Coal-to-Fuel Plant Simulation Studies for Optimal Performance

and Carbon Management

Coal-to-Fuel Plant Simulation Studies for Optimal Performance

and Carbon Management

Idaho National Laboratory:Richard BoardmanAnastasia Gribik

Rick Wood

Baard Energy, LLC:John BaardsonSteve Dopuch

Gasification Technologies ConferenceOctober 17, 2007

Ohio River Clean Fuels (ORCF) Project

• Future plant site located on the Ohio River in Wellsville, Ohio

• Close proximity to West Virginia, Pennsylvania, and Ohio coal reserves

• Near barge loading/unloading terminal

• Access to railroads, petroleum and natural gas pipeline, and electrical transmission

• Neighboring oil fields for EOR applications

Plant Description

• 50,000 bbl/day synthetic fuel production– Combination of diesel and naphtha

• Combination of coal and biomass feedstocks• Sulfur, CO2, and mercury removal utilizing Rectisol process• Pure CO2 stream produced which can be sequestered or used for

enhanced oil recovery (EOR)• Cogeneration of auxiliary power load and additional power for export

using a combined cycle system• Production of liquefied petroleum gas (LPG) from light gases

Aspen Plus Process Model Overview

• Steady-state process model developed using “hierarchy blocks” with emphasis on heat integration

• The following processes were modeled in detail:– Air Separation– Gasification & Syngas Conditioning – Sulfur Management– Fischer-Tropsch Synthesis– Product Upgrade & Refining– Power Generation– CO2 Capture & Compression

Aspen Plus Process Model Overview - Model Integration

Aspen Plus Process Model - Submodel Descriptions and Optimization

• Product Upgrading & Refining– Middle distillate hydrotreated then refined via distillation into diesel and naphtha

products– Bottoms product mixed with wax from FT reactors and hydrocracked to improve

yields• Power Generation

– Light gas fires gas turbines and heat is recovered in HRSG– Steam generated in HRSG and excess steam produces power in steam turbines

• CO2 Capture & Compression– CO2 is removed in the Rectisol process– Pure CO2 stream is compressed and liquefied for transport

