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Coal gas as a feed fuel for phosphoric acid fuel cell power plants
0360-3199/83 $3.00 + 0.00 Pergamon Press Ltd. © 1983 International Association for Hydrogen Energy.
Int. J. Hydrogen Energy, Vol. 8, No. 7, pp. 499--508,1983. Printed in Great Britain.
C O A L GAS AS A F E E D F U E L F O R P H O S P H O R I C ACID F U E L CELL P O W E R PLANTS B. R. KRASICKIand B. L. PIERCE Westinghouse Electric Corporation, Advanced Energy Systems Division, Pittsburgh, PA 15236. U.S.A.
(Received for publication 7 January 1983) Abstract--Westinghouse Electric Corporation has assessed the effects of a number of coal gasification systems and their gas compositions on a 7.5 MW(e) dc Phosphoric Acid Fuel Cell (PAFC) power plant. Both low and medium BTU synthesis gases were considered from various promising gasification processes. Degree of development or commercialization, technical complexity, availability and coal restrictions were taken into account. System studies performed on the 7.5 MW(,) dc PAFC power plant for nonintegrated and integrated fuel conditioning systems are discussed for the various gasification processes. In all cases coal gas was assumed to be purchased "over-the-fence". Representative characteristics for the derived coal gases and PAFC system performance data are presented. The direct capital costs of the PAFC power plant are evaluated for each system.
INTRODUCTION Westinghouse Electric Corporation has been working on various fuel cell technologies. Studies have shown that the phosphoric acid fuel cell (PAFC) is near term for both utility on-site power generation and commercial co-generation. The fuel cell selected for development by Westinghouse is a Gas Cooled concept originated by Energy Research Corporation (ERC). Westinghouse and E R C have formal working agreements whereby Westinghouse has access to E R C technology. The Gas Cooled fuel cell is efficient, reliable and cost effective. To facilitate the development of a commercially viable P A F C power plant, Westinghouse had undertaken a study (EPRI Contract RP1041-7) to assess the effects of alternate fuels on the performance and economics of candidate P A F C power plants. The hydrogen-rich fuel that feeds the fuel cell can be processed from almost any organic-based chemical. One of the candidate fuels considered was coal gas. A study was made for coal gasification systems, their product gas compositions and their applicability to Phosphoric Acid Fuel Cell (PAFC) power plants. The information gathered on the various coal gasification processes was for both low and medium BTU gas and specifically includes the detailed surveys conducted by O R N L and E R D A [1, 2]. Over 100 gasification processes were considered in the O R N L study. The most promising systems were selected by O R N L taking into account such major categories as degree of development or commercialization, technical complexity, availability and coal restrictions. These processes were grouped according to their generic gasifier type such as fixed, fluidized, entrained and molten. Additional cleanup would be required prior to processing in the fuel cell plant to remove sulfur and other impurities. DISCUSSION Twenty-one promising coal gasifiers are listed in 499
Table 1 (abstracted from [1, 2]). These processes by no means represent all the viable gasification systems available to date. They do, however, represent a generic group of gasifier bed types such as fixed, fluidized, entrained and molten for potential application with a Phosphoric Acid Fuel Cell (PAFC) power plant. The gas composition for each system is for oxygen and/or air blown cases. These compositions are the best average values representing the product coal gas out of the gasification plant. Additional cleanup is required in some cases to remove sulfur and other impurities prior to fuel conditioning in the P A F C plant. These impurities in excess of several ppm are detrimental to the performance and life of the fuel conditioner and fuel cell systems. Typical characteristics for the various coal derived gases are summarized in Table 2. The total hydrogen concentration out of the P A F C fuel conditioner was calculated for each of the gasification systems. A 1.3 water/carbon monoxide mole ratio was assumed for the fuel shift reaction. The additional 30 volume % water is used to reduce the carbon monoxide to acceptable levels and to minimize the potential for carbonization in the shift reactor catalyst bed. For the oxygen blown gasifier cases, the average hydrogen concentration after the shift reaction is approx. 50 mole %. The air blown cases were somewhat lower due to nitrogen inerting but still acceptable for P A F C feed. The average hydrogen concentration for the air blown cases is 30 mole %. For both the oxygen and air blown cases, the hydrogen feed concentration to the fuel cell (after shift) appears to be independent of the type of gasifier and the kind of coal used. It is important to have a sufficient concentration of hydrogen in the fuel cell feed gas. This can be seen in Fig. 1 which shows the effect of reduced hydrogen on the overall fuel cell voltage. For the oxygen blown gasifiers the voltage loss is 25 ~ 35 mV compared to pure hydrogen for fuel utilizations of 0.8 and 0.9, respectively. When compared to the air blown gasifiers
15.0
38.4
17.0
. 50~66
270 ~ 305
120 --~ 168
~280
175 ~ 205
300 ---, 350
~150
WellmanGalusha WellmanGalusha
Fixed bed
Fluidized bed Fluidized bed
Fluidized bed Fluidized bed Fluidized bed Fluidized bed
Fluidized bed
Fluidized bed
WoodallDuckham/Gas Integrale Battelle agglomerating burner Battelle agglomerating burner BCR TRI-gas
Fixed bed
02
Air
C O gas
CO gas
CO2 acceptor Air
~335
57.9
58.8
~380
CO2 acceptor
02
15.8
~150
39.4
B C R TRI-gas Air
02
Air
Oz
Air
WoodalP 02 Duckham/Gas Integrale
Air
Fixed bed
Fixed bed
.
~150
Lurgi, dry ash Air
Fixed bed
O2
24.0
285 --~ 300
Lurgi, dry ash 02
.
Fixed bed
~150
Air
British Gas Lurgi slag
27.8
Fixed bed
370 ~ 380
H2
02
Reactants
British Gas Lurgi slag
Process
BTU/SCF HVV
Fixed bed
Reactor type
.
.
.
31.2
15.5
31.2
0~39
.
28.3
37.5
28.6
16.0
16.9
60.6
CO
.
.
.
4.0
13.7
--
1 ~6
2.7
3.5
2.7
.
4.0
9.0
.
7.6
CH4
Gas compositions (mole %)
.
4.5
18.0
3.4
14.0
31.5
6.6
9.1
0.5
3~28
.
2.6
CO2
.
.
2.9
0
0.3
52.3
47.2
0.3
0.2
2.2
0.4
41.0
1.6
50.3
.
1.0
Nz(Ar)
--
1.0
0.8
--
H2S(COS)
111. No. 6
Bituminous coal Lignite
63.4
61.8
33.4
33.1
Bituminous
Bituminous type coal
51.0
Bituminous
33.1
31.8
Commercial; outside U.S.A.
46.2
Pilot unit shutdown 1978; approx. 65% N2 removed from composition stream P D U unit in U.S.A.; no 02 information in the literature P D U unit in U.S.A.; no reformer required Work completed in U.S.A.; not commercial; need reformer W o r k completed in U.S.A.; not commercial; no information available for air blown case Pilot plant in England; needs reformed Pilot plant in England; needs reformed
O2 tests p e r f o r m e d - - n o data reported Concentration of methane is low enough that no reformer is needed; 12 in U.S.A.; commercial units available Commercial; outside U.S.A.; concentrations reported are after scrubbing; methane concentration such may require a reformer As above; methane concentration is low enough that a reformer may not be required Pilot plant O2 runs; no data reported in literature
Commercial; outside U.S.A.
