,603

l2Bcilet

35.465

3240%

32.532

27.76%

33,11?

31.44%

34,639

3315%

32.031

32.46%

9.040

97%

15,464

1513%

8,502

1763%

3,464

19.22%

2355?

2644%

13293

1238%

22189

18506%

267,939

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

045

UMSIu

51

MUSh.

51

MMBIu

51

MM8tu

51

MMBtia

51

SAMDtu

51

P4605tu

51

MUBIu

51

MMD1u

51

MIADW

51

MUSh.

51

MMB(u

V.

total

I>’

l.108dler

28,496

777%

36.069

11.49%

39.148

1956%

34545

10.74%

37.634

17.63%

41,500

15.4370

49,383

1630%

35,882

1827%

33,736

12.03%

49596

14.10%

50.042

1522%

59.140

1546%

5.21.406

LI)

ii

Boiler

I)

6.00%

0

0.89%

0

093%

48

0.00%

.

0

0.00%

(1

0.480%

0

-

0

080%

0

040%

0

000%

0

0.00%

0

0848%

0

I2Bcilet

72.915

21.66%

11.486

14.74%

20.983

19.29%

17.106

10.49%

9,263

4654%

0,950

16.50%

13.430

1528%

13,271

2455%

20,659

21.13%

12,719

12.410%

82,437

1266%

14.719

14.39%

175.521

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

906

MIlBtu

51

NMBtu

51

MMBIu

51

MMBIu

14

UMBLU

51

MMBIu

51

UMBIu

51

bIMBlu

14

MMDIII

51

F4MBIU

51

MM&i

51

MMStu

51

Total

(TI

j459i4l

50.105

44.93%

43,550

14.55%

43,653

16.7091.

31,848

956%

43,701

1249%

470992

15.87%

45,585

15.21%

40,820

12.74%

41,316

1325%

50,381

28.43%

30,672.

25548%

40454

2957%,

538,121

QlIBolOcc

3,50012911

-

8500%

5.053.46%

-

5,46%

.

4840%

500%

-

0.00%

-

0.048%

040%

-

093%

-

080%

-

0.943%

3,813

83

BaIler

33,647

2242%

10,253

2253%

313574

27.92%

29.405

2994%

2,195

4.46%

26299

38.74%

19,690

1932%

30,010

2971%

33)394

37.31%

9,033

1428%

33,629

36.5598,

30,363

32.15%

200,218

JAN

FEB

lIAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

0107

MMBIu

51

MMBIv

51

MMBtio

51

MUBOu

51

MMBtu

51

MIOBtu

51

lIlIBtu

51

MUB6u

51

MUSts

51

MMDOu

51

MMBIU

51

MUSts

51

Total

z

cr

1-

---

-lOBo?ers

68.783

34)9%

41.595

1833%

38.165

1405%

14.291

4.82%

29.177

9.4.5%

29.092

1.22%

19992

433%

13.817

5.22%

9.105

3.48%

13.796

4.96%

12.700

4.61%

25373

9.16%

37ç44

\IBcOsr

0080%

004)0%

004)3%

0009%

0

800%

LI

0.90%

(0090%

0000%

09.00%

0000%

0

0.06%

00.00%

0

Q2Bc4er

15.515

18.01%

24.590

24.11%

22361

20.57%

19.325

19.94%

15,188

21.92%

11.560

2785%

27.449

2599%

19.720

19.36%

19.381

17.59%

5.307

14.13%

34.773

35.42%

17.955

19.41%

220.653

-I

JAil

FEB

MAR

APR

MAY

JUN

JUL

IWO

SEP

OCT

NOV

DEC

MMB9v

‘%

MMUIu

51.

MMBSu

51.

MMEbs

%

MMBIu

%

flOtu

51.

M4u

51.

!dMflcu

54.

MMB(u

54.

MMBLIZ

54.

MI!Btu

54

MMBLu

%

Total

23246

046%

10493

5.95%

19364

5.93%

25,045

8.81%

32.540

9025%

357420

11.54%

34.882

11.86%

12.748

4.53%

11,450

4.34%

7,925

3.33%

20ft03

631%

52.969

24.69%

249.733

0

090%

0

9.00%

0

9.00%

76

9.01%

4>

9.00%

0

000’%

41

003%

32

092%

0.272

51)3%

0

iS.50%

337476

31.94%

0

000%

zsolier

25.513

21.46%

18501

1645%

20.482

11.55%

23240

2228%

9.794

1.04%

336

029%

12765

10.16%

13968

12.03%

5.599

0.44%

44,682

80.14%

10126

29.29%

25.950

62.75%

19%494

0-I

(N

N

,-1

z

cc

E

w

N

w

DI-

3

w

0

Q

0

I

---

JAN—30-2009

16:57

HODGE

DIJY’ER

ZEMAN

217

523

4948

P.11/45

D

United

Statas

Steel

Corporation

Granite

City

Works

Description

of

NOX

RACT

Emission Rate

and

Emission

Reduction Calculations

USSR

Granite

City

Works

has

estimated

the

emissions

for

its

boilers

11

and

12

response

to

the

Illinois

Environmental

Protection

Agency’s

proposed

rule

to

require

that

the

emissions

units

employ

Reasonably Available

Control

Technology

(RACT)

on

these

two

units.

The

Illinois

Pollution

Control

Board

has

proposed

revisions to

Title

35

Part

217

which

would

require

these

units

to meet

emissions limits

that

have

been

proposed as

RACT.

While

these

units

meet

the

definition

of

industrial

boilers

in

which

would

be

regulated

under

Subpart

D of

the

proposed

rule,

the fuel

mix

that

they

fire

is

unlike

that

of

a

typical

industrial boiler.

