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In Pursuit of a H2 Economy for Mitigating Climate Change ... · Economics of H 2 from Coal with...
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In Pursuit of a H2 Economy for Mitigating Climate Change...
How Important isAdvancing the State-of-the-Art inH2 Production from Fossil Fuels?
Tom KreutzPrinceton Environmental Institute
Princeton University
Presented at the GCEP Energy Workshop:“Carbon-Free Production of Hydrogen”
April 26, 2004, Stanford University, Palo Alto, California
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Outline of Talk
• Overview of our work on production of carbon-free H2
and electricity from fossil fuels (primarily coal)
• Putting our work in perspective
• Areas of interest for future work
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The Carbon Mitigation Initiative (CMI)at Princeton University, 2001-2010
• CMI Project Areas:
- Carbon capture (Kreutz, Larson, Ogden, Socolow, Williams)
- Carbon storage (Celia)
- Carbon science (Pacala, Sarmiento, GFDL)
- Carbon policy (Bradford, Oppenheimer)
- Integration (Socolow, Pacala)
• Funding: 15.1$ from BP, 5 M$ from Ford
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World Consumption of Primary Energy
Oil
Coal
Natural Gas
From: http://www.bp.com/centres/energy2002/primary.asp#
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Motivation for Studying Coal (vs. Gas)
• Plentiful. Resource ~ 500 years (vs. gas/oil: ~100 years).
• Inexpensive (low volatility). 1-1.5 $/GJ HHV (vs. gas at 2.5+ $/GJ).
• Ubiquitous. Wide geographic distribution (vs. middle east).
• Carbon intensive.
• Potentially clean. Gasification, esp. with CCS, produces few gaseous emissions and a chemically stable, vitreous ash.
• Ripe for innovation.
• Globally significant. For example: China: extensive coal resources; little oil and gas. Potential for huge emissions of both criteria pollutants and greenhouse gases.
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Our Work on Low-CO2 Hydrogen and Electricity from Fossil Fuels
• Coal (entrained flow gasification at 70 bar):
- H2 / CO2 separation with WGS membrane reactors,
- Conventional H2 and CO2 separation: • Electricity-only (IGCC) plants• H2 + electricity plants
• Natural gas:- SMR and ATR with steam and combined cycles
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Generic Process: Coal to H2, Electricity, and CO2
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
COdrying andcompression
Hydrogencompression
Syngas cleanup,gas separation
Electricityproduction
Heat recovery,steam generation
H2-richsyngas
CO2
Electricpower
2
• All work presented here is based on O2-blown, entrained flow, coal gasification (e.g. Texaco, E-Gas gasifiers).
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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. 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)
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Estimates of Overnight Component Capital Costs
0
1
2
3
4
5
6
7
8
9
1 0
1 1
1 2
0 50 100 150 200
Capital Cost (MM$)
SimbeckHoltDoctorChiesaHendriksPrudenEPRI3,000-6,000 $/m2
Solids handlingASUO2 compressionGasifier & quenchWGS reactorMembrane reactorRaffinate turbineFGDH2 compressionHRSG, steam turb.CO2 compression
Scale (HHV):1.5 GWth
coal,
• 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.
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Economic Assumptions
~ 1 GWth H2 (LHV)Plant scale
12.0% of overnight capitalInterest during construction
Illinois #6Coal Type
2002U.S. dollars valued in year
5 $/mt CO2 (~8.6 ¢/kg H2)CO2 transport + storage cost*
4% of overnight capital per yearO&M costs
15% per yrCapital charge rate
80%Capacity factor
1.2 $/GJ (HHV)Coal price (2001 average cost to electric generators)
• “Best case” cost estimate for: 16,000 tonne/day CO2, 100 km pipeline, 2 km deep injection well (layer thickness > 50 m, permeability > 40 mDa)
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Sensitivity of Cost to CO2 Storage Costs
0
2
4
6
8
10
12
0 10 20 30 40 50 60
CO2 Storage Cost ($/tonne CO2)
Ele
ctric
ity C
ost (
¢/kW
h)
Order of magnitude increase in CO2 storage costs increases electricity and H2 costs by 60-70%.