49.4
Comments Near-commercial; outside U.S.A.; molten slag; methane conc. high; will need reformer No data reported
Bituminous
Pittsburgh No. 8; III. No. 6; bituminous; nearly all coals Pittsburgh No. 8; III, No. 6; bituminous; nearly all coals Anthracite
Donisthorpe, nearly all coals
Coal type
H2 % after shift 1.3 H 2 0 / C O
T a b l e 1. P r o m i s i n g c o a l g a s i f i c a t i o n s y s t e m s a n d t h e i r p r o d u c t g a s ( r e p r e s e n t a t i v e c o m p o s i t i o n s )
Z Z7
>
>
7~
~154 ~285
Westinghouse O:
260 --, 290
Winkler
Entrained flow Molten bath
02
Combustion engineering Combustion engineering FosterWheeler FosterWheeler KoppersTotzek KoppersTotzek Texaco
Air
02
Texaco
Rockwell International
02
~250 (279) 39.0 (35,8)
36.0
=290
02
Air
14.2
10.6
~160
~120
Air
02
Air
Air
BI-gas
32.0
~356
02
Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow
23.3
8.4
~150
Air
37.6 (44.6)
52.5
29.1
24.7
29.3
65.3
27.9
~300
O2
Babcock and Wilcox Babcock and Wilcox Bl-gas
Entrained flow Entrained flow Entrained flow
22.0
14.0
Air
Winkler
Fluidized bed ~150
•9.2
51.1
49.1
19.6
16.1
10.1
13.2
23.8
48.2
14.4
25.6
29.8
17.5
41.4
21.5
32.3
30.2
35.3
02
120 ~ 150
Westinghouse Air
Fluidized bed Fluidized bed
~350
Westinghouse 0 2
Fluidized bed
~320
0 2
Air
U-gas
U-gas
~150
~355
Fluidized bed Fluidized bed Fluidized bed
Air
02
Synthane
370
Synthane
Air
HY gas
02
Fluidized bed
Fluidized bed Fluidized bed
Table 1 (continued) Fluidized H Y gas bed
(1.0)
0.5
3.4
15.7
1.0
1.8
2.7
10.2
3.2
3.4
35.8
5.6
15.0
18.6
20.8 (18.o)
10.0
3.3
4.0
21.5
4.6
5.0
7.0
13.8
9.3
9.9
17.2
9.9
5.9
17.9
36.2
24.5
1.5 (0.1)
0.4
0.7
0.5
0.8
0.2
0.6
0.1
L7
0.5
0.7
0.2
0.7
1.6
1.2
Subbituminous Bituminous
111. No. 6
111. N o . 6
Bituminous subbituminous
0.6
1.1
49.3
60.4
0.7
63,5
1.2
56.0
0.9
Eastern; Western; any coal
Eastern coal
I11. No. 6
Pittsburgh seam
Pittsburgh No. 8 Pittsburgh No. 8 Pittsburgh seam
Subbituminous
Lignite
0.3 Pittsburgh seam; Eastern coal 0.5 Pittsburgh seam; Eastern coal 54.3 Eastern coal
43.5
0.6
43.5
--
0.1
51.4 (51.0)
52.6
31.4
26.7
44.4
24.3
50.4
28.0
51.3
26.9
46.1
48.2
29.6
47.6
27.9
38.8
41.2
Commercial units worldwide but outside U.S.A.; methane l o w - no reformer needed Commercial units worldwide but outside U.S.A.; methane l o w - no reformer needed Near-commercial; U . S . A . ; no reformer--methane content low Near-commercial; U . S . A . ; no r e f o r m e r - - m e t h a n e content low Pilot plant operation; U . S . A . ; high methane c o n c e n t r a t i o n - needs reformed No data in the literature for air blown gasifier No data in the literature for oxygen blown gasifier P D U system; U.S.A.; no reformer required No data in the literature for oxygen blown gasifier Pilot facility in U.S.A.; may need reformer Commercial worldwide outside U.S.A.; no reformer required No data found in literature search for air blown case Near-commercial; U.S.A.; no reforming (data provided by the Fuel Cell User's group) No information in the literature for air blown case No information in the literature for 02 blown case
Proposed commercial compositions; high methane needs reformer PDU U.S.A.; no reformer
Pilot plant in U.S.A.; very high methane Pilot plant in U.S.A.; needs r e f o r m e r - - m e t h a n e concentration too high Pilot plant in U.S.A., needs r e f o r m e r - - m e t h a n e concentration too high Pilot plant in U.S.A.; very high methane; needs reformer Pilot plant in U.S.A.; may need reformer P D U U.S.A.; may need reformer
Pilot plant in U.S.A.; very high methane; needs reformer
O
O
"
fJ~
t-'
502
B. R. KRASICKI AND B. L. PIERCE Table 2. Representative characteristics for coal derived gas* Medium BTU Low BTU Low methane Low methane
05
" ~
o ~o ~= ~ ~= =~=~
~o
0
~, 0
0
0
0
P'.O
Composition
(vol. %)
~=~ ~
H2 CO CH4 COz
:''
H2S N2 Heating value (BTU/SFC)
I
8
I
I
I
<::5
I
I
37.7 50.4 0.3 10.1 0.1 1.4 250
15.0 28.6 2.7 3.4 -50.3 150
26.6 51.1 10.2 9.9 1.7 0.5 350
* The Westinghouse fluidized bed gasifier is a commercially viable system that can be tailored to produce a range of medium or low BTU gas having either low or high methane content.
I
(37---> 45 mV), the average differential voltage loss between the two cases is approx. 12 mV. This amounts to 1.8% reduction in overall fuel cell performance for air vs oxygen blown coal gas utilization assuming an operating voltage of 0.66 V/cell. For oxygen blown coal gas, the degradation in overall fuel cell performance compared to pure hydrogen feed is approx. 4%. The air blown case degradation is approx. 6%. (Relatively pure hydrogen feed could possibly be obtained using hydrogen separators in place of shift converters.) This means that the fuel cell system needs 4---~6% more fuel feed gas to obtain the same voltage output compared to pure hydrogen feed. In order to utilize this increased fuel flow and maintain a fixed total voltage, the number of fuel cells will have
<
"
Medium BTU High methane
I
',q.
N2 INLET MOLE FRACTION 0.0
r'G,
~
-:
o
0.6
i! /,/
0.8
1.0
/// o.,,2
o
©
8 <0 = oo .~ =N - ~
0.4
-10
.30
=©
0.2
-~ ~ "~ -~
~=
-70 II
r
Fig. 1. PAFC voltage loss due to decrease of hydrogen concentration in the anode feed gas.
COAL GASIFICATION SYSTEMS
FUEL ~
~'~(~VENT
503
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~ STEAGM 0
AIR
..Y.°
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.......
llJlllJ!ljl ANODE COOLING CA~MO~[ P L LL
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W ...... o,
r ...... , -l.--/++k.~
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'tOW l r l m TI~IATI~EI+I
~
|
+ "
m [
°
* corn
I~O£.IN~
STO~AS[L
TRE,+~'[~+
Fig. 2. Coal gas flow schematic (nonintegrated fuel conditioning system).