Therefore, an

evaluation

was

undertaken by

URS

Corporation

for

USS

to

evaluate

potential

control

technologies

applicable

to

the

units

and

estimate

the

resulting

emissions

for

technologies

that

are

found

to

be

feasible.

The

URS

evaluation

found

that

because

of

the

unique

mixture

of

fuels

fired

by

the

units,

the

only

technically feasible

control

technology is

Flue

Gas

Recirculation

(FGR).

The

potential

emissions

and

emissions reductions

related

to

the

use

of

FOR

were

evaluated.

The

evaluation method

is

described

below.

RACT

emissions

estimates

for

NOx

emissions

from

boilers

11

and

12

were

developed

as three

distinct

components

that

represent

three

distinct

operational

conditions

that

the

boilers

operate under.

These

are:

•

Normal

operations,

Operations

while

a

blast

furnace

is

out of

service

(limiting

the

supply

of

one

of the

fuels

(blast

furnace gas

(BFG)

used

by

the

boilers),

and

• Operations

while

the

desulfurization

unit

that

is being

constructed to

treat

the coke

oven

gas

(COG),

one

of the

fuels

used

by

the

boilers

is

off-line

in

maintenance

mode.

This

analysis

was

done

for

the two

boilers

in combination

since

that

is

the

way

the

steam

produced

by

the

boilers

is

used,

Each

boiler

has

a

heat

input

capacity

of 225

MMBtu

per

hour.

Therefore,

the

analysis

has

been

done

based

on

the

total

heat

input

of

450

MMBtu

per

hour.

The

calculation

of

estimated

emissions

for

each

of

these

operational

modes

is

described

below.

URS

Corporation

Page

1 of

3

Boiler

Calculation

Submittal

CorrectIon

November

24,

2008

---

JAN—30-2009

16:58

HODGE

DWYER

ZEMRN

21?

523

4948

P.12/45

Normal

Operations

For

this

analysis,

normal

operations

were

calculated

as

operations

during

those

times

when

the

two

blast

furnaces

at

the

facility

are

in

operation

and

providing

the

full

potentially

available

BFG.

Key

assumptions

for

this

mode

of

operations include:

.

Blast

furnace maintenance

time

as

shown

in

table

below:

Ozone

Season

Annual

15

23

2

40

15

days

Blast

Furnace

Rebuild

55

days

Blast

Furnace

Down

(15%)

of

time

annual basis

days

Blast

Furnace

Down

(15%)

of

time

ozone

season basis

2

days

maintenance

outage

72

days

Total

Maintenance

Outage

•

a

fuel

mix

on

the

boilers

of:

o

25%

natural

gas

(NG)

o

35%8FG

o

40%

COG

•

a

capacity

factor

of

100%

•

controlled NOx

emission rates

(lbs/MMBtu)

of:

o

0.084

NG

o

0.0288

BFG

o

0.144

COG

Furnace

Downtime Operations

•

Furnace downtime

o

15 days

furnace

rebuild

o

15%

downtime

per

furnace (55

days

for

annual and

23

days

for

ozone season)

o

2 days

maintenance

outage

•

Fuel

Mix

oNG

oCOG

•

Capacity

factor

40%

•

Same

emission rates

per

fuel

as

for

normal

operations

Coke

Oven

Gas

Scrubber

Maintenance

Mode

•

35daysperyear

•

occurs

when

COG

represents

40%

of

the

fuel

mix

40%

60%

URS

Corporation

Boiler

C&cuiaticn

Submittal

CorretlQn

Page

2

of

3

November

24.

2tO8

---

JRN—30—2009

16:58

HODGE DWYER ZEMAN

217 523

4948

P.13/45

• since

NO

emissions are higher in this

mode

of operation emissions

are

treated as

a delta

based

on the

COG emissions

rate

without COG

desulfurization

minus

COG emission

rate

with COG

desulfurization

o COG

emission rate with

desulfurization

0.144

o COG

emission rate

without desulfurization

0.336

Baseline

conditions

were

calculated using the

same

assumptions presented

above

but with the

following

emission

rates in

Ib/MMBtu:

.0.3

NG

• 0.066

BFG

•

0.729

COG

Results

Based

on the assumptions

and

calculations shown above and the

resulting

ozone season controlled

emission

rate, the following

emission reductions are

anticipated due to the

installation

of

FOR on Boilers 11

and

12.

NO

Emissions

NO

Emissions

(tonsIyear

(tonslozone

season)

.

Baseline

Controlled

Baseline

Controlled

Normal

Operations

179.4

237.8

54.1

Furnace

Downtime

Operations

86.69

17.6

48.16

10.37

COG

Desulfurization

Down Delta

14.5

14.52

Total

703.3

211.6

286

79.0

Reduction

in

Emissions

491.7

207.0

USS proposes

to

meet

NOx

requirements

by averaging

emissions between

boilers

11

and

12 and among fuels

and meet an average controlled

rate of 0.113

lb/MMBtu.

URS

Corporation

Page 3 of 3

holier Calculation Submittal Correction

November 24, 2008

---

JRN—30—2009

:59

HOD6E

DWYER

ZENRN

21?

