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1
Perspectives onHydrogen from Fossil Fuels
for CO2 Mitigation
Tom KreutzPrinceton Environmental Institute
Princeton University
Presented at the Aspen Global Change Institute, Workshop:“Energy Options and Paths to Climate Stabilization”
July 6-11, 2003, Aspen, Colorado
2
• CMI Project Areas:- Carbon capture (Kreutz, Larson, Ogden, Socolow, Williams):
production, distribution, and utilization of electricity and H2from fossil fuels.
- Carbon storage (Celia): modeling CO2 storage in and leakagefrom saline aquifers; emphasis on risk assessment.
- Carbon science (Pacala, Sarmiento, GFDL): global climatemodeling of CO2 in the atmosphere, oceans, and land.
- Carbon policy (Bradford, Oppenheimer): Kyoto alternatives,stabilization targets, GH damage functions.
- Integration: economic implications of delayed action,knowledge about trajectories, optimal emission paths.
• Funding: 15.1$ from BP, 5 M$ from Ford
The Carbon Mitigation Initiative (CMI)at Princeton University, 2001-2010
3
• How H2 might fit into the problem of global carbonemissions.
• Some ongoing work at Princeton relating to H2
production and distribution.
Talk Outline
4
Point of Departure
• The greenhouse effect is real, and growing.- It’s a big problem, requiring large changes.
• We want to mitigate its effects, to stabilize CO2concentrations at some level, e.g. 550 ppmv, but- We don’t want to curtail economic growth.
• We seek to minimize the costs (economic, societal,etc.) of mitigation.- Advantages may result from large changes.
• We balance GH costs against mitigation costs.- Evolving process: science + policy/politics.
5
From: http://www.bp.com/centres/energy2002/primary.asp#
World Consumption of Primary Energy
Oil
Coal
Natural Gas
6
Fossil Fuels are…• plentiful:
• the primary cause of greenhouse warming.
• the largest source of primary energy (X% worldwide)
• likely to continue to be extremely important for manydecades until other, low carbon sources (renewables,nuclear energy) become more mature, widespread,and less expensive.
153004600Total
29003400Coal (70% C)
10600Clathrates
220250Unconventional natural gas
240Conventional natural gas (75% C)
1550440Unconventional oil
250Conventional oil (85 wt. % C)
AdditionalResourceBase
Global Fossil CarbonResources (Gt)
7
8
Growth Rate of Carbon Reservoirs
9
Use of Fossil Fuels in a Carbon-Constrained World
• Stabilization of CO2 concentrations (e.g. 550ppmv) will require huge reductions in CO2emissions over the next century.
• Thus, continued, large scale use of fossil fuelswill require carbon capture and storage (CCS).
• Large scale generation of carbon-free energycarriers, electricity and hydrogen, from fossilfuels is commonplace.
• CO2 separation/capture can be accomplishedwith proven, commercial technology.
• Very large scale CO2 storage is the big unknown.
10
Second Point of Departure
• In our work, and in this talk, we assume:- Widespread, large scale CO2 storage, e.g. in saline
aquifers, will be a viable - and not too expensive -undertaking.
- Fossil fuels are going to play a major role for the next50-100 years.
• The extent of fossil fuel use will depend on a hostof factors (discussed at this conference):- Actual CO2 storage costs,- Carbon taxes/policy,- Costs of competing low carbon energy sources,- Etc.
