1
Production of Hydrogen and Electricity
from Coal with CO2 Capture
Princeton University: Tom Kreutz, Bob Williams,Rob Socolow
Politecnico di Milano: Paolo Chiesa, Giovanni Lozza
Presented at the 6th International Conference on Greenhouse Gas Control Technologies (GHGT-6)
September 30-October 4, 2002, Kyoto Japan
2
Princeton UniversityCarbon Mitigation Initiative (CMI)
CMI Carbon Capture Group:• Investigating the H2/Electricity Economy
Activities:
• H2/electricity production from fossil fuels
• H2 (and CO2) distribution
• H2 utilization (e.g. fuel cells, combustion)
• Princeton/Tsinghua collaboration on low emission energy technologies for China
3
Background and Motivation• Distributed energy use (transportation and heating) responsible for
~2/3 of global CO2 emissions
• CO2 capture, compression, dehydration, and pipeline transport from
distributed sources is very expensive.
• Low carbon energy carriers are needed: electricity and hydrogen.
• If CO2 sequestration is viable, fossil fuel decarbonization likely to be
the cheapest route to electricity and hydrogen for many decades.
• Coal is of great interest because it is:
• Plentiful. Resource ~ 500 years (vs. gas/oil: ~100 years).
• Inexpensive. 1-1.5 $/GJ HHV (vs. gas at 2.5+ $/GJ).
• Ubiquitous. Wide geographic distribution (vs. middle east).
• Clean?! Gasification, esp. with sequestration, produces little gaseous emissions and a chemically stable, vitreous ash.
• Example: China: extensive coal resources; little oil and gas. Potential for huge emissions of both criteria pollutants and greenhouse gases.
4
Generic Process: Coal to H2, Electricity, and CO2
• All work presented here is based on O2-blown, entrained flow, coal gasification (e.g. Texaco, E-Gas gasifiers).
GHGT-6 generic process figure (9-25-02)
CO-richraw syngas
H2 product (60 bar)
N2
H2- andCO2-richsyngasQuench +
scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
SupercriticalCO2 (150 bar)
Water-gas shift(WGS) reactors
CO + H2O <=> H2 + CO2
CO2drying andcompression
Hydrogencompression
Syngas cleanup,gas separation
Electricityproduction
Heat recovery,steam generation
H2-richsyngas
CO2
Electricpower
5
Process Modeling
• Heat and mass balances (around each system component) calculated using:
• Aspen Plus (commercial software), and
• GS (“Gas-Steam”, Politecnico di Milano)
• Membrane reactor performance calculated via custom Fortran code
• Component capital cost estimates taken from the literature, esp. Holt, et al. and EPRI reports on IGCC
• Benchmarking/calibration:• Economics of IGCC with carbon capture studied by numerous groups
• Used as a point of reference for performance and economics of our system
• Many capital-intensive components are common between IGCC electricity and H2 production systems (both conventional and membrane-based)
6
• Significant variation found in cost values, methodology, and depth of detail.
• Our cost model is a self-consistent set of values from the literature.
• Cost database is evolving; less reliable values removed; range is narrowing.
• Uncertainty shown above leads to an uncertainty of ±10-15% in H2 cost.