0
2
4
6
8
10
12
14
16
0 10 20 30 40 50 60
CO2 Storage Cost ($/tonne CO2)
H2 C
ost (
$/G
J LH
V)
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
H2 C
ost ($/kg)
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Disaggregated Cost of H2 Production
Net cost: 1.03 $/kg H2
-0.2
0.0
0.2
0.4
0.6
0.8
1.0H
ydro
gen
Cos
t ($/
GJ,
HH
V)CO2 Sequestration (5 $/mt CO2)
CO2 drying & compression
HRSG & steam turbine
Gas turbine
PSA and purge compressor
Selexol CO2 absorption, flashing
Selexol H2S removal, Claus, SCOT
WGS reactors, heat exchangers
Gasifier, quench, scrubbing
O2 separation & compression
Coal preparation & handling
Construction Interest (4 yr)
O&M (4% per year)
Coal (1.2 $/GJ, HHV)
Electricity revenue (at 6.2 c/kWh)
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A Few Conversion Factors
• Thermal energy (LHV):
1 kg H2 ~ 1 gallon gasoline
(so $/kg H2 = $/gallon gasoline)
• 1 $/kg H2 = 7.05 $/GJ HHV = 8.34 $/GJ LHV
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System Parameter VariationsSystem Performance:
- gasifier/system pressure- syngas cooling via quench vs. syngas coolers - hydrogen recovery factor (HRF)- hydrogen purity- sulfur capture vs. sulfur + CO2 co-sequestration- membrane reactor configuration- membrane reactor operating temperature- hydrogen backpressure- raffinate turbine technology (blade cooling vs. uncooled)
System Economics (Sensitivity Analysis):- membrane reactor cost (and type)- co-product electricity value, capacity factor, capital charge rate,
fuel cost, CO2 storage cost, etc.
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Annual U.S. Carbon Emissions (2000)
0
100
200
300
400
500
600
700
Electricity Transportation Industrial Commercial Residential
Tonn
es C
per
Yea
r (x1
06 )
Natural Gas
Petroleum
Coal
Source: U.S. EPA Inventory of Greenhouse Gases, Apr. 2002
• Let’s focus for a moment on the power market...
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“Commercially Ready” Coal IGCC with CO2 Capture
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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
2
Syngasexpander
H -richsyngas
• CO2 venting: 390 MWe @ $1190/kWe, ηLHV = 43.0%, 4.6 ¢/kWh
• CCS: 362 MWe @ $1530/kWe, ηLHV = 36.8%, 6.2 ¢/kWh (no carbon tax)
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Economics of Coal IGCC with Carbon Storage
4.5
5.0
5.5
6.0
6.5
7.0
0 20 40 60 80 100 120
Carbon Tax ($/tonne C)
Ele
ctric
ity C
ost (
¢/kW
h)
CO2 storage crossover:(93 $/tonne C)
Coal IGCC withCO2 storage
Coal IGCC withCO2 venting
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H2 Production: Add H2 Purification/Separation
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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
H2-richsyngas
Syngasexpander
• Replace syngas expander with PSA and purge gas compressor.
• Reduce the size of the gas turbine.
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Conventional H2 Production with CO2 Capture
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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
SupercriticalCO2 to storage
• 1070 MWth H2 (LHV) + 39 MWe electricity, efficiency ηLHV=60.9%, 1.03 $/kg H2 (no carbon tax). [70 bar gasifier, quench cooling]
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Economics of H2 from Coal with Carbon Storage
6.0
6.5
7.0
7.5
8.0
8.5
9.0
0 20 40 60 80 100 120Carbon Tax ($/tonne C)
Hyd
roge
n C
ost (
$/G
J, H
HV
)
CO2 storage crossover (39 $/tonne C,4.1 $/GJ NG,
4.6 ¢/kWh NGCC)
H2 from coal withCO2 storage
H2 from coal withCO2 venting
H2 from NG withCO2 venting
H2 from NG withCO2 storage
• Both the carbon tax and breakeven NG price needed to induce coal H2 with CO2 storage are significantly lower than those for electric power.