11
Options For CO2 Disposal
• Deep ocean disposal
• Disposal in geological media– Depleted oil and gas fields– Beds of unminable coal–– Deep saline aquifersDeep saline aquifers (at least 800 m down)
• Disposal as carbonate rocks
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Global Capacity For CO2 StorageIn Deep Saline Aquifers
• If closed aquifers with structural traps needed: ~ 50 GtC
• If large, open aquifers w/good top seals also usable:– Estimate by IEA GHG R&D Programme: up to 2,700 GtC
– Estimate by Hendriks (Utrecht University): ~ 13,000 GtC
• For comparison:– Cumulative emissions, 1990-2100, from fossil fuel burning
[Business-As-Usual Global Energy Scenario (IS92a) of IPCC:1,500 GtC]
– Carbon content of remaining exploitable fossil fuels (excludingmethane hydrates) ~ 5,000 – 7,000 GtC
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CO2 Disposal Experience
• Enhanced oil recovery: 74 projects worldwide injecting 30MMt CO2/y; 4% of US oil so produced—mostly using CO2 fromnatural reservoirs (> 3000 km of CO2 pipelines in US), butWeyburn (Canada) uses 1.5 MMt/y of CO2 piped 300 km fromNorth Dakota coal gasification plant
• Enhanced coal bed methane recovery: 1 commercialproject in San Juan Basin (US)
• Acid gas disposal: 31 acid gas (H2S + CO2) disposal projectsin Canada associated with recovery of sour NG
• Sleipner project in North Sea: 1 MMt/y of CO2 beingdisposed of since 1996 in aquifer under seabed
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Current CO2 Emissions
• Centralized power generation is relatively easy todecarbonize.
• 2/3 – 3/4 of CO2 emissions from distributed sources:transportation and “other” (primarily industrial,commercial, and residential heating).
36.0 30.6
32.0
20.8
32.0
48.6
0%
20%
40%
60%
80%
100%
United States World
Other
Transportation
Electricity
1997
15
Projected CO2 Emissions
• Similar story under IPCC IS92a projections.
• These ratios obviously depend on competitionbetween sectors.
33.425.2
29.434.4
37.2 40.4
0%
20%
40%
60%
80%
100%
United States World
Other
Transportation
Electricity
IS92a2100
16
What to do about CO2 Emissions fromDistributed Consumption of Fossil Fuels?
• Switch to “low-carbon” electricity (from fossil fuels withCCS, nuclear, or renewables):- Difficulties with storage (transportation) and efficiency
(heating) will limit adoption. By how much?
• Switch to “low-carbon” hydrogen, from:- Centrally “decarbonized” fossil fuels with CCS,- Biomass (without - or with - CCS),- Nuclear, via advanced thermochemical cycles,- Electrolysis using low-carbon electricity.
• Efficiency losses vs. transportation costs• H+T require H2 distribution, T requires H2 onboard storage
• CO2 capture and storage from air.
17
Annual U.S. Carbon Emissions (2000)
• Power generation with CCS ~100-200 $/tonne C.
• Transportation sector via H2…1000 $/tonne C?
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
18
Drivers for the H2 Economy
• H2 is abundant and can be utilized relatively andcleanly (via combustion, electrochemistry)
• Energy security
• Air pollution
• Climate change
• Common carbon-free energy carrier from:- renewables- fossil fuels- nuclear power
19
Difficulties with the H2 Economy
• Efficiency losses during production
• Cost:- distribution- storage (at both large and small scales)- safety
• Safety
20
“Low-Carbon” Electricity
• Electricity grid already exists.
• Competition between:- “Decarbonized” fossil-based, central station power
generation, via CO2 capture and storage (CCS),- Nuclear power- Renewable energy (wind, solar, biomass)
21
Economics of Base Case System Capital Cost (million $)
0200400600800
10001200140016001800
H2 from NG H2 from Coal
H2 refueling Sta
Local H2 Distribution
H2 pipeline 100 km
H2 Storage at CentralPlantCO2 Wells and InjectionSiteCO2 Pipeline 100 km
H2 Plant
02468
1012141618
H2 from NG H2 from Coal
H2 Refuel Sta O&M
H2 Refuel Sta Capital
Local H2 Distrib
H2 Pipeline 100 km
H2 Storage at H2 Plant
CO2 Wells and InjectionSiteCO2 Pipeline 100 km
Feedstock
H2 Plant
Delivered H2 Cost ($/GJ)
22
23
H2 DEMAND DENSITY (kg/d/km2):YEAR 1: 25% OF NEW Light Duty Vehicles = H2 FCVs
Blue shows good locations for refueling station
24
H2 DEMAND DENSITY (kg/d/km2):YEAR 5: 25% OF NEW LDVs = H2 fueled
25
H2 DEMAND DENSITY (kg/d/km2): YEAR 10: 25% OF NEW LDVs = H2 fueled
26
H2 DEMAND DENSITY (kg/d/km2): YEAR 15: 25% OF NEW LDVs = H2 fueled
27
Societal Lifecycle Costs ($/veh) for AlternativeFueled Vehicles, Including Externality Costs
02000400060008000
10000120001400016000
Energy Supply SecurityGHGAir PollutionFuelVehicle BodyDrive Train
CurrentICEVs Adv.