523

4948

P.14/45

US

STEEL

GRANITE

CITY

BOILERS1I&12

NOx

REDUCTION

STUDY

US

Steel

Granite

City,

IL

Boilers

11

&

12

NO

Reduction

Study

RE

VISION

1

Prepared

for:

Prepared

by:

—

URS

US

Stcel

9801,

Westheimer

Granite

CityJL

Suitei0I

Houston,

TX

77042

Rev

1

January

19,

2009

‘LJRS

March

200S

Page

i

---

JAN—30—2009

HODGE

DWYER

ZEMAN

217

523

4948

P.15/45

US

STEEL

GRANITE

CITY

BOILERS

11

&

12

NOx

REDUCTION

STUDY

TABLE

OF

CONTENTS

1.0

EXECUTIVE

SUMMARY

2.0

INTRODUCTION

3.0

STUDY

APPROACH

4.0

NOx

REDUCTION

OPTIONS

5.0

NOx

ESTIMATES

6.0

CONCLUSIONS

&

RECOMMENDATIONS

Revi

January

192OO9

U’RJS

March

200S

Pagc

ii

---

JflN—30—2009

16:58

HODGE

DWYER

ZEMFN

217

523

4948

P.16/45

GRANITE

CITY

BOILERS

11

&

12

NOx

REDUCTION

STUDY

1.0

EXECUTIVE

SUMMARY

The

Illinois

Pollution

Control

Board

is

proposing

new

limits

for

NO

sources

that

will

affect

Boilers

11

and

12

at

the

Granite

City,

IL

plant.

URS Corporation

(URS)

was

contracted

by

US

Steel

to

evaluate

the

boilers

and recommend

the

optimum

NOx

control

technology

to

meet

the

proposed

limits.

The

evaluation

included

two

major

parts. The

first was

to

conduct

an

on-site

inspection

of

the

two

boilers.

The

second

was to

collect

and

analyze

the

available

design

and

operating information.

The

results

of

these

analyses

were

compared

to

the

NO

emission

limits

and the

applicable

NOx

control

technologies

to

arrive

at

the

most cost-effective,

technically

feasible

solution.

For

the

purposes

of

this

initial

evaluation,

only those

control

technologies

that

have

been sufficiently

demonstrated

as

successful

for

these

types

of

boilers

were

considered,

As

part

of

the

evaluation,

a

plan was

developed

that

addressed

the

NO

controls

technology

required

for

each

boiler.

Rev

1

January

19,

2009

IJIIJ_s

MARCH

2008

Privieged

and

Confidential

Page

1

---

JN—3G—28Ø9

16:59

HODGE

DWYERZEMN

217

523

4948

P.17/45

GRANITE

CITY

BOILERS

11

&

12

NO

REDUCTION

STUDY

2.0

INTRODUCTION

URS

has

been

commissioned

to

assess

the

optimum

NOx

control technology

for

Boilers

11

and

12

at

the

US

Steel plant

in

Granite

City,

IL.

Both

boilers

are

field

erected

boilers rated

at

a steam

flow

of

150,000

lb/hr.

Boiler

Ills

a

Combustion

Engineering

(ABB) corner

fired

boiler

with

a single

level

of

burners.

Boiler

12

is

a

front

wall

fired

bofler

built

by

Riley

with

two

circular

burners,

Relevant

data

for

the

two

boilers

are

shown

in

Table 1 and 2.

Natural

Gas

(NG), Coke

Oven Gas

(COG)

and

Blast Furnace

Gas

(BFG)

can

all

be

fired

on

both

boilers

11

and 12.

Rev

lJanuwyi,2009

tJDS

MARCH

2008

Privileged

and

Confidential

Pagc

2

---

0

D

C

m

-c

‘

m

p-4

1

0

0

4

---

r,)

C,

0

0

0

—

.4

‘-1

‘0

C,

C,

0

z

0-

C,

0

0-

C,

0

‘0

C’

---

JiN—30—2009

1700

HODGE

DWYER

ZEMRN

217

523

4948

P.20/45

GRANITE

CITY

BOILERS

11

&

12

NO

REDUCTION

STUDY

Table 3

shows

the

COG

and

BEG

analysis

used

for

this

study.

The

COG

analysis

is

shown

both

before

and

after

the

H

2

S

scrubber.

According

toUS

Steel

the

scrubber

may be

out

of

service

up

to

35

days/year.

Natural

gas

is

also

fired

on

both

boilers,

A

typical

natural

gas

analysis

of

92%

Cl

4

,

5%

higher

hydrocarbons,

3%

inerts

and

a

HHV

of

1030

Btu!&

was

used.

The

values

of

HCN, post

scrubber,

need

to

be

confirmed.

Table

3:

Fuel

Analysis

.

COG

Before

H2S

sórubber

COG

After

H2S

scrubber

BFG

VOL

%/PPM

VOL%1PPM

VOL

%/PPM

Hydrogen

58.7

58.7

10.2

Argon

<0.1

‘c0.1

Oxygen

<0.3

0.3

0.4

r1troen

<03

<O-.3

41.9.

Methane

29.7

29,7

Carbon

Monoxide

5.5

5.5

25

Carbon

Dioxide

1.4

1.4

-

22.5

thy1ene

2.4

2.4

Eane

0.7

0.7

Nydoen

Sulfide

-

5508

PPM

370

PPM

-

26

PPM

Propane

0.2

0.2

-.

-

Carbonyl

Sulfide

107

PPM

20

PPM

27

ppm

Sulftr

Dioxide

8

PPM

Q

PPM

I

PPM.

C4-C6

Cl

<1

Aromatics

6352

PPM

—

6352

PPM

Ammonia

-

2

PPM

0

PPM

0

drogen

Cyanide

1960

PPM

130

PPM

HHV

576

BTU/FT3

80

-

120

B?U/FT3

Rev

1

Januaiy

19.