Table 3. Performance summary coal gas fueled nonintegrated system Gross dc electrical output (kW) Gross ac electrical output (kW) Turbogenerator ac power (kW) Gross ac power (kW) Parasitic losses (kW) Pumps Fans (cooling tower) Vacuum pump Air compressor and dryer Controls Net electrical ac output (kW) Input energy (HHV) BTU/h Overall plant efficiency Heat rate (BTU/kWh)
7500 7200 1178 8378 23 210 3 1 15 8126 74.03 x 106 0.375 9110
to be increased. This will result in approx, a 4 ~ 6% increase in direct capital cost of the fuel cell system over a pure hydrogen feed. The product gas from coal gasification systems has a significant concentration of carbon monoxide. The carbon monoxide "results in some performance loss" to the PAFC if the concentration is greater than about 1-4 volume %. Therefore, the product coal gas carbon monoxide is shifted by adding steam to produce carbon dioxide and hydrogen. A n oxygen blown entrained flow gasifier product gas was selected as representative of a medium BTU, low methane gas, and was used as a basis for this study. This gas was typical in composition of medium BTU gas from any type of coal where the desired methane concentration was low. Figure 2 shows a conceptual coal gas flow schematic
B. R . K R A S I C K I
504
A N D B . L. P I E R C E
T a b l e 4. S t a t e p o i n t s f o r c o a l g a s n o n i n t e g r a t e d fuel c o n d i t i o n i n g s y s t e m
Station
Temp (°F)
Pressure (psia)
H2
H20
CO
CO2
02
1 2 3 4 5 8 10 11 12 13 14 15 16 17
350 350 1754 1200 360 80 135 280 277 352 269 249 269 138
--------50 50 49 30 49 15
0.482 0.156 ---0.39 ---------
0.01 0.015 ---0.376 . . ---. ---
0.365 0.593 0.434 0.434 0.434 0.208 . . . . ---. . ---
--0.007 0.007 0.007 -. . 0.100 0.094 0.094 . 0.094 0.094
0.004 0.006 0.295 0.295 0.295 0.006 . . . . 0.713 0.709 0.709 . . 0.709 0.709
18
96
15
--
--
--
0.106
0.798
19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 35 37 38 39 40 41 42 43
96 249 141 135 80 80 348 269 273 135 136 106 244 80 100 135 600 521 820 452 436 350 587
0.128 0.207 0.264 0.264 0.264 -1.000 1.000 0.187 0.197 0.197 1.000 0.197 0.175g 0.0221 0.054g 0.0421 1.000 1.000 1.000 1.000 0.010 0.010 0.010 0.197 0.197 1.000 1.000 1.000 1.000 0.010 0.010 1.000 -0.219 0.078 0.078 0.244 0.244 0.128
. . . . 0.253 0.208 0.208 0.094 0.094 . . . . 0.208 0.208 . --------
. . . . 0.782 0.782 0.782 0.709 0.709 . . . . 0.782 0.782 . 0.006 0.005 0.005 0.005 0.004 0.004 0.004
15 30 3 3 14.6 14.6 50 49 50 30 3 15 3 15 15 ---------
Mole fraction
----------------0.39 0.305 0.44 0.44 0.365 0.365 0.492
. . . . -----. . . . --. 0.376 0.294 0.15 0.15 0.125 0.125 0.010
where the fuel conditioning s y s t e m is n o t i n t e g r a t e d with the balance of plant. Since the methane concent r a t i o n is l o w , t h e m e t h a n e w i l l a c t a s a n i n e r t i n t h e fuel cell. Reforming o f t h e c o a l g a s is t h e r e f o r e n o t r e q u i r e d . T h e f u e l u t i l i z a t i o n i n t h e f u e l c e l l is a s s u m e d to be 80% which produces an exhaust fuel mixture that h a s 1 5 . 9 v o l u m e % h y d r o g e n . W h e n t h i s e x h a u s t g a s is mixed with compressed air at a stoichiometric ratio of 1.1, the resulting mixture will burn without the use of a catalytic combustion chamber. The flame temperature w i t h t h i s m i x t u r e is a b o u t 1 7 5 0 ° F . T h e h o t g a s is t h e n expanded through a turbine, which drives an ac generator and the air compressor. The turbine exhaust at 1 2 0 0 ° F is t h e n c o o l e d i n a l o w p r e s s u r e s t e a m g e n e r a t o r t o 3 6 0 ° F . S t e a m is a l s o g e n e r a t e d in the exothermic
. . . .
. . . . ------
. . . .
. . . . ---
.
. 0.208 0.162 0.303 0.303 0.249 0.249 0.365
Flowrate
N2
H2S
CH4
(lb/h)
0.01 0.015 ---0.015
0.003 0.005 ---0.005
----
----
---
---
24320 23395 34685 34685 34685 16487 15718 9986 1103350 1104190 1104190 240 65160 65160
--
--
60190
. . . . ------
------
---
---
0.015 0.012 0.012 0.012 0.010 0.010 0.010
0.005 0.004 0.004 0.004 0.003 0.003 0.003
. . . .
.
4970 24110 22610 24110 12720 64320 64320 1039030 1039030 28930 773930 773930 1500 4.8 × 106 4.8 × 106 5732 16487 20357 20357 20357 24320 24320 24320
shift converter and the anode gas cooler. These three heat exchangers produce more steam than required for the fuel conditioning reaction. T h e e x c e s s s t e a m is directed to the steam turbine. The conceptual coal gas fueled PAFC plant performa n c e is s u m m a r i z e d in Table 3 for a nonintegrated fuel conditioning system. The gross ac output comes from two sources, the fuel cell and the anode side turbogenerator. The net electrical output for this configura t i o n is s i g n i f i c a n t l y g r e a t e r t h a n t h o s e P A F C p l a n t s that would require reforming the fuel feed. The heat r a t e f o r t h i s c a s e is 9 1 1 0 B T U / k W h with a dry cooling tower. The state points for this case (Fig. 2) are given i n T a b l e 4. O n e o f t h e d e s i g n f e a t u r e s o f t h e n o n i n t e g r a t e d P A F C d e s i g n is t h a t t h e f u e l c o n d i t i o n i n g s y s t e m
COAL GASIFICATION SYSTEMS
505
CO 2 VENT
® .P
@
FUEL
®
@ @
'
I
T II ~!1
FUEL CELLS Q
l
'DSTEAM COMPRESSOR AIR TURBINE AIR
C(RCULATOR
)
IACT
~
CON.
®
,,. v
COOLING
Fig. 3. Coal gas flow schematic (integrated fuel conditioning system).
B. R. K R A S I C K I A N D B. L. P I E R C E
506
Table 5. Performance summary coal gas integrated system Gross dc electrical output (kW) Gross ac electrical output (kW) Parasitic losses (kW) Pumps Fans (cooling tower) Vacuum pump Air compressor and dryer Controls Net electrical ac output (kW) Input energy ( H H V ) BT U/h Overall plant efficiency Heat rate (BTU/kWh)* * Note that inefficiency.
this
does
not
7500 7200 23 205 3 1 15 6953 59.22 × 106 0.40 8520 include
coal
gasification
effectively o p e r a t e s i n d e p e n d e n t of the fuel cell system. Another conceptual schematic of a coal gas fueled p l a n t is s h o w n i n F i g. 3. T h i s d e s i g n i n t e g r a t e s t h e f u e l conditioning system with the PAFC plant. Here the h y d r o g e n c o n t a i n i n g a n o d e e x h a u s t is u s e d m o r e e f f e c t i v e l y i n t h e f u e l c e l l t o o b t a i n h i g h P A F C p l a n t effic i e n c i e s . T h e g a s is p a s s e d t h r o u g h a p u r i f i c a t i o n s y s t e m w h e r e i m p u r i t i e s such as c a r b o n m o n o x i d e , c a r b o n dioxide, methane and nitrogen are absorbed and hydrogen w i t h p u r i f y o f o v e r 9 9 . 9 9 % is o b t a i n e d . It s h o u l d b e n o t e d t h a t s u c h a h i g h d e g r e e o f h y d r o g e n p u r i t y is n o t a r e q u i r e m e n t for the fuel cell p e r f o r m a n c e . A s i m p l e r B e n f i e l d p r o c e s s c o u l d h a v e b e e n u s e d as a r e p r e s e n tative system.