• Industrial H2 from coal might be the earliest CCS opportunity.
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Conventional H2 Production with CO2 Capture
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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
SupercriticalCO2 to storage
• Incremental cost for CO2 capture is less for hydrogen than electricity because much of the equipment is already needed for a H2 plant.
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Capture (and Co-store) H2S with CO2
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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
SupercriticalCO2 to storage
• Remove the traditional acid gas recovery (AGR) unit.
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Conventional H2 Production with CO2+H2S Capture
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
• Resulting system is simpler and cheaper.
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Co-Capture and Co-storage of CO2 and H2S
0.0
0.2
0.4
0.6
0.8
1.0
1.2
Conv. tech. base case
H2 C
ost (
$/kg
)
CO2 venting Pure CO2 sequestration Co-sequestration
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Economics of H2 from Coal with H2S-CO2 Co-Storage
6.0
6.5
7.0
7.5
8.0
8.5
9.0
0 20 40 60 80 100 120Carbon Tax ($/tonne C)
Hyd
roge
n C
ost (
$/G
J, H
HV
)
Co-storage crossover (19 $/tonne C,3.8 $/GJ NG,
4.2 ¢/kWh NGCC)
H2 from NG withCO2 storage
H2 from NG withCO2 venting
H2 from coal withCO2 venting
H2 from coal withH2S-CO2 co-storage
• H2S-CO2 co-storage further reduces both the crossover carbon tax and breakeven NG price.
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Produce “Fuel Grade” H2 with CO2+H2S Capture
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
• Remove the PSA and gas turbine; smaller steam cycle.
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“Fuel Grade” (~93% pure) H2 with CO2/H2S Capture
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
• Simpler, less expensive plant. No novel technology needed.
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Production of “Fuel Grade” H2
0.0
0.2
0.4
0.6
0.8
1.0
1.2
Conv. tech. base case Fuel grade H2
H 2 C
ost (
$/kg
)CO2 venting Pure CO2 sequestration Co-sequestration
• Fuel grade H2 more competitive with gas and oil in the heating sector, and might be adequate for transportation (H2 ICEVs; barrier to PEM FCEVs?)
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Change H2-CO2 Gas Separation Scheme
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
• This work uses a membrane to separate H2 from the syngas instead of CO2.
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H2 Separation Membrane Reactor System
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
• Employ a H2 permeable, thin film (10 µm), 60/40% Pd/Cu (sulfur tolerant) dense metallic membrane, configured as a WGS membrane reactor.
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Hydrogen Separation Membrane Reactor (HSMR) Concept
Membrane Reactor 5 5-3-03
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
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Typical Membrane Reactor Performance
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 Recovery Factor (%
)
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
Aver
age
H2 F
lux
(kW
/m2 )
Mem
brane Material C
ost ($/kW)
H2 Recovery Factor (%)
→
→
b)
10 µm thick Pd-40Cu membrane475 C; 1000 ppm H
2S; 67 bar syngas
Tube length →
• 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)
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Cost of H2 Compression and HSMRvs. H2 Backpressure
0.0
0.1
0.2
0.3
0.4
0 2 4 6 8 10H2 Backpressure (bar)
Cos
t Com
pone
nt ($
/kg
H2)
Total cost
HSMR capital
Compressor
Number of compression
stages:
Compressor capital
Cost minimum
34
5
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Membrane System with Cooled Raffinate Turbine
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
Raffinate
(for bladecooling)
Steam(for bladecooling)
Uncooledexpander
Steam
• Blade cooling with steam enables higher TIT (1250 C vs. 850 C), and higher electrical conversion efficiency. Requires much lower HRF (~60%).