2009

IJ1IS

MARCH

2008

?rivilcgcd

and

Confidential

Page

5

---

JRN—30—2009

17:80

HODGE

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ZEMRN

217

523

4949

P.21/45

I.)

hY

IJ .1

IlAd

GRANITE

CITY

BOILERS

11

&

12

NOx

REDUCTION

STUDY

3.0

STUDY

APPROACH

AND

PROCEDURES

Analysis

Approach

The

analysis

approach

consisted

of two

major

efforts. The

first

was

to

conduct an

on-site

inspection of the

two

boilers,

The

second

was

to

collect

and

analyze

the

available

design

and

operating

information.

The results

of

these

analyses

were

compared

to

the

future

NOx

emission

limits, and

the

applicable

NOx

control

technologies

to

arrive

at

the

most

costeffective,

technically

feasible

solution. For

the

purposes

of

this

initial

evaluation,

only

those

control

technologies

that

have

been

sufficiently demonstrated

as

successful

for

these

types

of

boilers

were

considered.

3.1

On-Site

Inspection

IJRS

personnel

conducted an

on-site

inspection of

the

operational units.

This

information

was

reviewed

with

engineering

personnel,

information

was

collected

and

verified.

The

following

types

of

information

were

collected:

• Boiler drawings

showing

existing

burner

layout,

burner

wall

details

(in

particular tube

locations on

the

burner

wall)

• Boiler

data

sheets

giving

heat

release

rates,

furnace

volume, existing

stack

temperatures,

maximum

heat

input,

steam

conditions

(pressure

and

temp.)

•

Existing

heat

recovery

equipment and

design

data

(inlet

and

outlet

temperatures)-

economizer or

air

heater

•

Fuels

burned

(natural gas

blast

furnace

gas,

COG)

•

Existing

NOx

levels

•

Target

NO

levels

•

Existing controls

hardware

and

burner management

•

Fan

manufacturer

and

model

•

Burner

manufacturer

and

model

• Number of

burners

•

Burner

Spacing

• Draft

type

• Configuration

of

ducting

and

pre-heaters

MARCH

Rev

3

January

2008

19,2009

Pdvileged

and Confidential

IJS

Page

6

---

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17:00

H006E DWYER

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217

523

4946

P.22/45

J.4JdLJ

GRANITE

CITY

BOILERS

11

&

12

NOx

REDUCTION

STUDY

Field

inspections

were

made

to

collect

information

that

was

critical

to

determining

the

feasibility

and

cost

for

applying

the

latest

technologies

to

the boilers.

This

information

included,

but

was

not limited

to,

the

following:

•

General

arrangement

and area

layout

•

General

condition

of the

boiler

• Burner

accessibility

• Number

of operative

burners

32

Technologies

Considered

The

practical

available

technologies

considered

were:

Flue

Gas

Recirculation

(fGR)

Evaluation

for

Boilers

Factors

considered

in the assessment

included:

• Boiler

geometry

and

ancillary

equipment

layout,

•

Fan

sizing.

•

Existing

burner

design

and

suitability

for

use

with

FGR.

•

Suitability

of existing

combustion

controls.

Burner

Retrofit

Evaluation

With

respect

to

the boilers

controlled

via

lOw-NOx

burner

technology,

issues

that

were considered

include:

•

The ability

for

the burner

technoLogy

to meet

the

target

NOx

emission

limit for

each unit.

• Burner-to-burner

spacing,

and

burner-to-tube

dimensions,

• Matching

low-NOx

burner

flame

characteristics

with

the

available

physical

envelope.

Feedwater

Economizer

Factors

considered

in this

assessment

included:

•

Boiler

geometry

and

ancillary

equipment

layout.

• Existing

ductwork

configuration

and

space

limitations.

Rcv1Jnuaxy19,2OO9

IJDS

MARCH

2005

Privileged

and

Confidential

Page

7

---

JRN—30—2009

17101

H006E

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217 523

4949

P.23/45

GRANITE

CITY

BOILERS

II

&

12

NO

REDUCTION

STUDY

SCR

Evaluation

Factors

considered

for

the

application

of

SCR:

Fuel

type

and

sulfur

leveL

• Upstream

temperature

and

impact

on

SCR

catalyst

volume,

• Existing

ductwork

conguration

and

space

limitations.

•

Fan

and/or

draft

requirements/limitations.

SNCR

Evaluation

• Fuel

type

and

sulfur

level.

Existing

ductwork

configuration

and

space

considerations.

•

Fan

and/or

draft

requirements/considerations.

Potential

for

ammona

slip.

•

Temperature

variations,

•

Load

variations.

The

following

section

further

describes

the

NOx

reduction

technologies

considered

in

this

evaluation.

Rev

1

Januaiy

19, 2009

IJ’PS

MARCH

2008

Privileged

and Confidcnial

Page

8

---

JflN—30—2009

17:01

HODGE

DL*JYER

ZEMRN

%JL

GRANITE

CITY

BOILERS

11

&

12

NO

REDUCTION

STUDY

4.0

NOx

REDUCTION

OPTIONS

217

523

4948

P.24/45

The

NO

control

technologies

that

were

evaluated

for

application

to

the

affected

combustion

units

included

flue

gas

recirculation,

low-NOx

burners,

feedwater

economizer,

selective

noncatalylic

reduction

and

selective

catalytic

reduction.

A

description

of

each

of

these

technologies

is

presented

in

the

following

sections.

4,1

FLUE

GAS

RECIRCULATION

Flue

Gas

Recirculation

(FOR)

seeks

to

reduce

NOx

emissions

by

reducing

the

peak

temperatures

that

occur

during

combustion,

Relatively

cool,

inert

flue

gas

that

does

not

contribute

to

combustion

is

recirculated

through

the

windbox.

This

has

the

effect

of

stretching

the

flame,

and

reducing

peak

flame

temperatures

that

contribute

to

NOx

formation.