0
1
2
3
4
5
6
7
8
9
1 0
1 1
1 2
0 50 100 150 200
Capital Cost (MM$)
Simbeck
Holt
Doctor
Chiesa
Hendriks
Pruden
EPRI3,000-6,000 $/m2
Solids handlingASUO2 compressionGasifier & quenchWGS reactorMembrane reactorRaffinate turbineFGDH2 compressionHRSG, steam turb.CO2 compression
Scale (HHV):1.5 GW th
coal,1 GW th H2
Estimates of Overnight Component Capital Costs
7
Coal price (year 2020 EIA est.) 0.94 $/GJ (HHV)
Capacity factor 80%
Capital charge rate 15% per yr
Balance of plant (BOP) costs 23% of gasifier island (GI) capital
Engineering fees (EF) 15% of (GI+BOP)
Process/project contingency 15% of (GI+BOP+EF)
Plant lifetime* 25 yr
Construction time* 4 yr
Interest during construction (IDC) 16.0% of overnight capital**
O&M costs 4% of overnight capital per year
CO2 sequestration cost 5 $/mt CO2 (~0.5 $/GJ H2 HHV)
U.S. dollars valued in year 2001
Plant scale 1 GWth H2
* Used only in calculating the interest during construction and/or plant internal rate of return** Assuming a 10% real interest rate
Economic Assumptions
8
Benchmark: IGCC Electricity with CO2 Capture
• Cost: 5.6 ¢/kWh, efficiency: 38.4% (HHV). (70 bar gasifier, scale: 406 MWe)
GHGT-6 conv. electricity, CO2 seq. (9-25-02)
Saturatedsteam
CO-richraw syngas
N2 for (NOx control)
H2- andCO2-richsyngas
Heat recoverysteam generator
CO2-leanexhaust
gases
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
Steamturbine
Gas turbineAir
Turbineexhaust
SupercriticalCO2 to storage
CO2 drying +compression
High temp.WGS
reactor
Low temp.WGS
reactor
Lean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
H2-richsyngas
Syngasexpander
9
H2 Production: Add H2 Purification/Separation
• Replace syngas expander with PSA and purge gas compressor.
GHGT-6 conv. electricity, CO2 seq. (9-25-02-a)
Saturatedsteam
CO-richraw syngas
N2 for (NOx control)
H2- andCO2-richsyngas
Heat recoverysteam generator
CO2-leanexhaust
gases
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
Steamturbine
Gas turbineAir
Turbineexhaust
SupercriticalCO2 to storage
CO2 drying +compression
High temp.WGS
reactor
Low temp.WGS
reactor
Lean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
H2-richsyngas
Syngasexpander
10
Conventional H2 Production with CO2 Capture
• H2 cost: 7.1 $/GJ (HHV). (85% HRF, scale: 1 GWth H2 HHV, 3.0 ¢/kWh)
GHGT-6 conv. hydrogen, CO2 seq. (9-25-02)
Saturatedsteam
CO-richraw syngas
High purityH2 product
N2 for (NOx control)
H2- andCO2-richsyngas
Heat recoverysteam generator
CO2-leanexhaust
gases
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
Steamturbine
Gas turbineAir
Pressureswing
adsorption
Purgegas
Turbineexhaust
CO2 drying +compression
High temp.WGS
reactor
Low temp.WGS
reactor
Lean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
SupercriticalCO2 to storage
11
Capture (and Co-sequester) H2S with CO2
• Remove the traditional acid gas recovery (AGR) unit.
GHGT-6 conv. hydrogen, CO2 seq. (9-25-02-a)
Saturatedsteam
CO-richraw syngas
High purityH2 product
N2 for (NOx control)
H2- andCO2-richsyngas
Heat recoverysteam generator
CO2-leanexhaust
gases
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
Steamturbine
Gas turbineAir
Pressureswing
adsorption
Purgegas
Turbineexhaust
CO2 drying +compression
High temp.WGS
reactor
Low temp.WGS
reactor
Lean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
SupercriticalCO2 to storage
12
Conventional H2 Production with CO2/H2S Capture
• Resulting system is simpler and cheaper.
GHGT-6 conv. hydrogen, co-seq. (9-25-02).FH10
Saturatedsteam
CO-richraw syngas
High purityH2 product
N2 for (NOx control)
H2- andCO2-rich
syngas
Heat recoverysteam generator
CO2-leanexhaust
gases
High temp.WGS
reactor
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
Low temp.WGS
reactor
CO2/H2Sphysical
absorption
Solventregeneration
Lean/richsolvent
95%O2
Steamturbine
Gas turbineAir
Pressureswing
adsorption
Purgegas
Turbineexhaust
CO2 + H2Sto storage
CO2/H2Sdrying andcompression
13
Conventional H2 with Co-Sequestration of CO2
and Sulfur-bearing Species
• CO2 capture and sequestration lowers efficiency by ~3% and increases H2 cost by ~ 1.5 $/GJ.