Aspen Plus Process Model - Model Flowsheet

HIERARCHY

CLAUS

HIERARCHY

COAL-HHV

HIERARCHY

CRY O-ASU

HIERARCHY

FT-SYNTH

HIERARCHY

GAS-HHV

HIERARCHY

GAS-TURB

HIERARCHY

GASIFIER

HIERARCHY

LIQUEFAC

HIERARCHY

REFINERY

HIERARCHY

SCOT

HIERARCHY

ST-HRSG

70

15

6407403AIR

74

17

4338707

N2

74

17

1226361O2

74

17

835433

WSTE-GAS

224

665

1226361O2-GFR-1

74

17

104938O2-ENR-1

74

17

730495

ASU-VENT

100

145

104938

O2-ENR-2

212

442

1350199SYNGAS-9

46

389

280657TG-FT

428

395

250440

FT-WAX

117

392

154968

FT-MID-D

47

389

22877

FT-NAP

48

389

300934

GT-FUEL

70

15

1723449COAL-HV

224

665

1226361

O2-GFR-2

248

1160

284748

CO2-GFR

70

15

1723449

GFR-COAL

437

1160

88526CO2-FLTR

104

487

3906981

SYNGAS-1

70

15

1723449

COAL

437

1160

670727CO2-2

437

1160

582200

CO2-5

248

1160

582200

CO2-6

248

1160

297453CO2-VENT

104

487

3906981

SY NGAS-2

104

487

3906981

SY NGAS-3

104

487

3906981SY NG-HV

100

43

164089

REC-RECY

74

17

237050

STRIP-N2

104

458

1415193SY NGAS-4

125

29

159597

H2S

65

17

2528026 CO2

65

17

193567

WSTE-CO2

100

17

11737H2O

300

445

1415193

SYNGAS-7

192

455

1415193

SY NGAS-5

212

442

1415193SY NGAS-8

300

452

1415193

SY NGAS-6

300

15

0S-ADSORB

212

419

6208

H2-REF

212

110

58234 PSA-TG

68

15

117682

NAPHTHA

68

27

281976

DIESEL

107

251

34461

TG-REF1

825

15

247164FH-EXHST

300

21

193719

TO-SCOT86

1515

1644841

CO2-PROD

437

1160

670727GFR-CO2

1200

15

6544856

GT-POC

330

15

6792095

STACKGAS

212

442

64994

TO-PSA 212

419

6760

H2212

419

552

H2-SCOT

O2-COMP

W=68689

WST-SPLT

CL-O2-CW=4144

CL-CHG-1

COAL-DUP

GAS-SPL1

CO2-COOLQ=-30

GAS-SPL2

CL-CHG-3 SY NG-DUP

SEP

RECTISOLQ=-16

HEATXQ=79

REHEATQ=97

S-GUARD

Q=-0

SG-SPLT

PSAQ=0

H2-SPLT

Temperature (F)

Pre ssur e (psi)

Ma ss Flow Ra te (lb/hr)

Q Duty (MMBtu/hr)

W Power( kW)

Manually AdjustTemperature,

Pressure &Composition

Manually AdjustTemperature,

Pressure &Composition

TG-MIX1

68

389

315118

TG-TOT

0

TG-GT1TG-SPLT1 TG-MI X2

68

389

315118

TG-LPG1

187

400

34461

TG-REF2

REC-COMPW=473

COOLERQ=-5

PRECOOLQ=7

25

389

315118TG-LPG2

-3

389

300934

TG-LPG3

48

389

300934

TG-LPG-4

-3

389

14184

LPG

70

15

6407403AIR

AIR(IN)

74

17

4338707N2

N2(OUT)

74

17

1226361O2

O2(OUT)

74

17

835433WASTE

WSTE-GAS(OUT)

80

94

6400501

AIR-3

80

94

5952466

AIR-3B

80

94

448035AIR-3A

80

109

448035

AIR-5

-295

17

4338707N2-1

-295

17

1226361

O2-1

-307

17

835433

C2-WASTE

-274

102

448035AIR-6

-278

87

5952466

TO-HPCOL

80

94

6407403

AIR-2

80

94

6902

MS-LIQ

-295

17

1226361

LPCOLBOT

80

94

6407403AIR-1

94

0KO-LIQ

80

94

6902BLOWDOWN

-311

17

448035

TO-LPCOL

-318

17

2559565

HP-TOP-3

-310

17

3392901HP-BOT-2

-318

17

4338707LPCOLTOP

-286

87

2559565

HPCOLTOP

-279

87

3392901

HPCOLBOT

-286

87

2559565

HP-TOP-1

-312

87

2559565HP-TOP-2

-312

17

3392901HP-BOT-1

113

109

448035AIR-4

AIR-SPLT

H-EXQ=573

MOLSIEVE

COLD-1BQ=111

ACOMP-1W=195662

KO-DRUM

H20-MIX LP-COL

QC=0QR=264

HP-COLQC=-264QR=0

COLD-1AQ=-111

VALVE-2

VALVE-1

COLD-2BQ=26

COLD-2AQ=-109

ACOMP-2W=1027

CW-EXCHQ=-4

COLD-2CQ=83

A-EXPANDW=-1617

Temp erature (F)

Pr ess ure (psi)

Mass Flo w Rate (lb/hr)

Duty (MMBtu/h r)

Q Duty (MMBtu/h r)

W Po wer(k W)

Air Separation Unit

224

665

1226361GFR-O2

O2-GFR-2(IN)

248

1160

284748

GFR-CO2

CO2-GFR(IN)

70

15

1723449COAL

GFR-COAL(IN)

437

1160

88526

FLTR-CO2

CO2-FLTR(IN)

104

487

3906981

SYNGAS SY NGAS-1(OUT)