Table 6. State points coal gas integrated system
Station
Temp. (°F)
Pressure (psia)
Mole fraction CO2 O:
H2
H20
CO
0.114 0.200 --
0.010 0.018 0.376
0.330 0.581 0.208
---
------
------
0.100 0.094 0.094 0.094 0.094
--
--
1 2 8
350 350 80
50 50 80
0.540 0.190 0.390
12 13 14 16 17
277 352 269 269 138
50 50 49 49 15
------
18
96
15
--
19 21 22 24 25 26 27 29 30 32 33 37 38 39 40 41 42 43 45 47 48 49 50 51 52
96 141 135 80 348 269 273 135 105 80 100 600 483 725 419 390 350 558 280 249 135 280 250 280 280
15 3 3 15 50 49 50 3 15 15 15 105 85 85 84 83 82 81 49 30 15 49 45 49 49
-----------0.396 0.371 0.492 0.492 0.441 0.441 0.540 ----0.479 ---
0.187 0.197 0.197 0.197 0.175g 0.0221 0.054g 0.0421 1.000 1.000 1.000 0.010 0.010 0.197 0.197 1.000 1.000 0.010 0.010 -0.242 0.122 0.122 0.212 0.212 0.114 1.000 1.000 0.173 1.000 0.506 1.000 1.000
. . . ----. . --0.382 0.242 0.121 0.121 0.108 0.108 0.010 . . -. -. .
. . . -----
--0.211 0.138 0.258 0.258 0.232 0.232 0.330 . . 0.827 . 0.015 . .
CH4
0.003 0.006 0.006 0.713 0,709 0.709 0.709 0.709
0.003 0.005 0.005 CH4 0.015 H2S ------
0.106
0.798
--
. . . 0.208 0.208 0.094 0.094 . . 0.208 0.208 -------. . -. -. .
. . . 0.782 0.782 0.709 0.709 . . 0.782 0.782 0.006 0.004 0.004 0.004 0.004 0.004 0.003 . . -. -. .
--
. . .
. .
N2
. .
. . . . .
-----
--0.005 0.003 0.003 0.003 0.003 0.003 0.003
---
Flowrate (lb/h) 19513 18581 13212 1103350 1104190 1104190 65160 65160 59500 5660 4934 4934 64320 64320 1039 030 1039030 167685 167685 1.0394 X 1 0 6 1.0394 × 1 0 6 12894 17504 17504 17504 19513 19513 19513 1998 17121 16849 2020 2603 2009 2009
COAL GASIFICATION SYSTEMS
507
Table 7. Coal gas prototype 8.10 MW¢ ac PAFC plant nonintegrated direct capital cost--1980 basis (thousands of dollars) Account No.*
$1000"~
341--Structures and improvements 342--Fuel handling and processing~ Fuel handling Fuel processing 343---Rotating equipment auxiliaries Gas turbine/generator system Steam turbine/expander Condenser system Separator system Cooling tower Air compressor system Air filter/silencer system Cathode exhaust gas circulator Miscellaneous auxiliaries 344---Electrical generating system Low pressure boiler system Recirculation ducts Fuel cell System 345--Accessory electric equipment Power conversion system Instrumentation and control DAS system Diesel generator system 346--Other miscellaneous power plant equipment 353---Station equipment Main transformer Total direct capital costt§ (land not included)
163 2171 64 2107 1074 262 177 32 22 133 295 2 98 53 4067 96 38 3933 2455 1712 390 245 108 265. 548 548 $10743 ($1326/kW)1[
* Federal Power Commission Uniform Systems of Accounts for Public Utilities. t EPRI Technical Assessment Guide. ~: Cost of initial catalyst is included in fuel processor cost (approx. 200 K). The fuel to the PAFC plant is commercially available medium BTU coal gas with low methane concentration. § R&D, G&A and fee (25%) are included. 1tBased on ac power to utility grid, the cost per kW does not include the coal gasifier. The fuel is assumed to be available over-the-fence.
The carbon dioxide removal system allows almost all of the hydrogen produced to be consumed in the fuel cell. The system also reduces the steam requirements for the shift reaction since the stream returning from the carbon dioxide removal system has high concentrations of both hydrogen and water vapor. A performance summary for the coal gas integrated case is given in Table 5. The state points for this concept (Fig. 3) are given in Table 6. A summary of direct capital cost for the two coal gas cases is presented in Tables 7 and 8. The significant cost differences between the two plants is in the Rotating
Equipment and Auxiliaries account. All other accounts remain virtually the same. In the auxiliaries to this account, the carbon dioxide cleanup system is expensive. The size and cost for cleanup was based on a commercially available potassium carbonate system designed for removing carbon dioxide from stack gases. Other gas purification systems should be considered to reduce overall cost. Preliminary evaluations to data indicate that a water scrubbing system may work but more detailed studies are needed to verify performance (i.e. sufficient carbon dioxide removal capability, system size and capital cost).
508
B. R. KRASICKI AND B. L. PIERCE Table 8. Coal gas prototype 6.96 MWe ac PAFC plant integrated direct capital cost--1980 dollars (thousands of dollars) Account No. *
$1000~
341--Structures and improvements 342--Fuel handling and processing$ Fuel handling Fuel processing 343---Rotating equipment and auxiliaries CO2 scrubber system¶ Steam turbine/expander Condenser system Separator system Cooling tower Air compressor system Air filter/silencer system Cathode exhaust gas circulator Miscellaneous auxiliaries 344--Electrical generating system Low pressure boiler system Recirculation ducts Fuel cell system 345----Accessory electric equipment Power conversion system Instrumentation and control DAS system Diesel generator system 346---Other miscellaneous power plant equipment 353----Station equipment Main transformer Total direct capital costt§ (land no included)
163 2171 64 2107 3106 2294 177 32 22 133 295 2 98 53 4067 96 38 3933 2455 1712 390 245 108 265 548 548 $12~/75 ($1838/Kw)11
See Table 7 for key to footnote symbols. ¶ Sized and costed based on a commercial K2CO3System for COz removable from stack gases.
Acknowledgements--The material in this paper is based in part on work performed under Research Project 1041-7 for the Electric Power Research Institute Energy Management and Utilization Division. REFERENCES 1. ORNI_/ENG/TM-13, V1 and V2, Low BTU coal gasifica-
tion, H. F. Hartman, J. P. Belk and D. E. Reagan,prepared for DOE (November 1978). 2. Fossil Energy Program Report, Vol. II, Coal Gasification, R. C. Seamans and P. G. White, Energy Research and Development Administration (1976).