(Cost of CO2 pipeline transport and disposal used here is 0.4-0.6 $/GJ.)
• Co-sequestration has potential to lower H2 cost by 0.25-0.75 $/GJ, depending on sulfur content of coal.
0
1
2
3
4
5
6
7
8
Conv. tech. base case
H2
Co
st
($/G
J H
HV
)
CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
14
Produce “Fuel Grade” H2 with CO2/H2S Capture
• Remove the PSA and gas turbine; smaller steam cycle.
GHGT-6 conv. hydrogen, co-seq. (9-25-02-a).FH10
Saturatedsteam
CO-richraw syngas
High purityH2 product
N2 for (NOx control)
H2- andCO2-rich
syngas
Heat recoverysteam generator
CO2-leanexhaust
gases
High temp.WGS
reactor
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
Low temp.WGS
reactor
CO2/H2Sphysical
absorption
Solventregeneration
Lean/richsolvent
95%O2
Steamturbine
Gas turbineAir
Pressureswing
adsorption
Purgegas
CO2 + H2Sto storage
CO2/H2Sdrying andcompression
15
“Fuel Grade” (~93% pure) H2 with CO2/H2S Capture
• Simpler, less expensive plant. No novel technology needed.
GHGT-6 Fuel grade H2, co-seq. (9-25-02)
Saturatedsteam
CO-richraw syngas Low purity
H2 product(~93% pure)
N2
H2- andCO2-rich
syngas
Heat recoverysteam generator
CO2-leanexhaust
gases
High temp.WGS
reactor
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
Low temp.WGS
reactor
CO2/H2Sphysical
absorption
Solventregeneration
Lean/richsolvent
95%O2
Steamturbine
CO2 + H2Sto storage
CO2/H2Sdrying andcompression
16
Production of “Fuel Grade” H2
• Reduced H2 purity yields a significant cost savings: 1.0-1.4 $/GJ.
• Fuel grade H2 will be more competitive with gas and oil in the heating sector, and
might be adequate for transportation (H2 ICEVs; barrier to PEM FCEVs?)
0
1
2
3
4
5
6
7
8
Conv. tech. base case Fuel grade H2
H2 C
os
t ($
/GJ
HH
V)
CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
17
Change H2-CO2 Gas Separation Scheme
• Use membrane to separate H2 from the syngas instead of CO2.
GHGT-6 conv. hydrogen, co-seq. (9-25-02-b)
Saturatedsteam
CO-richraw syngas
High purityH2 product
N2 for (NOx control)
H2- andCO2-rich
syngas
Heat recoverysteam generator
CO2-leanexhaust
gases
High temp.WGS
reactor
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
Low temp.WGS
reactor
CO2/H2Sphysical
absorption
Solventregeneration
Lean/richsolvent
95%O2
Steamturbine
Gas turbineAir
Pressureswing
adsorption
Purgegas
CO2 + H2Sto storage
CO2/H2Sdrying andcompression
18
H2 Separation Membrane Reactor System
• Employ a H2 permeable, thin film (10 m), 60/40% Pd/Cu (sulfur tolerant)
dense metallic membrane, configured as a WGS membrane reactor.