-96

15

1653462COAL-3

70

15

1653462

ELEMENTS

HEAT

502

700

97838

GFR-STM

250

600

58863

INERT-N2

2835

600

3321271GFR-EFF1

250

15

1723449

COAL-1

2801

600

3362608GFR-EFF2

2801

598

240781SLAG-1

2801

598

3121827SY NG-1

675

594

5943705SY NG-3

464

591

5943705SY NG-4

463

587

113290

FLY -ASH

463

587

5918941

SY NG-5

250

15

69988COAL-H2O

250

15

1653462

COAL-2

1616

598

5943705SY NG-2

100

650

41337

QNCH-H2O

297

603

2821878

SG-REC-2

282

600

36592581

SCRUB-4

287

582

6116905SY NG-6

287

582

36395042SCRUB-1

282

580

36592581

SCRUB-3

287

582

36242581

SCRUB-2

287

582

152461SCR-BD 104

582

152461

SCR-BD-2

319

507

4839815

SY NG-8

300

497

4495827

SY NG-9

300

497

343988SAT-1

104

487

588846

KO-LIQ

104

485

738846COND-1

107

600

738846COND-2

105

600

150000MU-H2O-2

485

0COND-VNT

105

600

350000

MU-H2O-1

580

0SCR-VENT

192

15

3762948

BD-3

150

15

3762948

BD-4

200

15

4003729

BD-6

200

15

267535SLAG

200

15

3736194

BD-7

150

30

3762948

BD-5

107

600

150000COND-BD

192

15

4029305BD-1

192

15

9350SOUR-GAS

287

582

2821878 SG-REC-1

287

582

3295028

SY NG-7

301

600

343988SAT-2

107

600

588846

SAT-3

192

15

14795

BD-SOLID

192

15

4014510

BD-2

192

15

251562

BD-W ATER

104

30

150000

COND-MU

104

30

350000

SCR-MU

502

700

611953

SHFT-STM

392

582

2808600WGS-SG-2

414

582

3420553WGS-SG-3

450

572

3420553WGS-SG-4

897

554

3420553

WGS-SG-5

517

544

3420553WGS-SG-6

289

582

1875766WGS-SG-1

289

582

1419262WGS-BP

331

507

3420553WGS-SG-9

450

534

3420553WGS-SG-7

536

517

3420553WGS-SG-8

198

600

932834SAT-4

476

595

932834SAT-5

482

590

932834

SAT-6

DECOMPQ=-13646

GIBBS

Q=13646

RYIELD

DRYER-1

Q=175

SEP

GFR-SEPQ=-0

SC-2Q=-435

SEP

DSRQ=0

SEP

DRYER-2

Q=-0

GFR-HEATQ=-170

SC-1Q=-2077

ADJUSTQ=0

QNCH-MIX

SCRUBBERQ=0 SCR-PUMP

W=761

SCR-SPLT

CW-EXCHQ=-26

KO-DRM-1

Q=-235

KO-DRM-2

Q=-920

CON-PMP2

W=96

CON-TANKQ=0

SCR-TANKQ=-98

QCH-COOL

Q=-158

SEP

CON-SCRNQ=-0

MIXER

SLG-QNCH

BW-TANK

Q=0

QCH-PUMPW=59

REC-COMP

W=2848

QCH-SPLT

CON-PMP1

W=45

CON-SPLT

SEP

SCREENQ=-0

BW-SPLT

MU-PMP-2W=113

MU-PMP-1W=235

WGS-MIX1

WGS-1Q=0

WGS-EX1AQ=-587

SHIFT-BP

WGS-MIX2

WGS-2Q=0

WGS-EX3AQ=-414

WGS-EX3BQ=414

WGS-EX1BQ=587

WGS-EX2AQ=-102

WGS-EX2BQ=102

SAT-MIX1

SAT-MIX2

T emperature (F)

Pressure (psi)

Mass Flow Rate (lb/hr)

Duty (MMBtu/hr)

Q Duty (MMBtu/hr)

W Power(kW)

Water Scrub System

Black/Grey Water & Slag Handling Systems

Syngas Cooling / Condensate SystemGasification Coal Drying

Heat Recovery

Sour Shift Conversion

Shell Gasifier w/ Sour Shift Conversion

(Manual Adjust)

(Manual Adjust)

125

29

159597H2S-RECT

H2S(IN)

100

145

104938ENR-AI R

O2-ENR-2(IN)

300

21

193719TO-SCOT

TO-SCOT(OUT)