Int. J. Hydrogen Energy, Vol. 8, No. 7, pp. 499--508,1983. Printed in Great Britain.
C O A L GAS AS A F E E D F U E L F O R P H O S P H O R I C ACID F U E L CELL P O W E R PLANTS B. R. KRASICKIand B. L. PIERCE Westinghouse Electric Corporation, Advanced Energy Systems Division, Pittsburgh, PA 15236. U.S.A.
(Received for publication 7 January 1983) Abstract--Westinghouse Electric Corporation has assessed the effects of a number of coal gasification systems and their gas compositions on a 7.5 MW(e) dc Phosphoric Acid Fuel Cell (PAFC) power plant. Both low and medium BTU synthesis gases were considered from various promising gasification processes. Degree of development or commercialization, technical complexity, availability and coal restrictions were taken into account. System studies performed on the 7.5 MW(,) dc PAFC power plant for nonintegrated and integrated fuel conditioning systems are discussed for the various gasification processes. In all cases coal gas was assumed to be purchased "over-the-fence". Representative characteristics for the derived coal gases and PAFC system performance data are presented. The direct capital costs of the PAFC power plant are evaluated for each system.
INTRODUCTION Westinghouse Electric Corporation has been working on various fuel cell technologies. Studies have shown that the phosphoric acid fuel cell (PAFC) is near term for both utility on-site power generation and commercial co-generation. The fuel cell selected for development by Westinghouse is a Gas Cooled concept originated by Energy Research Corporation (ERC). Westinghouse and E R C have formal working agreements whereby Westinghouse has access to E R C technology. The Gas Cooled fuel cell is efficient, reliable and cost effective. To facilitate the development of a commercially viable P A F C power plant, Westinghouse had undertaken a study (EPRI Contract RP1041-7) to assess the effects of alternate fuels on the performance and economics of candidate P A F C power plants. The hydrogen-rich fuel that feeds the fuel cell can be processed from almost any organic-based chemical. One of the candidate fuels considered was coal gas. A study was made for coal gasification systems, their product gas compositions and their applicability to Phosphoric Acid Fuel Cell (PAFC) power plants. The information gathered on the various coal gasification processes was for both low and medium BTU gas and specifically includes the detailed surveys conducted by O R N L and E R D A [1, 2]. Over 100 gasification processes were considered in the O R N L study. The most promising systems were selected by O R N L taking into account such major categories as degree of development or commercialization, technical complexity, availability and coal restrictions. These processes were grouped according to their generic gasifier type such as fixed, fluidized, entrained and molten. Additional cleanup would be required prior to processing in the fuel cell plant to remove sulfur and other impurities. DISCUSSION Twenty-one promising coal gasifiers are listed in 499
Table 1 (abstracted from [1, 2]). These processes by no means represent all the viable gasification systems available to date. They do, however, represent a generic group of gasifier bed types such as fixed, fluidized, entrained and molten for potential application with a Phosphoric Acid Fuel Cell (PAFC) power plant. The gas composition for each system is for oxygen and/or air blown cases. These compositions are the best average values representing the product coal gas out of the gasification plant. Additional cleanup is required in some cases to remove sulfur and other impurities prior to fuel conditioning in the P A F C plant. These impurities in excess of several ppm are detrimental to the performance and life of the fuel conditioner and fuel cell systems. Typical characteristics for the various coal derived gases are summarized in Table 2. The total hydrogen concentration out of the P A F C fuel conditioner was calculated for each of the gasification systems. A 1.3 water/carbon monoxide mole ratio was assumed for the fuel shift reaction. The additional 30 volume % water is used to reduce the carbon monoxide to acceptable levels and to minimize the potential for carbonization in the shift reactor catalyst bed. For the oxygen blown gasifier cases, the average hydrogen concentration after the shift reaction is approx. 50 mole %. The air blown cases were somewhat lower due to nitrogen inerting but still acceptable for P A F C feed. The average hydrogen concentration for the air blown cases is 30 mole %. For both the oxygen and air blown cases, the hydrogen feed concentration to the fuel cell (after shift) appears to be independent of the type of gasifier and the kind of coal used. It is important to have a sufficient concentration of hydrogen in the fuel cell feed gas. This can be seen in Fig. 1 which shows the effect of reduced hydrogen on the overall fuel cell voltage. For the oxygen blown gasifiers the voltage loss is 25 ~ 35 mV compared to pure hydrogen for fuel utilizations of 0.8 and 0.9, respectively. When compared to the air blown gasifiers
15.0
38.4
17.0
. 50~66
270 ~ 305
120 --~ 168
~280
175 ~ 205
300 ---, 350
~150
WellmanGalusha WellmanGalusha
Fixed bed
Fluidized bed Fluidized bed
Fluidized bed Fluidized bed Fluidized bed Fluidized bed
Fluidized bed
Fluidized bed
WoodallDuckham/Gas Integrale Battelle agglomerating burner Battelle agglomerating burner BCR TRI-gas
Fixed bed
02
Air
C O gas
CO gas
CO2 acceptor Air
~335
57.9
58.8
~380
CO2 acceptor
02
15.8
~150
39.4
B C R TRI-gas Air
02
Air
Oz
Air
WoodalP 02 Duckham/Gas Integrale
Air
Fixed bed
Fixed bed
.
~150
Lurgi, dry ash Air
Fixed bed
O2
24.0
285 --~ 300
Lurgi, dry ash 02
.
Fixed bed
~150
Air
British Gas Lurgi slag
27.8
Fixed bed
370 ~ 380
H2
02
Reactants
British Gas Lurgi slag
Process
BTU/SCF HVV
Fixed bed
Reactor type
.
.
.
31.2
15.5
31.2
0~39
.
28.3
37.5
28.6
16.0
16.9
60.6
CO
.
.
.
4.0
13.7
--
1 ~6
2.7
3.5
2.7
.
4.0
9.0
.
7.6
CH4
Gas compositions (mole %)
.
4.5
18.0
3.4
14.0
31.5
6.6
9.1
0.5
3~28
.
2.6
CO2
.
.
2.9
0
0.3
52.3
47.2
0.3
0.2
2.2
0.4
41.0
1.6
50.3
.
1.0
Nz(Ar)
--
1.0
0.8
--
H2S(COS)
111. No. 6
Bituminous coal Lignite
63.4
61.8
33.4
33.1
Bituminous
Bituminous type coal
51.0
Bituminous
33.1
31.8
Commercial; outside U.S.A.
46.2
Pilot unit shutdown 1978; approx. 65% N2 removed from composition stream P D U unit in U.S.A.; no 02 information in the literature P D U unit in U.S.A.; no reformer required Work completed in U.S.A.; not commercial; need reformer W o r k completed in U.S.A.; not commercial; no information available for air blown case Pilot plant in England; needs reformed Pilot plant in England; needs reformed
O2 tests p e r f o r m e d - - n o data reported Concentration of methane is low enough that no reformer is needed; 12 in U.S.A.; commercial units available Commercial; outside U.S.A.; concentrations reported are after scrubbing; methane concentration such may require a reformer As above; methane concentration is low enough that a reformer may not be required Pilot plant O2 runs; no data reported in literature
Commercial; outside U.S.A.