GHGT-6 uncooled turbine, co-seq. (9-25-02)
CO-richraw syngas
High purityH2 product
N2
H2- andCO2-rich
syngasHigh temp.WGS
reactor
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
Hydrogencompressor
Uncooledturbine
MembraneWGS
reactor
O2 (95% pure)
CO2 + SO2to storage
CO2/SO2drying andcompression
Catalyticcombustor
Water
Pure H2
Raffinate
19
Hydrogen Separation Membrane Reactor Concept
Membrane Reactor 4 1-7-02
Porous (optionally asymmetric) ceramic orstainless steel (SS) supporting substrate
Optional oxide layer (needed for metallicmembrane with SS substrate)
Catalyst pellets
Thin film membrane
Entering highpressure syngas
Exiting raffinate
Permeatinghydrogen
High pressure syngas
Shell-tube membrane module
Thin film membrane
Membrane Structure:
Low pressure hydrogen permeate
Porous substrate
Low pressurehydrogen permeate
• Alternative HSMR design: high pressure, WGS reaction, and membrane outside supporting tube, with H2 permeating to the interior of the tube
20
Typical Membrane Reactor Performance
• H2 Recovery Factor (HRF) = H2 recovered / (H2+CO) in syngas
• HRF increases with membrane area diminishing returns
• Membrane costs rise sharply above HRF~80-90% (no sweep gas)
0
5
10
15
20
25
0
20
40
60
80
100
0 5 10 15 20 25 30 35
H2 P
artia
l Pre
ssur
e (b
ar) H
2 Reco
very F
actor (%
)
Membrane Area (103 m2)
® ®
a)
0
10
20
30
40
50
60
70
0
10
20
30
40
50
60
70
0 20 40 60 80 100
Ave
rage
H2 F
lux
(kW
/m2)
Mem
brane M
aterial C
ost ($/kW)
H2 Recovery Factor (%)
®
®
b)
10 m thick Pd-40Cu membrane475 C; 1000 ppm H
2S; 67 bar syngas
21
System Parameter Variations
System Performance:- membrane reactor configuration
- membrane reactor operating temperature
- gasifier/system pressure
- hydrogen purity
- hydrogen backpressure
- hydrogen recovery factor (HRF)
- raffinate turbine technology (blade cooling vs. uncooled)
System Economics:- membrane reactor cost (and type)- by-product electricity value
- sulfur capture vs. sulfur + CO2 co-sequestration
22
Pd/Cu Membrane-Based H2 Separation
• Cost of H2 via Pd/Cu membrane very close to conventional technology.
0
1
2
3
4
5
6
7
8
Conv. tech. base case Fuel grade H2 Membrane base case
H2 C
os
t ($
/GJ
HH
V)
CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
est.
23
Oak Ridge Molecular Sieving Membrane- H2 Permeance Relative to 60/40 Pd/Cu -
0
10
20
30
40
50
60
70
1 10 100 1000
Upstream Pressure (bar)
H2 P
erm
eanc
e R
atio Hydrogen
backpressure(bar):
0
12
5
10
20
50
• Membrane permeance pressure dependence:
- ceramic: (Phigh – Plow) vs. metallic: (√Phigh – √Plow)
• Permeance increase up to factor of ~50 possible. Reduced purity.
24
• Preliminary economic comparison, using same membrane cost ($3,000/m2): H2 cost lower by ~0.5 $/GJ HHV (at
70 bar; more for 120 bar gasifier).
Ceramic Molecular Sieving Membrane
0
1
2
3
4
5
6
7
8
Conv. tech. basecase
Fuel grade H2 Membrane basecase
High permmembrane
H2
Co
st
($/G
J H
HV
)CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
est.est.
25
Conclusions
• Consistent framework for estimating the performance and cost of converting coal to H2 and electricity with CO2 sequestration.
• Investigated membrane-based vs. conventional H2 separation.
• Parametric investigation of membrane systems shows:
– H2 cost via 60/40 Pd/Cu membrane is comparable to that via conventional technology.
– High permeance microporous membranes offer modest cost reductions (~$0.6/GJ HHV), but with reduced H2 purity.
• High H2 purity is costly; “fuel grade” H2 can be produced with conventional technology at significantly lower cost (1.0-1.4 $/GJ).
• Co-sequestration lowers the cost of H2 (0.25-0.75 $/GJ HHV), and may provide other environmental benefits (Hg, etc.).
• We plan to extend methodology to study other feedstocks (petroleum residuals, natural gas, etc.) and novel technologies.
26
Back-up Slides...
27
Example of Disaggregated Cost of H2 Production system
(membrane system...change to conventional)...drop slide?