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Membrane System Results Summary
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
70HCQ LU-F LU HU HU-S HC-1 HC-2
H2 + Electricity Plant
H2 C
ost (
$/kg
H2)
0
10
20
30
40
50
60
70
Effective E
fficiency (% LH
V)
6.3
4
5
3
¢/kWh
Cooledturbine
Conventialtechnology
6.3
Starting case(70 bar, uncooled
Base case(120 bar,
uncooled turbine)
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Part 1 Summary
• No matter how hard we try, H2 costs $1/kg!
• Question: Would the world’s outlook be significantly enhanced if H2 cost 90 ¢/kg? 80 ¢/kg?
0.0
0.2
0.4
0.6
0.8
1.0
Hyd
roge
n C
ost (
$/G
J, H
HV)
CO2 Sequestration (5 $/mt CO2)
CO2 drying & compression
HRSG & steam turbine
Gas turbine
PSA and purge compressor
Selexol CO2 absorption, flashing
Selexol H2S removal, Claus, SCOT
WGS reactors, heat exchangers
Gasifier, quench, scrubbing
O2 separation & compression
Coal preparation & handling
Construction Interest (4 yr)
O&M (4% per year)
Coal (1.2 $/GJ, HHV)
Electricity credit (6.42 ¢/kWh)0 2
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Outline of Talk
• Overview of our work on production of carbon-free H2
and electricity from fossil fuels (primarily coal)
• Putting our work in perspective
• Areas of interest for future work
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Where Might H2 be Used?
0
100
200
300
400
500
600
700
Electricity Transportation Industrial Commercial Residential
Tonn
es C
per
Yea
r (x1
06 )
Natural Gas
Petroleum
Coal
Source: U.S. EPA Inventory of Greenhouse Gases, Apr. 2002
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Production Cost of H2 (Scale=1 GWth HHV)
0
1
2
3
4
5
NG Coal
Cos
t of H
2 ($/
kg)
Non-fuel O&M (4%/yr of OC)
Feedstock (NG=$4/GJ, coal=$1.2/GJ)
Plant capital (15%/yr CCR)
Electricity credit
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Add CO2 Transport and Geologic Storage...
0
1
2
3
4
5
NG Coal
Cos
t of H
2 ($/
kg)
CO2 injection wells
CO2 injection site piping
CO2 pipeline (100 km)
Non-fuel O&M (4%/yr of OC)
Feedstock (NG=$4/GJ, coal=$1.2/GJ)
Plant capital (15%/yr CCR)
Electricity credit
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Add H2 Storage and Distribution Pipelines...
0
1
2
3
4
5
NG Coal
Cos
t of H
2 ($/
kg)
City gate H2 booster compressor
H2 local distribution pipelines
H2 pipeline from plant to city gate (100 km)
Central H2 storage (1/2 day's output)
CO2 injection wells
CO2 injection site piping
CO2 pipeline (100 km)
Non-fuel O&M (4%/yr of OC)
Feedstock (NG=$4/GJ, coal=$1.2/GJ)
Plant capital (15%/yr CCR)
Electricity credit
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Add H2 Refueling Stations...
0
1
2
3
4
5
NG Coal
Cos
t of H
2 ($/
kg)
H2 refueling station
City gate H2 booster compressor
H2 local distribution pipelines
H2 pipeline from plant to city gate (100 km)
Central H2 storage (1/2 day's output)
CO2 injection wells
CO2 injection site piping
CO2 pipeline (100 km)
Non-fuel O&M (4%/yr of OC)
Feedstock (NG=$4/GJ, coal=$1.2/GJ)
Plant capital (15%/yr CCR)
Electricity credit
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Add the Incremental Vehicle Cost...