49.4
Comments Near-commercial; outside U.S.A.; molten slag; methane conc. high; will need reformer No data reported
Bituminous
Pittsburgh No. 8; III. No. 6; bituminous; nearly all coals Pittsburgh No. 8; III, No. 6; bituminous; nearly all coals Anthracite
Donisthorpe, nearly all coals
Coal type
H2 % after shift 1.3 H 2 0 / C O
T a b l e 1. P r o m i s i n g c o a l g a s i f i c a t i o n s y s t e m s a n d t h e i r p r o d u c t g a s ( r e p r e s e n t a t i v e c o m p o s i t i o n s )
Z Z7
>
>
7~
~154 ~285
Westinghouse O:
260 --, 290
Winkler
Entrained flow Molten bath
02
Combustion engineering Combustion engineering FosterWheeler FosterWheeler KoppersTotzek KoppersTotzek Texaco
Air
02
Texaco
Rockwell International
02
~250 (279) 39.0 (35,8)
36.0
=290
02
Air
14.2
10.6
~160
~120
Air
02
Air
Air
BI-gas
32.0
~356
02
Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow
23.3
8.4
~150
Air
37.6 (44.6)
52.5
29.1
24.7
29.3
65.3
27.9
~300
O2
Babcock and Wilcox Babcock and Wilcox Bl-gas
Entrained flow Entrained flow Entrained flow
22.0
14.0
Air
Winkler
Fluidized bed ~150
•9.2
51.1
49.1
19.6
16.1
10.1
13.2
23.8
48.2
14.4
25.6
29.8
17.5
41.4
21.5
32.3
30.2
35.3
02
120 ~ 150
Westinghouse Air
Fluidized bed Fluidized bed
~350
Westinghouse 0 2
Fluidized bed
~320
0 2
Air
U-gas
U-gas
~150
~355
Fluidized bed Fluidized bed Fluidized bed
Air
02
Synthane
370
Synthane
Air
HY gas
02
Fluidized bed
Fluidized bed Fluidized bed
Table 1 (continued) Fluidized H Y gas bed
(1.0)
0.5
3.4
15.7
1.0
1.8
2.7
10.2
3.2
3.4
35.8
5.6
15.0
18.6
20.8 (18.o)
10.0
3.3
4.0
21.5
4.6
5.0
7.0
13.8
9.3
9.9
17.2
9.9
5.9
17.9
36.2
24.5
1.5 (0.1)
0.4
0.7
0.5
0.8
0.2
0.6
0.1
L7
0.5
0.7
0.2
0.7
1.6
1.2
Subbituminous Bituminous
111. No. 6
111. N o . 6
Bituminous subbituminous
0.6
1.1
49.3
60.4
0.7
63,5
1.2
56.0
0.9
Eastern; Western; any coal
Eastern coal
I11. No. 6
Pittsburgh seam
Pittsburgh No. 8 Pittsburgh No. 8 Pittsburgh seam
Subbituminous
Lignite
0.3 Pittsburgh seam; Eastern coal 0.5 Pittsburgh seam; Eastern coal 54.3 Eastern coal
43.5
0.6
43.5
--
0.1
51.4 (51.0)
52.6
31.4
26.7
44.4
24.3
50.4
28.0
51.3
26.9
46.1
48.2
29.6
47.6
27.9
38.8
41.2
Commercial units worldwide but outside U.S.A.; methane l o w - no reformer needed Commercial units worldwide but outside U.S.A.; methane l o w - no reformer needed Near-commercial; U . S . A . ; no reformer--methane content low Near-commercial; U . S . A . ; no r e f o r m e r - - m e t h a n e content low Pilot plant operation; U . S . A . ; high methane c o n c e n t r a t i o n - needs reformed No data in the literature for air blown gasifier No data in the literature for oxygen blown gasifier P D U system; U.S.A.; no reformer required No data in the literature for oxygen blown gasifier Pilot facility in U.S.A.; may need reformer Commercial worldwide outside U.S.A.; no reformer required No data found in literature search for air blown case Near-commercial; U.S.A.; no reforming (data provided by the Fuel Cell User's group) No information in the literature for air blown case No information in the literature for 02 blown case
Proposed commercial compositions; high methane needs reformer PDU U.S.A.; no reformer
Pilot plant in U.S.A.; very high methane Pilot plant in U.S.A.; needs r e f o r m e r - - m e t h a n e concentration too high Pilot plant in U.S.A., needs r e f o r m e r - - m e t h a n e concentration too high Pilot plant in U.S.A.; very high methane; needs reformer Pilot plant in U.S.A.; may need reformer P D U U.S.A.; may need reformer
Pilot plant in U.S.A.; very high methane; needs reformer
O
O
"
fJ~
t-'
502
B. R. KRASICKI AND B. L. PIERCE Table 2. Representative characteristics for coal derived gas* Medium BTU Low BTU Low methane Low methane
05
" ~
o ~o ~= ~ ~= =~=~
~o
0
~, 0
0
0
0
P'.O
Composition
(vol. %)
~=~ ~
H2 CO CH4 COz
:''
H2S N2 Heating value (BTU/SFC)
I
8
I
I
I
<::5
I
I
37.7 50.4 0.3 10.1 0.1 1.4 250
15.0 28.6 2.7 3.4 -50.3 150
26.6 51.1 10.2 9.9 1.7 0.5 350
* The Westinghouse fluidized bed gasifier is a commercially viable system that can be tailored to produce a range of medium or low BTU gas having either low or high methane content.
I
(37---> 45 mV), the average differential voltage loss between the two cases is approx. 12 mV. This amounts to 1.8% reduction in overall fuel cell performance for air vs oxygen blown coal gas utilization assuming an operating voltage of 0.66 V/cell. For oxygen blown coal gas, the degradation in overall fuel cell performance compared to pure hydrogen feed is approx. 4%. The air blown case degradation is approx. 6%. (Relatively pure hydrogen feed could possibly be obtained using hydrogen separators in place of shift converters.) This means that the fuel cell system needs 4---~6% more fuel feed gas to obtain the same voltage output compared to pure hydrogen feed. In order to utilize this increased fuel flow and maintain a fixed total voltage, the number of fuel cells will have
<
"
Medium BTU High methane
I
',q.
N2 INLET MOLE FRACTION 0.0
r'G,
~
-:
o
0.6
i! /,/
0.8
1.0
/// o.,,2
o
©
8 <0 = oo .~ =N - ~
0.4
-10
.30
=©
0.2
-~ ~ "~ -~
~=
-70 II
r
Fig. 1. PAFC voltage loss due to decrease of hydrogen concentration in the anode feed gas.
COAL GASIFICATION SYSTEMS
FUEL ~
~'~(~VENT
503
]
~ STEAGM 0
AIR
..Y.°
"'
.......
llJlllJ!ljl ANODE COOLING CA~MO~[ P L LL
J
.®
¢01~*14[ $$~A
"rORlqh+t
-
~
+
-
lllt
'
W ...... o,
r ...... , -l.--/++k.~
g++
P:'+,+:~t,, L .....a..j
~
'tOW l r l m TI~IATI~EI+I
~
|
+ "
m [
°
* corn
I~O£.IN~
STO~AS[L
TRE,+~'[~+
Fig. 2. Coal gas flow schematic (nonintegrated fuel conditioning system).