• 70 bar gasifier, 85% HRF, uncooled raffinate turbine, scale: 1 GWth H2 (HHV)
-1
0
1
2
3
4
5
6
7
Hyd
roge
n C
ost
($/G
J, H
HV
)CO2 Sequestration (5 $/mt CO2)
CO2 drying & compression
H2 compressor
Raffinate turbine
Membrane reactor
H.T. WGS reactor
Gasifier and quench
O2 separation & compression
Coal preparation & handling
Construction Interest (4 yr)
O&M (4% per year)
Coal (0.93 $/GJ, HHV)
Electricity credit (5.54 ¢/kWh)
Fig. D3Net cost: 6.6 $/GJ
Capital Charge Rate=15%
28
Membrane System with Cooled Raffinate Turbine
• Blade cooling enables higher TIT (1250 C vs. 850 C), and higher electrical conversion efficiency for raffinate stream. Requires much lower HRF (~60%).
GHGT-6 cooled turbine, co-seq. (9-25-02)
CO-richraw syngas
High purityH2 product
N2
H2- andCO2-rich
syngasHigh temp.WGS
reactor
Quench +scrubber
Air Airseparation
unit
Coalslurry O2-blown
coalgasifier
95%O2
Hydrogencompressor
Cooledturbine
MembraneWGS
reactor
O2 (95% pure) CO2 + SO2to storage
CO2/SO2drying andcompression
Catalyticcombustor
Water
Pure H2
RaffinateSteam(for bladecooling)
Steam(for bladecooling)
Uncooledexpander
29
• Cooled turbine (low HRF) system has poor overall efficiency and economics (at low co-product
electricity prices, 3 c/kWh)
0
1
2
3
4
5
6
7
8
9
Conv. tech. basecase
Fuel grade H2 Membrane basecase
Cooled raf.turbine
H2
Co
st
($/G
J H
HV
)CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
est. est.
Membrane System with Cooled Raffinate Turbine
30
The Case for Hydrogen
~1/3 Central station electricityCentralized(large scale)
~1/3 Transportation Distributed
~1/3 Other (industrial & residential heating)
Distributed
• Stabilizing atmospheric CO2 at e.g. 500 ppmv will require deep
reductions, probably in all 3 sectors.
• Capture, compression, dehydration, and pipeline transport of CO2 from
distributed sources is extremely expensive.
• Distributed energy consumption with low CO2 emissions requires low
carbon energy carriers, electricity and hydrogen.
• H2 likely to play a key role in both the transportation and heating
sectors. Relative to electricity:
• Higher overall efficiency of production & use
• Easier (less costly) storage
31
The Case for Coal
• Abundance of low quality feedstocks (coal, heavy oils, tar sands, etc.) relative to conventional oil and natural gas
• Low feedstock cost relative to natural gas
• China is dependent on coal; US expected to continue being large coal user is near-zero emission option for coal feasible?
• Air pollution concerns likely to drive coal gasification for power generation—springboard for producing H2 from coal
• Sulfur, other criteria pollutants, toxics (e.g, Hg) pose major challenges in H2/electricity manufacture; gasification facilitates low emissions
• Residual environmental, health, and safety issues of coal mining and other low-quality feedstocks
32
Some Interesting Results
Description CO2 ventingPure CO2
sequestrationCO2-S
Co-seq.
eff (%) $/GJ eff (%) $/GJ $/GJ
Conv. Tech.
Base case 71.6 5.6 69.4 7.1 6.8
Fuel grade H2 75.5 4.8 74.7 6.1 5.8
HSMR-Based System
Base case 75 5.3 69.1 7.2 7.0
Cooled raf. turbine 66 4.9 57.8 8.5 8.1
High perm HSMR 76 4.7 69.9 6.6 6.4
• Sequestration lowers efficiency and increases costs• Co-sequestration has potential to lower costs
• H2 purity comes at a significant cost. Fuel grade (~94% H2) can be produced at a significantly lower cost in a system with significantly lower capital cost.