675

28

264535

TO-SEP-1

300

28

210138SEPGAS-1

300

28

54397

S-1

500

27

210138TO-RX-2

795

25

210138RX-2-OUT

608

24

210138

TO-SEP-2

300

24

201283

SEPGAS-2

300

24

8855S-2

410

23

201283TO-RX-3

471

22

201283RX-3-OUT

365

21

201283

TO-SEP-3

300

21

7564

S-3

299

15

70816SULFUR

795

25

210138TO-COOL2

471

22

201283TO-COOL3

2000

28

264535RX-1-OUT

2000

28

264535TO-COOL1

60

25

0

H2S-SCOT

121

29

159597H2S-1

121

29

159597

TO-RX-1

0

RX-1-BP

COOL-1BQ=-28

RX-2Q=0

COOL-2BQ=-18

RX-3Q=0

COOL-3BQ=-4

MIX

RGIBBS

PHASE-2

Q=27RGIBBS

PHASE-3

Q=24RGIBBS

PHASE-1

Q=145MIXER

H2S-SPLT

REHEAT-1Q=11

REHEAT-2Q=6

RX-1Q=0

COOL-1AQ=-101

COOL-2AQ=-11

COOL-3AQ=-6

Temperature (F)

Pressu re (p si)

Mass Flo w Rate (lb/h r)

Duty (MMBtu /h r)

Q Duty (MMBtu /h r)

Claus Process

Note: To simulate a split -flowprocess rather than a straight-through process, simply activatedesign spec "T EMP" and changethe temperature of "REHEAT-1" to640°F (necessary to hydrolize COSand CS2 to protect subsequentcatalyst stages from poisoning).

Note: Aspen seems to be lacking some thermodynamicpropert ies for S2, S3, S4, S5, S6, S7, and S8 related tovapor pressure that are necessary to perform a flashcalculat ion. For this reason, blocks "PHASE-1","PHASE-2", and "PHASE-3" are used to convert all ofthese compounds to S prior to the flash blocks. Notethat there is some enthalpy change associated withthis simplificat ion, and it is neglected in this simulation.

Note: Enriched air from the ASUis used to simulate an oxygen-enriched Claus process.

300

21

193719

CLAUSGASTO-SCOT(IN)

100

43

164089

TO-RECT REC-RECY(OUT)

212

419

552

H2

464

19

193719PREHEAT

536

19

194271

REDUCED

100

17

165777

COOLED-2

100

27

1688H2O-2

300

18

194271

COOLED-1

100

17

28494H2O-1

FURNACEQ=0

TG-COMPW=2266

COOLER-2

Q=-41

COOLER-1

Q=-13

HEATERQ=9

Temperature (F)

Pres sure (p si)

Mas s Flow Rate (lb/hr)

Q Duty (MMBtu /h r)

W Power(kW)

SCOT Process

Literature shows outlet temperatureof 572°F. Uhde indicates the rangecan be between 536°F and 572°F.By selecting the lower temperature,H2 usage is cut in half. Note thatmost of the heat produced is frommethanation -- this should beverified (i.e., Ni catalysts are activefor methanation, but I don't knowhow active a Mo/Co/Al catalystwould be).

Manually Adjust Pressure

65

17

2528026

CO2CO2(IN)

86

1515

1644841

CO2-PROD CO2-PROD(OUT)

437

1160

670727GFR-CO2

GFR-CO2(OUT)

0H2O-1

100

17

2528026CO2-1

17

0KO-LIQ-6

437

1160

2528026

CO2-2

80

1286

1644841LIQUID

96

1286

1857299

CO2-5

80

1286

212458VAPOR

437

1160

1857299

CO2-3

80

1160

1857299

CO2-4

KO-DRUMQ=19

COMPR-1W=141932

CO2-PUMP

W=525

CO2-SEPQ=-101

CO2-SPLT

COMPR-2W=1248

COOLERQ=-201

Tem perature (F)

Pressure (psi)

Ma ss Flow Rate (lb/hr)

Q Duty (MMBtu/hr)

W Power(kW)

CO2 Liquefaction

Not e: Final pressure from thecompressor is set at 1286 psi,which allows for some inerts inthis st ream. Block "CO2-SEP"is modeled as a SEP block becauseAspen seems to have t roublepredict ing liquefact ion using aflash even when a small amountof inerts is present.