Table 3. Performance summary coal gas fueled nonintegrated system Gross dc electrical output (kW) Gross ac electrical output (kW) Turbogenerator ac power (kW) Gross ac power (kW) Parasitic losses (kW) Pumps Fans (cooling tower) Vacuum pump Air compressor and dryer Controls Net electrical ac output (kW) Input energy (HHV) BTU/h Overall plant efficiency Heat rate (BTU/kWh)
7500 7200 1178 8378 23 210 3 1 15 8126 74.03 x 106 0.375 9110
to be increased. This will result in approx, a 4 ~ 6% increase in direct capital cost of the fuel cell system over a pure hydrogen feed. The product gas from coal gasification systems has a significant concentration of carbon monoxide. The carbon monoxide "results in some performance loss" to the PAFC if the concentration is greater than about 1-4 volume %. Therefore, the product coal gas carbon monoxide is shifted by adding steam to produce carbon dioxide and hydrogen. A n oxygen blown entrained flow gasifier product gas was selected as representative of a medium BTU, low methane gas, and was used as a basis for this study. This gas was typical in composition of medium BTU gas from any type of coal where the desired methane concentration was low. Figure 2 shows a conceptual coal gas flow schematic
B. R . K R A S I C K I
504
A N D B . L. P I E R C E
T a b l e 4. S t a t e p o i n t s f o r c o a l g a s n o n i n t e g r a t e d fuel c o n d i t i o n i n g s y s t e m
Station
Temp (°F)
Pressure (psia)
H2
H20
CO
CO2
02
1 2 3 4 5 8 10 11 12 13 14 15 16 17
350 350 1754 1200 360 80 135 280 277 352 269 249 269 138
--------50 50 49 30 49 15
0.482 0.156 ---0.39 ---------
0.01 0.015 ---0.376 . . ---. ---
0.365 0.593 0.434 0.434 0.434 0.208 . . . . ---. . ---
--0.007 0.007 0.007 -. . 0.100 0.094 0.094 . 0.094 0.094
0.004 0.006 0.295 0.295 0.295 0.006 . . . . 0.713 0.709 0.709 . . 0.709 0.709
18
96
15
--
--
--
0.106
0.798
19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 35 37 38 39 40 41 42 43
96 249 141 135 80 80 348 269 273 135 136 106 244 80 100 135 600 521 820 452 436 350 587
0.128 0.207 0.264 0.264 0.264 -1.000 1.000 0.187 0.197 0.197 1.000 0.197 0.175g 0.0221 0.054g 0.0421 1.000 1.000 1.000 1.000 0.010 0.010 0.010 0.197 0.197 1.000 1.000 1.000 1.000 0.010 0.010 1.000 -0.219 0.078 0.078 0.244 0.244 0.128
. . . . 0.253 0.208 0.208 0.094 0.094 . . . . 0.208 0.208 . --------
. . . . 0.782 0.782 0.782 0.709 0.709 . . . . 0.782 0.782 . 0.006 0.005 0.005 0.005 0.004 0.004 0.004
15 30 3 3 14.6 14.6 50 49 50 30 3 15 3 15 15 ---------
Mole fraction
----------------0.39 0.305 0.44 0.44 0.365 0.365 0.492
. . . . -----. . . . --. 0.376 0.294 0.15 0.15 0.125 0.125 0.010
where the fuel conditioning s y s t e m is n o t i n t e g r a t e d with the balance of plant. Since the methane concent r a t i o n is l o w , t h e m e t h a n e w i l l a c t a s a n i n e r t i n t h e fuel cell. Reforming o f t h e c o a l g a s is t h e r e f o r e n o t r e q u i r e d . T h e f u e l u t i l i z a t i o n i n t h e f u e l c e l l is a s s u m e d to be 80% which produces an exhaust fuel mixture that h a s 1 5 . 9 v o l u m e % h y d r o g e n . W h e n t h i s e x h a u s t g a s is mixed with compressed air at a stoichiometric ratio of 1.1, the resulting mixture will burn without the use of a catalytic combustion chamber. The flame temperature w i t h t h i s m i x t u r e is a b o u t 1 7 5 0 ° F . T h e h o t g a s is t h e n expanded through a turbine, which drives an ac generator and the air compressor. The turbine exhaust at 1 2 0 0 ° F is t h e n c o o l e d i n a l o w p r e s s u r e s t e a m g e n e r a t o r t o 3 6 0 ° F . S t e a m is a l s o g e n e r a t e d in the exothermic
. . . .
. . . . ------
. . . .
. . . . ---
.
. 0.208 0.162 0.303 0.303 0.249 0.249 0.365
Flowrate
N2
H2S
CH4
(lb/h)
0.01 0.015 ---0.015
0.003 0.005 ---0.005
----
----
---
---
24320 23395 34685 34685 34685 16487 15718 9986 1103350 1104190 1104190 240 65160 65160
--
--
60190
. . . . ------
------
---
---
0.015 0.012 0.012 0.012 0.010 0.010 0.010
0.005 0.004 0.004 0.004 0.003 0.003 0.003
. . . .
.
4970 24110 22610 24110 12720 64320 64320 1039030 1039030 28930 773930 773930 1500 4.8 × 106 4.8 × 106 5732 16487 20357 20357 20357 24320 24320 24320
shift converter and the anode gas cooler. These three heat exchangers produce more steam than required for the fuel conditioning reaction. T h e e x c e s s s t e a m is directed to the steam turbine. The conceptual coal gas fueled PAFC plant performa n c e is s u m m a r i z e d in Table 3 for a nonintegrated fuel conditioning system. The gross ac output comes from two sources, the fuel cell and the anode side turbogenerator. The net electrical output for this configura t i o n is s i g n i f i c a n t l y g r e a t e r t h a n t h o s e P A F C p l a n t s that would require reforming the fuel feed. The heat r a t e f o r t h i s c a s e is 9 1 1 0 B T U / k W h with a dry cooling tower. The state points for this case (Fig. 2) are given i n T a b l e 4. O n e o f t h e d e s i g n f e a t u r e s o f t h e n o n i n t e g r a t e d P A F C d e s i g n is t h a t t h e f u e l c o n d i t i o n i n g s y s t e m
COAL GASIFICATION SYSTEMS
505
CO 2 VENT
® .P
@
FUEL
®
@ @
'
I
T II ~!1
FUEL CELLS Q
l
'DSTEAM COMPRESSOR AIR TURBINE AIR
C(RCULATOR
)
IACT
~
CON.
®
,,. v
COOLING
Fig. 3. Coal gas flow schematic (integrated fuel conditioning system).
B. R. K R A S I C K I A N D B. L. P I E R C E
506
Table 5. Performance summary coal gas integrated system Gross dc electrical output (kW) Gross ac electrical output (kW) Parasitic losses (kW) Pumps Fans (cooling tower) Vacuum pump Air compressor and dryer Controls Net electrical ac output (kW) Input energy ( H H V ) BT U/h Overall plant efficiency Heat rate (BTU/kWh)* * Note that inefficiency.
this
does
not
7500 7200 23 205 3 1 15 6953 59.22 × 106 0.40 8520 include
coal
gasification
effectively o p e r a t e s i n d e p e n d e n t of the fuel cell system. Another conceptual schematic of a coal gas fueled p l a n t is s h o w n i n F i g. 3. T h i s d e s i g n i n t e g r a t e s t h e f u e l conditioning system with the PAFC plant. Here the h y d r o g e n c o n t a i n i n g a n o d e e x h a u s t is u s e d m o r e e f f e c t i v e l y i n t h e f u e l c e l l t o o b t a i n h i g h P A F C p l a n t effic i e n c i e s . T h e g a s is p a s s e d t h r o u g h a p u r i f i c a t i o n s y s t e m w h e r e i m p u r i t i e s such as c a r b o n m o n o x i d e , c a r b o n dioxide, methane and nitrogen are absorbed and hydrogen w i t h p u r i f y o f o v e r 9 9 . 9 9 % is o b t a i n e d . It s h o u l d b e n o t e d t h a t s u c h a h i g h d e g r e e o f h y d r o g e n p u r i t y is n o t a r e q u i r e m e n t for the fuel cell p e r f o r m a n c e . A s i m p l e r B e n f i e l d p r o c e s s c o u l d h a v e b e e n u s e d as a r e p r e s e n tative system.