FGR

has

been

employed

successfully

for

25

years,

and

is

one

of

the

most

cost-effective

methods

for

reducing

NO

emissions,

primarily

from

boilers.

There

are

three

basic

types

of

flue

gas

recirculation

systems

that

have

been

applied

to

boilers:

•

Forced

FOR

(FEGR),

where

a

separate

FOR

fan

is

used

to

extract

flue

gas

from

a

location

upstream

of

the

ID

fan

and

inject

it

into

the

combustion

air

downstream

of

the

FD

fan.

Ray

1

January

19

2009

URS

Page

9

BOILER

FD

Fan

ID

Fan

STACK

MARCH

2005

Privileged

and

Confidential

---

JflN—30-2009

17:01

HODGE

DWYER

ZEMRN

GRANiTE

CITY

BOILERS

1l&12

NOx

RfDUCTION

STUDY

217

523

4948

P.25/45

•

induced

FGR

(IFGR),

where

the

negative

pressure

at

the

FO

fan

inlet

is

used

to

induce flue

gas

flow

into

the

FD

fan,

where

it

mixes with

the

combustion

air.

•

Fuel

Induced

FGR

(FIR),

where

the

motive

force of

the

fuel is

used

to

mix

flue

gas

into

the

fuel

stream,

rather than

the

combustion

air.

FGR

is

very

effective

in

reducing

thermal

NOx

but

has

very

little

effect

on

fuel

NOx.

Figure

1

shows

typical

NOx

reductions

using FGR.

for

a

wide

range

of

industrial

boiler

types

and

sizes.

Rcv

1

January

19,2009

URS

BOILER

FD

Fan

STACK

FD Fan

ID

Fan

STACK

MARCH

2008

Privllcgcd

and

Confidcntia

Pagc

10

---

JAN—30—2009

17:01

HOD6E

DWYER

ZEMAN

217

523

4948

P.26/45

GRANITE

CITY

BOILERS

11

&

12

NO

kEDUCTION

STUDY

I

FIGURE

I

TYPICAL

NOc

REDUCTION

RESULTS

FOR

FOR

APPLICATION

TO

E)USTING

BURNERS

70

20

20

0

25

FOR

may

be

an

effective

tool

for

Boilers

11

and

12

since

the

amount

of

FOR

can

be

easily

controlled

depending

on

the

fuel

fired,

For

example

if

the

fuel

is

primarily

BFO,

the

flame

temperature

is

already

quite

lowe

and

it

may

not

be

necessary

to

recirculate

flue

gas.

In

fact,

when

the

boiler

fuci

is

largely

BFG,

flame

stability

would

become

problematic

if

FGR

is

applied

to

the

boiler.

When

the

fuel

is

primarily

COG

or

NG,

the

FOR

rate

can

be

increased

to

meet

the

desired

NOx

target.

If

the

FOR

system

is

designed

correctly,

there

would

not

be

an

affect

on

CO

or

PM

emissions.

URS

Page

8

Rev

I

January

19,

2009

March

2008

Privilcgcd

and

Confidential

---

JIIN—30—2009

17:02

H006E

DWYER

ZEMRN

217

523

4948

P.27/45

GRANITE

CITY

BOILERS

II

&12

NO

REDUCTION

STUDY

4.2

LOW

NO

BURNERS

(LNBs)

AND

ULTRA

LOW

NO

BURNERS

(ULNBs)

Burners

have

been

undergoing

rapid

development

due

to

pressures

to

reduce

NOx

emissions,

and

they

resulting

technologies

may

be

referred

to

as

either

l0W-NO

burners

(LNB),

or

ultra-low-NOx

burners

((JLNB)

If

new

burner

technology

meets

the

emission

limit

for

a

particular

combustion

unit,

it

will

often

be

the

most

economical

NOx

reduction

alternative,

This

is

especially

true

if

the

new

burners

can

fit

in

the

existing

burner

openings,

the

installation

cost

may

be

very

low,

and

the

installation

time

may

be

relatively

short.

However,

new

burners

alone

will

usually

not

be

able

to

meet

the

most

stringent

emission

limits.

It

is

worth

noting

that

a

major

drawback

of

LNB

retrofits

is

that

the

flames

are

generally

larger

and

more

diffuse

than

conventional

burner

flames.

This

stems

from

the

diffusion

mixing

and

delayed

combustion,

which

are

characteristic

of

the

air

staging

and/or

fuel

staging

combustion

processes.

Such

flame

characteristics

mean

that

flame

impingement

on

tubes

becomes

a

concern.

NOx

emissions

for

L.NBs

are

generally

very

sensitive

to

airflow

control

to

the

primary

and

secondary

combustion

zones

of

the

flame

and

care

must

be

taken

to

maintain

the

proper

fuel/air

ratios

to

achieve

the

optimum

NO

reductions.

This

often

requires

an

upgrade

of

the

combustion

control

system.

In

addition,

LNBs

will

often

require

upgrades

to

the

existing

burner

management

system.

Depending

on

the

current

system,

the

cost

of

these

confrol

upgrades

can

be

as

much

as

that

for

the

burners.

Particularly

for

Boiler

11,

a

low

NOx

burner

does

not

really

exist.

Even

for

Boiler

12,

a

viable

low

NO

burner

without

FGR

that

could

fIre

the

mix

of

fuels

fired

on

Boiler

12

and

generate

a

significant

NO

reduction

does

not

exist.

0.

course

a

low

NOx

burner

combined

with

FGR

would

produce

significant

NO

reductions,

but

it

is

unlikely

that

the

NOx

reduction

would

be

any

greater

than

application

of

FGR

to

the

existing

burners.