212

442

1350199SYNGAS-1

SYNGAS-9(IN)

46

389

280657

FT-TG TG-FT(OUT)

428

395

250440

FT-WAXFT-WAX(OUT)

117

392

154968

FT-MID-D FT-MID-D(OUT)

47

389

22877

FT-NAP FT-NAP(OUT)

428

436

1350199

SYNGAS-2

-186

FT-HX

428

396

1350199

FT-PROD1

1428FT-MPS-1

Q

300

393

1185752

FT-GAS-2

117

392

690711

FT-GAS-3

117

392

404860WATER-2

117

392

90180

MID-DIS1

428

395

1185752

FT-GAS-1

395

0

WATER-1

428

395

164447

WAX-1

41

390

690711

FT-GAS-4

49

389

680878FT-GAS-5

49

389

3480WATER-3

49

389

6353

NAPHTHA132FT-REF-1

Q

70

438

1479671

FT-GAS-7428

436

1479671FT-GAS-8 428

396

1479671

FT-PROD2

647FT-MPS-2

Q

428

395

1393679

FT-GAS-9

428

395

85992

WAX-2

395

0

WATER-4

300

393

1393679

FG-GAS10

117

392

1099842

FT-GAS11

117

392

229049WATER-5

117

392

64788

MID-DIS2

41

390

1099842

FG-GAS12

39

FT-REF-2Q

46

389

1079450FT-GAS13

46

389

3868WATER-6

46

389

16524

NAPHTHA2

46

389

798793

REC-GAS1

47

389

1479671

FT-GAS-6

117

392

404860

H2O-MIX1

116

389

408340

H2O-MIX2

117

392

229049

H2O-MIX3

116

389

641257

FT-WATER

FT-RX-1

Q=-1614

MID-SEP1

Q=-371

COOL-1Q=-262

WAX-SEP1

Q=0

NAP-SEP1Q=0

COOL-2Q=-32

SG-PRHT2Q=269

FT-RX-2Q=-916

WAX-SEP2

Q=0

COOL-3Q=-89

MID-SEP2Q=-355

COOL-6Q=-39

NAP-SEP2Q=0

GAS-SPLTGAS-MIX

REC-COMP

W=4731

WAX-MIX

H2O-MIX1

H2O-MIX2

H2O-MIX3

H2O-MIX4

MDIS-MIX

NAP-MIX

SG-PRHT1

Q=186

Temperature (F)

P ressu re (ps i)

Mass Flow Rate (lb/hr)

Duty (MMBtu/h r)

Q Duty (MMBtu/h r)

W P ower(kW)

Fischer Tropsch Synthesis

428

395

250440

FT-WAXFT-WAX(IN)

47

389

22877

FT-NAPFT-NAP(IN)

212

419

6208

H2 H2-REF(IN)

117

392

154968

FT-MID-D FT-MID-D(IN)

212

110

58234

PSA-TGPSA-TG(IN)

68

15

117682

NAPHTHANAPHTHA(OUT)

68

27

281976

2-DIESELDIESEL(OUT)

107

251

34461

TAILGAS TG-REF1(OUT)

825

15

247164

FH-EXHSTFH-EXHST(OUT)

816

490

99845

BOT-WAX2

548

395

350285WAX-1

165

15

117682

NAPHTHA2

439

27

281976

COL-DIES

181

15

94805

NAPHTHA1

102

31

475979

MD-6

810

32

99845BOT-WAX

182

15

94158

TOP-NAPH

-49Q-REBOIL

-160Q-FURN

41

251

25870

CRAK-GAS

358

251

8591

FLSHGAS2

555

2131

350285

WAX-2

776

2131

175114

HC-W AX-2

819

2131

5566

H2-CRAK2

702

2129

530965

WAX-3

-29

Q-HC

757

255

175114

HC-W AX-1

104

252

26517

HCRACK-5

41

251

647

CRAK-NAP

1

R-REF-1Q

300

253

355852

HCRACK-4

104

252

329335MID-DIS3

306

392

155610

MD-4

104

250

484945

MD-5 117

392

155610MD-1

572

392

155610

MD-2

212

419

642H2-TREAT

212

419

5566

H2-CRAK1

705

2029

530965

HCRACK-1

788

2024

530966

HCRACK-2

698

392

155610

MD-3

-238

COL-HEAT

70

15

188931

HT-AIR

825

15

247164FH-EX-1

757

255

355852HCRACK-3

102

31

375MD-W ATER

255

0

HC-W ATER

WAX-MIX

N-COOLERQ=-18

D-COOLERQ=-61

NAP-MIX1

ATM-DISTQC=-102QR=49QF=160

HC-HEATQ=29

WAX-PMP2W=804

NAP-SEP3Q=-1

MID-SEP3Q=-44

HYD-COOLQ=-18

HYD-PRHTQ=50

WAX-PMP1W=1124

BOT-PUMPW=116

H2-SPLT

DIST-MIX

NAP-MIX2

H-CRAK-2Q=0

HY -TREATQ=0

FIRED-HTQ=-238

HC-COOLQ=-138

Q

M I X E R

HEAT-MIX

MD-FLASHQ=0

H-CRAK-1Q=0

WAX-SEPQ=0

HYD-RECPQ=-50

H2-COMPW=3438

R S TOI C

NOX-ADJQ=0

Tem peratur e (F)

