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.