Rev

1

January

19.

2009

URS

March

2008

Privileged

arid

Confidential

Page

9

---

JRN—30-2009

17:02

HODGE

DtAJYER

ZENFN

217

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4948

P.28/45

GRANITE

CITY

BOILERS

I1&

12

NOx

REDUCTION

STUDY

4.3

AIR

PREHEAT

REPLACEMENT

WITh

A

FEED

WATER

ECONOMIZER

Replacing

the

air

heater

with a

t’eedwater

economizer

can

also

be

an

effective

technique

for

reducing

thermal

NON.

Reducing

the

combustion

air

temperature

from

500°F

to

ambient

would

also

reduce

thermal

NO

by

about

60%.

However

(much

like

FOR),

removing

the

air

preheat

would

have

little

effect

on

fuel

NO.

One

difficulty

with

removing

the

air

preheaters

would

be

that

the

flame

stability

with

the

BFG

might

become

a

problem.

If

the

air preheater

is

removed

a

higher

percentage

of

NO

or

COG

co-firing

may

be

required.

Another

key

consideration

for

removal

of

the air

preheaters

with

economizers

is

the

cost,

which

would

be

significantly

higher

than

other

options,

such

as

FGR.

One

advantage

of

removing

the air

beater

would

be

that

a

significant

reduction

in

the

pressure

drop

for

both

the FD

and ID

fans

would

be

obtained,

eliminating

current

issues

with fan

limitations

while

firing

BFG.

4.4

SELECTIVE

CATALYTIC

REDUCTION

(5CR)

SCR

Technologies

In

the field

of

NO

reduction,

Selective

Catalytic

Reduction

(SCR)

is

considered

a

mature,

proven

technology.

It

has

been

applied

to

achieve

NO

reduction

on

stationary

combustion

sources

since

the

1970’s.

Most

of

the

applications

have

been

on

coal,

oil,

and gas

fired

utility

boilers

and gas

turbines.

SCR

utilizes

catalyst

to

promote

the

reactions

to

occur

at

reduced

temperatures.

The

temperature

range

for

SCR

applications

is

300-1000°F.

The

most

efficient

application

of

this

technology

occurs

in

the 525-875°F

range

and

uses

conventional

Vanadium/Titanium

catalyst.

Application

of

this

technology

at

lower

temperatures

results

in

a

significant

increase

in

the

amount

of

catalyst

required.

Application

at

temperatures

above

875°F

typically

requires

the

use

of

a

special

zeolite

catalyst.

5CR,

regardless

of

the

application

temperature,

employs

a

reagent

that,

in

the

presence

of

the

catalyst,

converts

NO

to

N

2

and

H

2

0.

The

ammonia

or

urea-

reducing

reagent

is

thoroughly

mixed

with

the

flue

gas (in

a

nearly

stoichiometric

ratio

with

NOx)

upstream

of

a

catalyst

bed.

In

order

to

achieve

high

levels

of

NOx

reduction,

a

small

amount

of

“NH

3

slip”

(unreacted

ammonia)

is

designed.

Rev

1

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19,

00

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10

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11

&

i2

NOx

REDUCTION

STUDY

In

addition

to

promoting

the

reduction

of

NOx,

the

catalyst

will

also

convert

a

small

(typically

<1%)

percent

of

the

SO

2

in

the

flue

gas

to

SO

3

.

The

catalyst

bed is

contained

in

a

reactor

vessel

or

frame

that

suspends

the

catalyst

modules

in

the

flue

gas

stream,

Normally

the

linear

velocity

of

flue

gas

is

limited

to

20

fl/see

due to

catalyst

erosion

considerations.

Typically,

the

gas

velocity

at

the

catalyst

is

15

ftisec.

Consequently,

the

catalyst

cross

section

is

greater

than

the

typical

duct

cross

section.

Additional

transition

ducts

provide

the

transition

from

the

existing

ducts

to

the

SCR

bed.

This

new

ducting

configuration

needs

to

provide

an

area

of

mixing

the

reagents

with

the

flue

gas.

SeveraL

aspects

of

the

USS

boiler

11

and

12

operation

would

complicate

an

SCR

installation.

Issues

that

must

be

considered

in

an

5CR design

include:

•

The

USS

steel

boilers

are

load

following,

•

The

inlet

NOx

to

the

5CR

vary

considerably

based

on

the

fuels

used,

•

The

COG,

particularly

if

the

scrubber

is

out

of

service,

has

a

high

fuel

sulfur

content.

The

fact

that

the

boilers

are

load

following and

the

inlet

NOx

varies

with the

fuel

blend

fired,

make

control

of

the

NH

3

injection

rate

much

more

complex

than

for

a

boiler

firing only

one

fuel

at

a

time.

Normally

the

‘NH3 rate

is

controlled

based

on

firing

rate

with a

trim

of

the NH

3

rate based

on

the

outlet

NOx.

For the

USS

steel

boilers,

since

the

inlet

NOx

is

not

only

a

function

of

firing

rate,

but also

a

function

of

the

fuel blend

and the

fuel

nitrogen

content

of

the

COG.

This

would

mean

that the

5CR

control

would

need

to

be

based

on

measurement

of

the

inlet

and

outlet

NON.

Since

NOx

measurement

has

an

inherent

time lag,

during

rapid

load

swings

the

NH

3

rate

will either

be

high

or

low,

resulting

in

either

higher

NOx

emissions

or

NH

3

slip

issues.

The

presence

of

sulfur

in

the

COG

gas

complicate

the situation

further

since

unreacted

NH

3

will

react with

SO

3

in

the

flue

gas

to

form

ammonium

salts.