0
1
2
3
4
5
NG Coal
Cos
t of H
2 ($/
kg)
PEMFC-EV cost increment ($2,460)
H2 refueling station
City gate H2 booster compressor
H2 local distribution pipelines
H2 pipeline from plant to city gate (100 km)
Central H2 storage (1/2 day's output)
CO2 injection wells
CO2 injection site piping
CO2 pipeline (100 km)
Non-fuel O&M (4%/yr of OC)
Feedstock (NG=$4/GJ, coal=$1.2/GJ)
Plant capital (15%/yr CCR)
Electricity credit
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Where Else Might H2 be Used?
0
100
200
300
400
500
600
700
Electricity Transportation Industrial Commercial Residential
Tonn
es C
per
Yea
r (x1
06 )
Natural Gas
Petroleum
Coal
Source: U.S. EPA Inventory of Greenhouse Gases, Apr. 2002
• Displacing traditional H2 from NG (1% of global primary energy).
• At 200 $/tonne C, H2 for industrial boilers, furnaces, and kilns becomes competitive with gas at 4 $/GJ. Oil?
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Outline of Talk
• Overview of our work on production of carbon-free H2
and electricity from fossil fuels (primarily coal)
• Putting our work in perspective
• Areas of interest for future work
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What is this Curve?
Time
Con
sum
ptio
n
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The “Elephant-in-the-Snake” Problemor
“How does Ohio absorb a 1 GWth H2 plant?”
“Le Petit Prince”, Antoine de Saint Exupéry
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H2 DEMAND DENSITY (kg/d/km2): YEAR 1: 25% OF NEW Light Duty Vehicles = H2 FCVs
Blue shows good locations for refueling station
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H2 DEMAND DENSITY (kg/d/km2):
YEAR 5: 25% OF NEW LDVs = H2 fueled
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H2 DEMAND DENSITY (kg/d/km2):
YEAR 10: 25% OF NEW LDVs = H2 fueled
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H2 DEMAND DENSITY (kg/d/km2):
YEAR 15: 25% OF NEW LDVs = H2 fueled
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What is Required to Enable a H2 Economy?
• Safe / effective / low cost CCS
• H2 safety
• Better H2 storage?
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From Multiple Targets and Baselines to The Stabilization Wedge in Three Steps
Step One: Restrict attention to 50 years (the Goldilocks time frame)Step Two: Choose just one goal and one baseline
Yearly Emissions of Carbon
6789
101112131415
2000 2010 2020 2030 2040 2050
Year
Em
issi
ons
(GT
Carb
on)
IS92A BAUS500
Step Three: Abstracting further, take the goal to be flat emissions and the baseline to be doubling linearly in 50 years.
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The Stabilization Wedge
2004 21042054
GtC/yr21
14
7
0
Easier CO2 target ≈ 750 ppm
Tougher CO2 target ≈ 500 ppm
Business As Usual
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Seven “Slices” Fills the WedgeIt is irresistible to divide the wedge into seven
equal parts. We call these “slices.”
7 GtC/yr
20542004
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What is a “slice”?A “slice” is an activity reducing the rate of carbon build-up in the
atmosphere that grows in 50 years from zero to 1.0 Gt(C)/yr.
1 GtC/yrTotal = 25 Gigatons carbon
50 years
Cumulatively, a slice redirects the flow of 25 Gt(C) in its first 50 years. This is 2.5 trillion dollars at $100/t(C).
A “solution” to the Greenhouse problem should have the potential to provide at least one slice.
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Filling the WedgeThe strategies available to provide the slices to fill the wedge are grouped
below. All strategies are based on technologies already in use.
Coal to Gas
CCS
Nuclear
Renewables
Efficiency
Natural Sinks
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Parting Thoughts/Questions
• Lowering the cost of H2 from fossil fuels is hard work!
• The cost of H2 production per se may be only a small fraction of the cost of a H2 economy.
• Thus, how useful is it to try to squeeze production costs via novel technology?
• Other (e.g. system) issues may have greater leverage.
• How soon will H2 play an important role in carbon mitigation?
• How can we best use our talents to forestall global climate change?