• 60/40% Pd/Cu membrane system not obviously better than conventional.• Cooled turbine (low HRF) system has poor efficiency and economics (at low co-
product electricity prices, 3 c/kWh)• High permeance membrane (at 70 bar) might yield only modest improvements.
33
Effect of HSMR Configuration
• In this system, with an upstream WGS reactor, a membrane reactor not obviously necessary for good system performance.
0
10
20
30
40
50
60
70
0 20 40 60 80 100
H2 Recovery Factor (%)
Avg
. H
2 F
lux
(kW
/m2,
HH
V)
0
20
40
60
80
100
120
140
HS
MR
Co
st ($/kW
HH
V)HT-WGS+HSMR
HT-WGS+HSM
HSMR
34
• Increasing pressure can significantly reduce cost of decarbonized hydrogen
• Cooled raffinate turbine typically requires low HRF to realize high TIT
• Uncooled turbine/high H2 recovery: greater promise, esp. at low elec. prices
Hydrogen Cost vs Gasifier Pressure
6.0
6.5
7.0
7.5
8.0
8.5
40 50 60 70 80 90 100 110 120 130
Gasifier Pressure (bar)
Hyd
roge
n C
ost
($/G
J H
HV
)
Fig. H2
85% HRF
75% HRF
5.5
4.0
3.6
3.0
ElectricityPrice
(¢/kWh):
Lines:Cooled turbineat ~60% HRF
Single pointsat 70 bar:uncooled turbine
35
Cost of H2 Compression and HSMR
vs. H2 Backpressure
• Broad cost minimum seen here (not always) at low H2 backpressure
0.0
0.5
1.0
1.5
2.0
0 1 2 3 4 5
H2 Backpressure (bar)
Cos
t ($
/GJ
H2,
HH
V)
Fig. G4b
Sum
Membrane capital
Compressorpower
Compressorcapital4
3
Number of compressor
stages:
Cost Minimum
36
Effects of H2 Recovery and Electricity Price
• Efficiency rises monotonically with increasing HRF• Low prices for co-product electricity favors production of H2 over electricity
• At high electricity prices, H2 cost is insensitive to HRF in the 60-90% range
0
20
40
60
80
40 50 60 70 80 90
H2 Recovery Factor (%)
Effe
ctiv
e E
ffici
ency
(%
, HH
V)
6
7
8
9
10
Hydrogen C
ost ($/GJ, H
HV
)
Fig. A4e
3.0
5.8
Electricityprice
(¢/kWh):
5.5
37
Effects of H2 Recovery Factor and HSMR Cost
• A five-fold variation in HSMR cost alters the H2 cost by ~$1/GJ (HHV)
• H2 costs exhibit a broad minimum with respect to HRF (from ~60-90%)
• As HSMR costs decrease, optimal HRF increases (long green arrow)
5
6
7
8
9
40 50 60 70 80 90
H2 Recovery Factor (%)
Hyd
rog
en
Co
st (
$/G
J, H
HV
)
0
5
10
15
20
Hydrogen-to-E
lectricity Ratio
Fig. Ab
10,000
1,000
3,000
5,000
HSMR cost
($/m2):
Scale: 1 GWth H2 at 85% HRF
Electricity: 5.54 ¢/kWh (50 $/tC)
38
• 3.6 ¢/kWh: electricity from GTCC fired by natural gas (cost: 3.4 $/GJ HHV)
• 5.5 ¢/kWh: breakeven price for electricity from coal IGCC - at carbon tax of $50/tC - when CO2 sequestration becomes competitive with CO2 venting
Effects of Electricity Price and Turbine Technology
5.0
6.0
7.0
8.0
9.0
10.0
2 3 4 5 6 7
Electricity Price (¢/kWh)
Hyd
roge
n C
ost
($/G
J H
HV
)
Fig. O
Scale: 1.5 GW th coal
(= 1 GWth H2at 85% HRF)70 bar gasifier
Uncooled raffinate turbine75% H2 recovery
Uncooled raffinate turbine85% H2 recovery
Cooled raffinate turbine59% H2 recovery
3.6 5.5