These

salts

can deposit

in

the

air

heater

resulting

in

reduced

boiler

efficiency

and

increase

pressure

drop

or

exit

the

boiler

at

PM

2

.

5

emissions.

The presence

of

a

high

sulfur

concentration

in

the

flue

gas

would

involve

using

catalyst

that is

resistant

to

poisoning

by

sulfur

compounds.

This

would

increase

the

catalyst

cost

and

would

probably

also

reduce

the

catalyst

lifetime.

Although

these

technical

issues

in

applying

an,

SCR

to

the

USS

boilers

can

most

likely

be

solved,

an 5CR

installation

on

these

boilers

would

be

a

very

costly,

Rev

l3anuaryl9,2009

IJRS

March

2008

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wid

Confidential

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11

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BOILERS

11 &

12

NOx

REDUCTION

STUDY

custom

installation.

Consequently,

application

of

SCR

on

these

boilers

is

not

recommended.

4.5

Selective

Non-Catalytic

Reduction

(SNCR)

Selective

Non-Catalytic

Reduction

(SNCR)

systems

entail

the

injection

of

a

reducing

agent

(ammonia/urea)

into

the

flue

gas

stream

to

produce

a

NOx

reducing

atmosphere

at

proper

temperatures.

The

systems are

common

on

large

baseloaded

utility

boilers.

SNCR

systems

require

ample

residence

time

and

good

mixing

of

ammonia

and

flue

gases

at

the

ideal

temperature

range

for

satisfactory

NOx

reductions

to

occur.

If

these

conditions

arc not

met,

it

can

result

in higher

NOx,

or

the

emission

of

unreacted

ammonia

(“anirnonia

slip”).

The

ideal

temperature

range

for the SNCR

reactions

to

occur

is

from

about

1,700°F

to

2,100°F.

If

the

ammonia/urea

is

injected

where

the

temperature

is

higher,

it

will be

oxidized,

and

will

result

in

higher

NO

emissions.

If

the

ammonia/urea

is

injected

where

the

temperature

is

too

low,

the

reaction

will not

occur,

and

ammonia

will be

emitted

from

the

stack.

Improper

mixing

of

the

ammonia/urea

and

the

NO

can

also result

in

poor

SNCR

performance.

If

the

molar

ratio

of

ammoniaJurea

to

NOx

is

too

high

at

a

given

location,

then

the

excess

ammonia

will be

emitted.

In

sulfur-containing

fuel

firing

applications,

ammonia

slip

results

in

the

creation

of

ammonium

compounds

which

are

emitted

as

condensable

particulate.

These

compounds

typically

condense

at

temperatures

that

are

commonly

found

in the

air

heaters,

and the

deposits

that

form

can

lead

to

plugging,

fouling,

and

corrosion.

Air

heater

pluggage

increases

the pressure

drop,

and

acts

to

reduce

the

maximum

steam

production

from

the

boiler.

Air

heater

fouling

results

in

decreased

thermal

efficiency

of

the

boiler

process.

Air

heater

corrosion

decreases

the equipment

life,

and

results

in

more

frequent

maintenance.

Each

of

these

outcomes

will

ultimately

require

that

the

unit be

shut

down.

Recent

studies

on

utility

boilers

that

inject

ammonia

when

firing

sulfur-containing

fuels

suggest

that even

very

low

amounts

of

ammonia

slip

may

result

in

air

heater

fouling.

Boilers

LI and 12

are

not

good

candidates

for

an

SNCR

application

because

their

operating

characteristics

do

not

match

up

well

with

the

characteristics

required

for

SNCR

operation.

The

specific

characteristics

of

the

boiler

operation

that

preclude

SNCR

as a

viable

control

option

are

as

follows:

•

Load

variations;

•

Changes

in

the

bound-nitrogen

content

of

the

fuel;

•

Fluctuations

in

fuel

heating value;

Rcv

I

January

19,

2009

IJRS

March

2008

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Page

12

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BOILERS

11

&

12

NO

REDUCTION

STUDY

•

Sulfur

content

of

the COG;

and,

•

Stratification

that

varies

with

load and

fuel

composition

The

steam

loads

for

boilers

11

and

12

vary

significantly,

because

they

are

affected

by

other

parts of

the

process.

When

both

blast

furnaces

are

in

operation,

the

steam

demand

is

high.

However,

when

only

one

blast

furnace

is

in

operation,

the

steam

demand

is

relatively

low.

There

are

other

parts

of

the

process

that

require

steam,

that

cause

the

boiler

load to

swing.

When

the

load

changes,

the

flue

gas

temperature

also

changes.

As

such,

the

location

of

the optimum

temperature

window

for the

SNCR

reactions

changes.

Since

the

ammonia/urea

injection

grid

is

fixed,

the flue

gas

temperature

at

the

injection

point

may

not

be

ideal.

On

large

utility-scale

boilers,

multiple

injection

locations

may

be

used

to

overcome

this

problem,

but

it

is

not

practical

on

smaller

units

(boilers

11 and

12).

The

COG

contains

bound

nitrogen,

in

the

fonn

of

hydrogen

cyanide,

which

is

of

particular

concern

when

the

H

2

S

scrubber

is

out

of

service

for

maintenance

purposes.

The

presence

of

bound-nitrogen

compounds

in

the

COG

means

that

changes

in

the

COG

firing

rate wit]

also

produce

dramatic

changes

in

the

uncontrolled

NOx

concentration.

Variations

in

the

NO

cause

an

improper

molar

ratio

of

ammonia/urea

to

NOx

resulting

in

either

higher

NOx

emissions

or

ammonia

slip

as

the

COG

component

of

the

fuel

changes.