ICEVsHybridICEVs
Fuel Cell Vehicles
28
Societal Lifecycle Costs ($/veh) with Low,Medium, and High Externality Values
0
5000
10000
15000
20000
25000 Oil Supply InsecurityGHGAir PollutionFuelVehicle BodyDrive Train
Medium Externality Values
Low Externality Values
High Externality Values
Adv.ICEVs
Adv.ICEVs
Adv.ICEVs
ICE/HEVsICE/HEVs
ICE/HEVs
H2 FuelCell Veh
H2 FuelCell Veh
H2 FuelCell Veh
CurrentICEV
CurrentICEV
CurrentICEV
29
The Case for Hydrogen
1. Most of the century's fossil fuel carbon must be captured.
2. About half of fossil carbon, today, is distributed to smallusers – buildings, vehicles, small factories.
3. The costs of retrieval, once dispersed, will be prohibitive.
4. An all-electric economy is unlikely.
5. An electricity-plus-hydrogen economy is the most likelyalternative.
6. Hydrogen from fossil fuels is likely to be cheaper thanhydrogen from renewable or nuclear energy for a long time.
30
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 beinglarge coal user is near-zero emission option for coal feasible?
• Air pollution concerns likely to drive coal gasification for powergeneration—springboard for producing H2 from coal
• Sulfur, other criteria pollutants, toxics (e.g, Hg) pose majorchallenges in H2/electricity manufacture; gasification facilitateslow emissions
• Residual environmental, health, and safety issues of coal miningand other low-quality feedstocks
31
Why Focus on Coal and Gasification?
• Coal resources abundant globally.
• Coal prices low and not volatile.
• Much of global population (e.g., China, India) heavilycoal-dependent.
• Widespread use of coal is a GH disaster.
• Gasification is relatively efficient, and can be quiteclean, esp. with CCS.
• Gasification provides a route to H2, with its numerousadvantages:– Secure alternative to oil for transportation– near-zero emissions of air pollutants/GHGs
32
GASIFICATION ACTIVITY WORLDWIDE
61 GWth cum syngascapacity:
• By activity:– 24 GWth chemicals– 23 GWth power– 14 GWth synfuels
• By region:– 19 GWth W Europe– 18 GWth Asia/Australia– 10 GWth N America– 10 GWth Africa/ME– 3 GWth E Europe/FSU– 1 GWth Latin America
• By feedstock:– 27 GWth pet residuals– 27 GWth coal– 6 GWth NG– 1 GWth biomass
• New capacity added @ 3GWth/y
• Most power at refineriesvia “polygeneration”
• Coal power constrainedby NGCC competition
• Gasification technology for making chemicals in market by 1970
• Cool Water demonstration of coal IGCC power, 1984-1989
Source: SFA Pacific, Gasification—Worldwide Use andAcceptance, prepared for the US DOE, January 2000
• New syngas capacity being added @ 3 GWth/y• Most power at refineries via “polygeneration”• Coal power growth constrained by NGCC competition
33
Generic Process: Coal to H2, Electricity, and CO2
• All work presented here is based on O2-blown, entrained flow, coalgasification (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
34
Process Modeling
• Heat and mass balances (around each systemcomponent) calculated using:
• Aspen Plus (commercial software), and• GS (“Gas-Steam”, Politecnico di Milano)
• Membrane reactor performance calculated via customFortran code
• Component capital cost estimates taken from theliterature, 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 electricityand H2 production systems (both conventional and membrane-based)
35
• 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.
Component Capital Cost Estimates
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
Fig. Mb
Scale (HHV):1.5 GWth
coal,1 GWth H2
(Including installation, 23% BOP, 15% engineering, and 15% process/project contingencies; exclusive of IDC)
Estimates of Overnight Component Capital Costs
36
16.0% of overnight capital**Interest during construction (IDC)
15% of (GI+BOP+EF)Process/project contingency
23% of gasifier island (GI) capitalBalance of plant (BOP) costs
15% of (GI+BOP)Engineering fees (EF)
1 GWth H2Plant scale
2002U.S. dollars valued in year
5 $/mt CO2 (~0.5 $/GJ H2 HHV)CO2 sequestration cost
4% of overnight capital per yearO&M costs
15% per yrCapital charge rate
80%Capacity factor
1.2 $/GJ (HHV)Coal price (year 2020 EIA est.)