Table 6. State points coal gas integrated system
Station
Temp. (°F)
Pressure (psia)
Mole fraction CO2 O:
H2
H20
CO
0.114 0.200 --
0.010 0.018 0.376
0.330 0.581 0.208
---
------
------
0.100 0.094 0.094 0.094 0.094
--
--
1 2 8
350 350 80
50 50 80
0.540 0.190 0.390
12 13 14 16 17
277 352 269 269 138
50 50 49 49 15
------
18
96
15
--
19 21 22 24 25 26 27 29 30 32 33 37 38 39 40 41 42 43 45 47 48 49 50 51 52
96 141 135 80 348 269 273 135 105 80 100 600 483 725 419 390 350 558 280 249 135 280 250 280 280
15 3 3 15 50 49 50 3 15 15 15 105 85 85 84 83 82 81 49 30 15 49 45 49 49
-----------0.396 0.371 0.492 0.492 0.441 0.441 0.540 ----0.479 ---
0.187 0.197 0.197 0.197 0.175g 0.0221 0.054g 0.0421 1.000 1.000 1.000 0.010 0.010 0.197 0.197 1.000 1.000 0.010 0.010 -0.242 0.122 0.122 0.212 0.212 0.114 1.000 1.000 0.173 1.000 0.506 1.000 1.000
. . . ----. . --0.382 0.242 0.121 0.121 0.108 0.108 0.010 . . -. -. .
. . . -----
--0.211 0.138 0.258 0.258 0.232 0.232 0.330 . . 0.827 . 0.015 . .
CH4
0.003 0.006 0.006 0.713 0,709 0.709 0.709 0.709
0.003 0.005 0.005 CH4 0.015 H2S ------
0.106
0.798
--
. . . 0.208 0.208 0.094 0.094 . . 0.208 0.208 -------. . -. -. .
. . . 0.782 0.782 0.709 0.709 . . 0.782 0.782 0.006 0.004 0.004 0.004 0.004 0.004 0.003 . . -. -. .
--
. . .
. .
N2
. .
. . . . .
-----
--0.005 0.003 0.003 0.003 0.003 0.003 0.003
---
Flowrate (lb/h) 19513 18581 13212 1103350 1104190 1104190 65160 65160 59500 5660 4934 4934 64320 64320 1039 030 1039030 167685 167685 1.0394 X 1 0 6 1.0394 × 1 0 6 12894 17504 17504 17504 19513 19513 19513 1998 17121 16849 2020 2603 2009 2009
COAL GASIFICATION SYSTEMS
507
Table 7. Coal gas prototype 8.10 MW¢ ac PAFC plant nonintegrated direct capital cost--1980 basis (thousands of dollars) Account No.*
$1000"~
341--Structures and improvements 342--Fuel handling and processing~ Fuel handling Fuel processing 343---Rotating equipment auxiliaries Gas turbine/generator system Steam turbine/expander Condenser system Separator system Cooling tower Air compressor system Air filter/silencer system Cathode exhaust gas circulator Miscellaneous auxiliaries 344---Electrical generating system Low pressure boiler system Recirculation ducts Fuel cell System 345--Accessory electric equipment Power conversion system Instrumentation and control DAS system Diesel generator system 346--Other miscellaneous power plant equipment 353---Station equipment Main transformer Total direct capital costt§ (land not included)
163 2171 64 2107 1074 262 177 32 22 133 295 2 98 53 4067 96 38 3933 2455 1712 390 245 108 265. 548 548 $10743 ($1326/kW)1[
* Federal Power Commission Uniform Systems of Accounts for Public Utilities. t EPRI Technical Assessment Guide. ~: Cost of initial catalyst is included in fuel processor cost (approx. 200 K). The fuel to the PAFC plant is commercially available medium BTU coal gas with low methane concentration. § R&D, G&A and fee (25%) are included. 1tBased on ac power to utility grid, the cost per kW does not include the coal gasifier. The fuel is assumed to be available over-the-fence.
The carbon dioxide removal system allows almost all of the hydrogen produced to be consumed in the fuel cell. The system also reduces the steam requirements for the shift reaction since the stream returning from the carbon dioxide removal system has high concentrations of both hydrogen and water vapor. A performance summary for the coal gas integrated case is given in Table 5. The state points for this concept (Fig. 3) are given in Table 6. A summary of direct capital cost for the two coal gas cases is presented in Tables 7 and 8. The significant cost differences between the two plants is in the Rotating
Equipment and Auxiliaries account. All other accounts remain virtually the same. In the auxiliaries to this account, the carbon dioxide cleanup system is expensive. The size and cost for cleanup was based on a commercially available potassium carbonate system designed for removing carbon dioxide from stack gases. Other gas purification systems should be considered to reduce overall cost. Preliminary evaluations to data indicate that a water scrubbing system may work but more detailed studies are needed to verify performance (i.e. sufficient carbon dioxide removal capability, system size and capital cost).
508
B. R. KRASICKI AND B. L. PIERCE Table 8. Coal gas prototype 6.96 MWe ac PAFC plant integrated direct capital cost--1980 dollars (thousands of dollars) Account No. *
$1000~
341--Structures and improvements 342--Fuel handling and processing$ Fuel handling Fuel processing 343---Rotating equipment and auxiliaries CO2 scrubber system¶ Steam turbine/expander Condenser system Separator system Cooling tower Air compressor system Air filter/silencer system Cathode exhaust gas circulator Miscellaneous auxiliaries 344--Electrical generating system Low pressure boiler system Recirculation ducts Fuel cell system 345----Accessory electric equipment Power conversion system Instrumentation and control DAS system Diesel generator system 346---Other miscellaneous power plant equipment 353----Station equipment Main transformer Total direct capital costt§ (land no included)
163 2171 64 2107 3106 2294 177 32 22 133 295 2 98 53 4067 96 38 3933 2455 1712 390 245 108 265 548 548 $12~/75 ($1838/Kw)11
See Table 7 for key to footnote symbols. ¶ Sized and costed based on a commercial K2CO3System for COz removable from stack gases.
Acknowledgements--The material in this paper is based in part on work performed under Research Project 1041-7 for the Electric Power Research Institute Energy Management and Utilization Division. REFERENCES 1. ORNI_/ENG/TM-13, V1 and V2, Low BTU coal gasifica-
tion, H. F. Hartman, J. P. Belk and D. E. Reagan,prepared for DOE (November 1978). 2. Fossil Energy Program Report, Vol. II, Coal Gasification, R. C. Seamans and P. G. White, Energy Research and Development Administration (1976).