The

heating

value

of

the

three

fuels

being

fired

in

boilers

11

and

12

is

quite

different,

with the

]3F0

having

a

heating

value

about

one

tenth

that

of

natural

gas,

and the

COG

being

somewhere

in

between,

As

the fuel

blend

being

fired in

the

boilers

varies,

the

flame

temperature

in

the

boiler

fluctuates,

The

fuel

blend

also

affects

mass

flow

rate

through

the

boiler,

which

is

much

higher

for the

BFG

than

for

natural

gas.

The changes

in

the

flame

temperature

and

mass

flow

rate

not

only

cause

the

location

of

the

ideal

SNCR

injection

temperature

window

to

change,

they

also

cause

the

NO

mass

emission

rate

to

fluctuate.

Variations

in

the

NO

cause

an

improper

molar

ratio

of

ammonia/urea

to

NOx,

resulting

in

either

higher

NO

emissions

or

ammonia

slip

during

fuel

composition

transitions.

The

scrubbed

COG

contains

a

significant

amount

of

hydrogen

sulfide,

and

other

sulfur-containing

compounds.

These

concentrations

are

much

higher

when

the

boilers

are

being

operated

while

the

H

2

S

scrubber

is

out

of

service

for

maintenance

purposes

In

either

case,

some

of

the

sulfur

compounds

will

react

with

the

ammonia/urea

that

is

injected

to

form

condensable

ammonium

compounds.

These

compounds

will

then

form

deposits

on

the

air heater

surfaces,

and

will

negatively

affect

the

boiler

operation,

as

described

previously,

At

least

to

the

knowledge

of

1..TRS,

SNCR

has

never

been

applied

to

a

boiler

with

the fuel

blends

and

operating

characteristics

of

boilers

11

and 12.

Since

the

Rev

I

Januaiy

19,

2009

tJIS

March

2008

Privileged

and

Confidential

Page

13

---

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17:03

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CITY

BOILERS

11

&

12

NOx

REDUCTION

STUDY

technica’

issues

involved

with

applying

SNCR

to

these

boilers

are

significant

and

complex,

SNCR

would

not

be

recommended

for

these

boilers

Rev

1

Januaiy

19,

2009

Martth

2005

Privileged

and

Confidential

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14

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BOILERS

11

&

12

NO

REDUCTiON

STUDY

5.0

NOx

ESTIMATES

Both

the

baseline

and

Retrofit

NO

has

been

estimated

using

the

following

method.

First

the

thermal

NOx

was

estimated

by

calculating

the

adiabatic

flame

temperature

for

the

various

fuels

using

the

STANJAN

thermal

equilibrium

program

and

data

base.

The

flame

temperatures

were

then

used

to

calculate

NOx

emissions

based

on

a

URS

data

base

of

theoretical

flame

temperatures

and

NOx

emissions.

Thermal

NO

emissions

were

calculated

for

a

baseline

air

preheat

temperature

of

500°F

with

FGR

rates

of

10%

and

20%.

Calculations

were

done

for

each

fuel

alone.

Calculation

of

emission

rates

for

fuel

combinations

were

done

using

a

heat

input

weighted

average

of

individual

fuel

emission

rates

for

the

fuels

used

in

the

combined

emission

rate.

It

was

estimated

that

approximately

50%

of

the

HCN

would

be

converted

to

NOx

when

the

concentration

was

1960

PPM

and

100%

would

be

converted

to

NOx

when

the

concentration

was

130

PPM.

For

the

COG

the

overall

NOX

emissions

were

estimated

by

adding

the

thermal

and

fuel

NOx

together,

For

the

natural

gas

and

BFG

the

NO

was

assumed

to be

thermal

NO

alone.

Baseline

NO

emissions

for

a

given

fuel

were

assumed

to

be

the

same

on

both

boilers.

Table

4

shows

the

calculated

flame

temperatures

for

each

case

and

Tables

5

and

6

show

the

NOx

emissions

that

were

estimated

based

on

a

particular

COG

HN

concentration

and/or

FGR

rates.

Calculations

were

done

for

two

UN

concentrations

1960

ppm

corresponding

to

the

value

before

the

H

2

S

scrubber

and

130

ppm

corresponding

to

the

value

after

the

scrubber.

Table

4:

Calculated

Flame

Temperatures

FUEL

FLAME

TEMP

FOR

500

F

AIR

PREHEAT

IN

DEG

F

3581

COG

3677

BEG

2717

NGIIO%FGR

3309

NG/20%FGR

3103

Rev

1

January

19,

2009

March

2008

Privileged

and

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15

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11

&

12

NOx

REDUCTION

STUDY

Table 5:

Estimated

NO

Emissions

I

AIR

TEMP

THERMAL

NOx

ThERvIAL

NCc

THERMAL

NO

N(

LWMMI3TU

NOxLS1MMBTI.J

L

LBIMMBTUIOO%

LB’MMBTUIOO%

LB’MMBTUIOO%

COG

W/1900

(X)G

W/

130

PPM

II

T3

COG

BFG

PPM

HCN

-CN

500F

I

O.2

0.312

I

0)288

1

0.54

I

0.348

I

Table

6:

Estfrnatcd

NO

Emissions

with

and

without

1GR.

with

500bF

preheat

%

FGR

(500

F

THERMAL

NOx

THERMAL

NOx

THERMAL

NOX

NOx

AIR

PREHEAT)

LB/MMBTU

100%

LB/MMBTU

100

LB/MMBTU

100%

LBIMMBTIJ

LBIMMB

NG

%

COG

BFG

COG