Pressure (psi)

Mass Flow Ra te (lb/hr)

Duty (MMBtu/hr)

Q Duty (MMBtu/hr)

W Power( kW)

Product Refining & Upgrade

FG-COMPW=307

102

31

8591

FLSHGAS1

TG-MIX

48

389

300934

GT-FUELGT-FUEL(IN)

1200

15

6544856

EXHAUST GT-POC(OUT)

687

184

5602331GT-AIR-570

435

300934

GT-FUEL3

2325

175

5903266

GT-NOX

2322

175

5903266

GT-POC-1

687

184

641590

GT-AIR-4

687

184

6243921GT-AIR-3

59

15

6243921

GT-AIR-2

80

425

0

GT-N2

49

389

300934

GT-FUEL2

59

15

6243921

GT-AIR-1

GT-COMBQ=0

GT-NOX

Q=-15

GT-TURB

W=-541064

GT-SPL-1

GT-COMP

W=282472

N2-MIX

FILTER

FUELCOMPW=746

Temperature (F)

Pressu re (p si)

Mass Flow Rate (lb/h r)

Q Duty (MMBtu /h r)

W Power(kW)

Gas TurbineThe gas turbines are producing 250.7 MWcompared to the rating of 349.2 M W for 2 xGE 7241FB gas turbines.

825

15

247164FH-EXHST

FH-EXHST(IN)

FUEL-GAS

1200

15

6544856EXHAUST

GT-POC(I N)

330

15

6792095

STACKGAS STACKGAS(OUT)

220

1929

687209HP-BFW-2

811

15

6792020

EX-3

631

1929

687209

HP-BFW-3

632

15

6792020

EX-4

989

15

6792020

EX-2

629

1900

687209

HPS

200

17

6601557BFW-2

417

300

110960

FT-STM-2

217

17

6712517

BFW-3

217

17

687209

HP-BFW-1

629

1900

680337

HPS-1

688

463

680337

TO-REHT

1200

15

6544856

EXHST-1

1040

1800

680337

HPS-2

1040

400

680337

LPS

996

15

6544856

EX-1

105

1

680337

COND-1

120

17

6601557BFW-1

632

15

6792095

EX-5

105

1

680337

COND-2

59

15

716663MAKEUP

82

1

1397000COND-3

82

17

1397000COND-4

AIR-1

FG-EXH-1

0

FG-EXH-2

217

17

2745155

IPGEN-1217

17

792333

LPGEN-1

217

17

2487819FTGEN-1

82

17

1397000

BFW

293

60

338039

LP-COND

300

0

FT-COND

503

700

148868

IP-COND

105

17

4717649CON-4

217

60

792333

LPGEN-2

217

300

2487819FTGEN-2

218

700

2745155

IPGEN-2

503

700

1886496IP-STM

417

300

1886496T-EFF-1417

300

1776381KO-1-VAP

417

300

2376859FT-STM-1

287

55

4153240

T-EFF-2

287

55

3877355KO-2-VAP

293

60

454294LP-STM

105

1

4331649T-EFF-3

417

300

110115

CON-1

287

55

275885CON-2

105

1

4717649CON-3

417

300

2487819

FT-STM

68

20

75NH3

629

1900

6872HPB-BD

HPEQ=324

HPBQ=331

DA

HP-PUMP

W=1500

SHRHQ=-375

HP-TURBW=-29261

LP-TURBW=-94435

LTEQ=531

CONDSR-1Q=-667

MU-MIX

C-PUMP-1W=23

EXST-MIX

D-FI RE-1

RSTOI C

NOX-ADJ1EX-MIX-1BFW-SPLT

COND-MIX

LP-PUMPW=38

FT-PUMPW=744

IP-PUMPW=1982

S-TURB-1W=-24657

S-TURB-2W=-103406

S-TURB-3W=-203195

KO-1Q=0 KO-2

Q=0

CONDSR-2Q=-4143

C-PUMP-2W=77

STM-SPLT

SCRQ=0

HPB-BD

Temperature (F)