* Assuming a 10% real interest rate
Economic Assumptions
37
Coal IGCC Electricity with CO2 Capture
• Plant scale: 362 MWe, efficiency: 34.9% (HHV), cost: 6.5 ¢/kWh (no carbontax) vs. 4.8 ¢/kWh venting, 6.7 ¢/kWh (at 96 $/tonne C). (70 bar gasifierwith quench cooling)
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
H2-richsyngas
Syngasexpander
38
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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
H2-richsyngas
Syngasexpander
39
Conventional H2 Production with CO2 Capture
• 1285 MWth H2 (HHV) + 39 MW electricity, efficiency ηHHV=68.4%, 7.4 $/GJHHV (no carbon tax). [70 bar gasifier with quench cooling]
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
40
Capture (and Co-store) 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
reactorLean/richsolvent
CO2physical
absorption
Solventregeneration
Lean/richsolvent
H2Sphysical
absorption
Regeneration,Claus, SCOT
SupercriticalCO2 to storage
41
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
42
Conventional H2 with Co-Sequestration of CO2and Sulfur-bearing Species
• CO2 capture and sequestration lowers efficiency by ~3% and increases H2 costby ~ 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 C
ost (
$/G
J H
HV)
CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
43
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
44
“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
45
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
ost (
$/G
J H
HV)
CO2 venting Pure CO2 sequestration Co-sequestration
Includes $5/t CO2 = ~0.5 $/GJ HHV sequestration cost
46
• Incremental cost for CO2 capture is less for hydrogen than electricity becausemuch of the equipment is already needed for a H2 plant.
Breakdown of Incremental Capital Cost for CO2 Capture
37%
36%
24%
3%
WGS reactors, heat exchangers
Selexol CO 2
absorption, and stripping
CO 2 drying, compression
Other
Coal IGCC(1326 → 1737 $/kW e )
100%
CO 2 drying, compression
H 2 from Coal(706 → 742 $/kW th H 2 HHV)
47
• Carbon tax needed to induce CO2 storage is extremely high.
• NGCC with CO2 capture is not considered further.
Economics of NGCC with Carbon Storage
3
4
5
6
7
0 50 100 150 200 250 300 350
Carbon Tax ($/tonne C)
Ele
ctric
ity C
ost (
¢/kW
h)
"Crossover point"for CO2 storage(292 $/tonne Cat 3.0 $/GJ NG)
NGCC withCO2 capture
NGCC withCO2 venting
48
• Tax needed to induce CO2 storage in coal IGCC is much lower than NGCC.
• But, how does coal IGCC+CO2 storage compete with NGCC+CO2 venting...
Economics of Coal IGCC with Carbon Storage
4.5
5.0
5.5
6.0
6.5
7.0
0 20 40 60 80 100 120
Carbon Tax ($/tonne C)
Ele
ctric
ity C
ost (
¢/kW
h)
CO2 storage crossover:(94 $/tonne C)
Coal IGCC withCO2 storage
Coal IGCC withCO2 venting
49
• In addition to the carbon tax, the NG price must exceed ~6 $/GJ for coalIGCC+CO2 storage (...for any electricity+CO2 storage) to be economical!
The “Breakeven NG Price” to Induce CO2 Storage
4.5
5.0
5.5
6.0
6.5
7.0
0 20 40 60 80 100 120
Carbon Tax ($/tonne C)
Ele
ctric
ity C
ost (
¢/kW
h)
CO2 storage crossover:(94 $/tonne C,6.2 $/GJ NG)
NGCC withCO2 venting
Coal IGCC withCO2 storage
Coal IGCC withCO2 venting
50
• Co-storage reduces both the crossover carbon tax and breakeven NG pricesomewhat, but the barrier to carbon storage remains quite high.