Pressu re (psi)

Mass Flo w Rate (lb/hr)

Q Duty (MMBtu/h r)

W Power(kW)

HRSG & Steam Turbines

Condensing Steam T urbines

HRSG

(Manual Adjust )

Saturated Steam T urbines

Not e: If you change t he design specthat controls t he deaerator t emperature,be sure to update t he utility inlet specsfor all t hree steam levels.

Greenhouse Gas Emissions Calculations

• Greenhouse Gas (GHG) emissions calculations were calculated for the following coal/biomass to liquid cases:– Case 1 - 100% coal fed FT process

– Case 2 - 100% coal fed FT process with carbon capture and sequestration (CCS)

– Case 3 – 70 wt. %, dry, coal and 30 wt.%, dry, poplar biomass fed FT process

– Case 4 – 70 wt. %, dry, coal and 30 wt.%, dry, poplar biomass fed FT process with CCS

• GHG calculations were based upon the approach developed by NETL – Life-Cycle Greenhouse-Gas Emissions Inventory for Fischer-Tropsch

Fuels, NETL, 2001

GHG Emissions Calculations - Emission Sources

• Resource extraction and production

– CO2 adsorption credit for biomass re-growth

• Resource and product transportation emissions

• Conversion and refining

– CO2 sequestration credit

• End use combustion

• Potential credit for clean power production

Upstream (“well’)

PolyGen Conversion Plant

Product Disposition(“wheel”)

AtmosphericCO2

Sub-terrain Carbon

GHG

GHG GHG

Electricity

Diesel Fuel

LPG Fuel

Naphtha

Feedstock Production& Transportation

Emissions

FuelsTransportation

Emissions

Stack, Vent& FugitiveEmissions

GHG

FuelsCombustionEmissions

ConsumerProducts

Fuel

Chemicals

CO2Sequestration

& EOR

PressurizedCO2

Upstream (“well’)

PolyGen Conversion Plant

Product Disposition(“wheel”)

AtmosphericCO2

Sub-terrain Carbon

GHG

GHG GHG

Electricity

Diesel Fuel

LPG Fuel

Naphtha

Feedstock Production& Transportation

Emissions

FuelsTransportation

Emissions

Stack, Vent& FugitiveEmissions

GHG

FuelsCombustionEmissions

ConsumerProducts

Fuel

Chemicals

CO2Sequestration

& EOR

PressurizedCO2

ORCF

0

100

200

300

400

500

600

700

800

900

PetroleumDiesel

CTL CTL, CombinedCycle, 30%Biomass

CTL, CombinedCycle, Seq and30% Biomass

Gasoline Corn E85

gGHG-eq/mile Diesels Gasolines

Life-Cycle GHG Emissions for Various Fuel TypesIdaho National Laboratory GREET Model Results

Greenhouse Gases, Regulated Emissions and Energy Use in Transportation

Ohio River Clean Fuels

Petroleum DieselBenchmark

Decrease in Life-Cycle Urban EmissionsFT Diesel Compared to Petroleum Low Sulfur Diesel

0%

20%

40%

60%

80%

100%

VOCs CO NOx PM10 SOxCriteria Pollutant

Percent Reduction

* Based on NETL GHG study from FT plants

Conclusions

• Aspen Plus Conceptual Model– Aspen Plus can be utilized for rigorous material and energy balances for

CTL processes– Process efficiency improvements can be investigated with Aspen Plus

• GHG Emissions– GHG emissions from CTL plants without CCS are approximately twice

those for traditional diesel derived from crude– Incorporation of CCS, biomass feedstocks, and cogeneration of power can

improve GHG emissions for CTL fuels to meet or beat GHG emissions from traditional diesel

Recommendations – Things we should do…

• Plan for carbon management and sequestration as part of your project.

• Incorporate biomass utilization and direct your political capital to promote renewable FT diesel .

• FT Diesel should be included in the solution using diesel hybridengines.

• Do invest your efforts to engage the environmental community with facts and answers to their concerns.