The Economics of H2S-CO2 Co-Storage
4.5
5.0
5.5
6.0
6.5
7.0
0 20 40 60 80 100 120
Carbon Tax ($/tonne C)
Ele
ctric
ity C
ost (
¢/kW
h)
Co-storage crossover:(72 $/tonne C,5.8 $/GJ NG)
Coal IGCC withCO2 venting
NGCC withCO2 venting
Coal IGCC withH2S-CO2 co-storage
51
• Without CO2 storage, coal IGCC competes with NGCC at NG~4.5 $/GJ; thebreakeven NG price rises with carbon tax due to coal’s high C content.
• Above the crossover tax, CO2 storage plants out-compete CO2 venting plants.
Breakeven NG Prices vs. Carbon Tax
4.5
5.0
5.5
6.0
6.5
0 20 40 60 80 100 120
Carbon Tax ($/tonne C)
Brea
keve
n N
G P
rice
($/G
J H
HV)
Coal IGCC withH2S-CO2 co-storage
Coal IGCC withCO2 venting
Coal IGCC withCO2 storage
52
• Both the carbon tax and breakeven NG price needed to induce coal H2 withCO2 storage are much lower than those for electric power.
• Industrial H2 from coal might be the earliest CO2 storage opportunity.
Economics of H2 from Coal with Carbon Storage
6.0
6.5
7.0
7.5
8.0
8.5
9.0
0 20 40 60 80 100 120Carbon Tax ($/tonne C)
Hyd
roge
n C
ost (
$/G
J, H
HV)
CO2 storage crossover (39 $/tonne C,4.1 $/GJ NG,
4.6 ¢/kWh NGCC)
H2 from coal withCO2 storage
H2 from coal withCO2 venting
H2 from NG withCO2 venting
H2 from NG withCO2 storage
53
• H2S-CO2 co-storage further reduces both the crossover carbon tax andbreakeven NG price.
Economics of H2 from Coal with H2S-CO2 Co-Storage
6.0
6.5
7.0
7.5
8.0
8.5
9.0
0 20 40 60 80 100 120Carbon Tax ($/tonne C)
Hyd
roge
n C
ost (
$/G
J, H
HV)
Co-storage crossover (19 $/tonne C,3.8 $/GJ NG,
4.2 ¢/kWh NGCC)
H2 from NG withCO2 storage
H2 from NG withCO2 venting
H2 from coal withCO2 venting
H2 from coal withH2S-CO2 co-storage
54
• Breakeven NG prices for coal H2 mirror those for IGCC (but are lower).
Breakeven NG Prices vs. Carbon Tax
2.5
3.0
3.5
4.0
4.5
5.0
5.5
6.0
6.5
0 20 40 60 80 100 120
Carbon Tax ($/tonne C)
Brea
keve
n N
G P
rice
($/G
J H
HV)
CO2 venting
CO2 storage
H2S-CO2 co-storage
Coal IGCC:
CO2 venting
CO2 storage
H2S-CO2 co-storage
H 2 from Coal:
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Conclusions• If CCS is viable, fossil fuels will probably be used for the
production of low-carbon electricity and some H2. The cost ofavoided CO2 emissions is ~100 $/tonne C (200 $/tonne C withrespect to old plants).
• The imposition of a simple carbon tax will NOT induce IGCCelectricity with CCS at ~100 $/tonne C; a gas price of ~6 $/GJHHV is also required. Coal may disappear without a “feebate”scheme or portfolio standard to induce IGCC CCS.
• Low-carbon H2 may be an early opportunity for CCS, in caseswhere H2 distribution costs are small.
• H2 will be available at IGCC plants with CCS, reasonably neardemand centers. The penetration of H2 into heating andtransportation will depend on carbon taxes, public policy, andcompetition from other low carbon energy carriers.
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What is (and is Not) Needed?• Long term CO2 storage in saline aquifers needs to be validated
with many, well instrumented demonstration projects in a variety ofgeologic formations. A need for regulatory and legal frameworks,and standards for well placement, injection, and monitoring.
• The safety (or lack thereof) of H2 vehicles need to demonstratedby long term studies of H2 ICEV and FCEV fleets.
• FutureGen appears to be a good vehicle for testing anddemonstrating the H2 economy in its full extent.